116 FERC ¶ 61,057 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 35 

(Docket No. RM06-4-000; Order No. 679) 

Promoting Transmission Investment through Pricing Reform 

(Issued July 20, 2006) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Final Rule. 

SUMMARY: In this Final Rule, pursuant to the requirements of the Transmission 

Infrastructure Investment provisions in section 1241 of the Energy Policy Act of 2005, 

which adds a new section 219 to the Federal Power Act, the Federal Energy Regulatory 

Commission (Commission) is amending its regulations to establish incentive-based 

(including performance-based) rate treatments for the transmission of electric energy in 

interstate commerce by public utilities for the purpose of benefiting consumers by 

ensuring reliability and reducing the cost of delivered power by reducing transmission 

congestion. This Final Rule is intended to encourage transmission infrastructure 

investment. 

EFFECTIVE DATE: This Final Rule will become effective [insert date 60 days after 

publication in the FEDERAL REGISTER]. 
Docket No. RM06-4-000 -2- 

FOR FURTHER INFORMATION CONTACT: 

Jeffrey Hitchings (Technical Information) 

Office of Energy Markets and Reliability 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

202-502-6042 

Sebastian Tiger (Technical Information) 

Office of Energy Markets and Reliability 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

202-502-6079 

Andre Goodson (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

202-502-8560 

Tina Ham (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

202-502-6224 

Martin Kirkwood (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

202-502-8125 

SUPPLEMENTARY INFORMATION: 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Promoting Transmission Investment through 

Pricing Reform 

Docket No. RM06-4-000 

FINAL RULE 

ORDER NO. 679 

(Issued July 20, 2006) 

 

 Paragraph Numbers

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

II. Background .................................................................................................................. 1.

III. Overview ................................................................................................................... 10.

A. The Need for New Transmission Facilities ............................................................ 10.

1. Background.......................................................................................................... 10.

2. Comments............................................................................................................ 11.

3. Commission Determination................................................................................. 14.

B. The Need for Incentives.......................................................................................... 15.

1. Background.......................................................................................................... 15.

2. Comments............................................................................................................ 16.

3. Commission Determination................................................................................. 19.

C. Summary of the Nature and Applicability of Incentives Adopted by the 

Final Rule ..................................................................................................................... 21.

D. Effective Date and Duration of Effectiveness For Incentives................................ 30.

1. Background.......................................................................................................... 30.

2. Comments............................................................................................................ 31.

3. Commission Determination................................................................................. 34.

IV. Discussion ................................................................................................................. 37.

A. Standard for Approval of Incentive-Based Rate Treatments ................................ 37.

1. The Final Rule Applies to the Recovery of Costs Incurred to Ensure Reliability or 

to Reduce Transmission Congestion, or Both. ........................................................ 37.

2. Other Criteria For Approval of Incentives .......................................................... 44.

3. Rebuttable Presumptions..................................................................................... 57.

4. Applicants Seeking Incentive-Based Rates Will Not Be Required To File A Cost-
Docket No. RM06-4-000 ii 

Benefit Analysis ....................................................................................................... 59.

5. Procedural Requirements for Obtaining Incentive-Based Rate Treatments ....... 66.

B. Incentives Available To All Jurisdictional Public Utilities .................................... 84.

1. ROE Sufficient to Attract Capital........................................................................ 85.

2. Construction Work in Progress (CWIP) and Pre-Commercial Expenses ......... 103.

3. Hypothetical Capital Structure .......................................................................... 123.

4. Accelerated Depreciation .................................................................................. 135.

5. Recovery of Costs of Abandoned Facilities ...................................................... 155.

6. Deferred Cost Recovery ................................................................................... 168.

7. Other Incentives - Single-Issue Ratemaking .................................................... 179.

C. Incentives Available to Transcos.......................................................................... 194.

1. Definition of Transco ........................................................................................ 194.

2. Transco ROE Incentive ..................................................................................... 206.

3. Accumulated Deferred Income Taxes (ADIT) ................................................. 242.

4. Acquisition Premiums for Transco Formation.................................................. 251.

5. Merchant Transmission ..................................................................................... 259.

D. Performance-Based Ratemaking .......................................................................... 263.

1. General Comments ............................................................................................ 263.

2. Comments Proposing Performance Tests and Competitive Bidding ................ 273.

E. Advanced Technologies........................................................................................ 280.

1. General............................................................................................................... 280.

2. Case-by-Case Review........................................................................................ 294.

3. Whether To Require A Technology Statement ................................................ 300.

4. Risk Sharing ...................................................................................................... 303.

5. Other Technology-Related Issues...................................................................... 308.

F. Transmission Organization Incentive.................................................................... 312.

1. Background........................................................................................................ 312.

2. Comments.......................................................................................................... 314.

3. Commission Determination............................................................................... 326.

G. Recovery of Prudently Incurred Costs to Comply with Reliability Standards and 

Recovery of Prudently Incurred Costs Associated with Transmission Infrastructure 

Development............................................................................................................... 334.

1. Background........................................................................................................ 334.

2. Comments.......................................................................................................... 336.

3. Commission Determination............................................................................... 343.

H. Public Power......................................................................................................... 349.

1. Background........................................................................................................ 349.

2. Comments.......................................................................................................... 350.

3. Commission Determination............................................................................... 354.

V. Reporting Requirement............................................................................................. 358.

A. Background........................................................................................................... 358.
Docket No. RM06-4-000 iii 

B. Comments ............................................................................................................. 360.

C. Commission Determination .................................................................................. 367.

VI. Other Issues ............................................................................................................. 377.

A. Rate Related Issues............................................................................................... 377.

1. Rate Related Issues............................................................................................ 377.

B. Section 35.34......................................................................................................... 395.

1. The Proposal to Eliminate Section 35.34(e)...................................................... 395.

VII. Information Collection Statement.......................................................................... 406.

VIII. Environmental Statement ..................................................................................... 410.

IX. Regulatory Flexibility Act Certification ................................................................. 411.

X. Document Availability ............................................................................................. 412.

XI. Effective Date and Congressional Notification....................................................... 415.

APPENDICES 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Joseph T. Kelliher, Chairman; 

 Nora Mead Brownell, and Suedeen G. Kelly. 

Promoting Transmission Investment through 

Pricing Reform 

Docket No. RM06-4-000 

FINAL RULE 

Order No. 679 

(Issued July 20, 2006) 

I. Introduction

1. Pursuant to the directives in section 1241 of the Energy Policy Act of 2005 (EPAct 

2005)1

 which added a new section 219 to the Federal Power Act (FPA), in this Final Rule 

the Commission provides incentives for transmission infrastructure investment that will 

help ensure the reliability of the bulk power transmission system in the United States and 

reduce the cost of delivered power to customers by reducing transmission congestion. 

The Rule does not grant outright any incentives to any public utility, but rather identifies 

specific incentives that the Commission will allow when justified in the context of 

individual declaratory orders or section 205 filings by public utilities under the FPA. A 

number of these incentives reflect departures from what the Commission has permitted in 

 1

 Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594, 315 and 1283 

(2005).. 
Docket No. RM06-4-000 - 2 - 

the past and a willingness to consider much greater flexibility with respect to the nature 

and timing of rate recovery for needed transmission infrastructure. While the 

Commission in recent years has permitted higher rates of return and deviations from past 

ratemaking practices in a few individual transmission infrastructure cases, 2 we here 

determine generically that these types of ratemaking options and others should be 

considered on a broader basis for those applicants that can demonstrate that their 

infrastructure proposals meet section 219 requirements. 

2. In reaching our determinations in this Final Rule, we have considered comments 

that reflect widely divergent views with respect to whether and when utilities should 

receive incentives and what they must demonstrate in order to receive particular 

incentives. As noted, the Rule does not grant incentives to any public utility but instead 

permits an applicant to tailor its proposed incentives to the type of transmission 

investments being made and to demonstrate that its proposal meets the requirements of 

section 219. Further, under the Rule, the Commission will permit incentives only if the 

incentive package as a whole results in a just and reasonable rate. For example, an 

incentive rate of return sought by an applicant must be within a range of reasonable 

 2

 See Western Area Power, 99 FERC ¶ 61,306, reh’g denied, 100 FERC ¶ 61,331 

(2002) (Western), aff’d sub nom. Public Utilities Commission of the State of California 

v. FERC, 367 F.3d 925 (D.C. Cir. 2004); Michigan Electric Transmission Co., LLC, 

105 FERC ¶ 61,214 (2003) (METC); American Transmission Company, L.L.C., 

105 FERC ¶ 61,388 (2003) (American Transmission); ITC Holdings Corp., 102 FERC 

¶ 61,182, reh’g denied, 104 FERC ¶ 61,033 (2003) (ITC Holdings). 
Docket No. RM06-4-000 - 3 - 

returns and the rate proposal as a whole must be within the zone of reasonableness before 

it will be approved. 

3. An important component of this Rule is the willingness to provide procedural 

flexibility, including the use of expedited declaratory orders on permitted ratemaking 

treatments, to help with financing and up-front regulatory certainty for project 

investments. We are particularly attuned to the need for flexibility to support longdistance interstate projects that significantly reduce the cost of delivered power by 

reducing transmission congestion on the interstate grid. 

4. The Final Rule provides incentive-based rate treatments to any public utility 

transmitting electric energy in interstate commerce that meets the requirements of section 

219 and this Final Rule. The Commission will not limit an applicant’s ability to seek 

incentive-based rate treatments based on corporate structure or ownership. In addition, 

the Final Rule provides additional incentives, to the extent within our jurisdiction,3

 to any 

transmitting utility or electric utility transmitting electric energy in interstate commerce 

that joins a Transmission Organization.4

 Finally, as explained below, to the extent our 

 3

 With regard to non-public utilities, although the Commission’s regulatory 

authority is bound by statute, such entities could be covered by a public utility’s incentive 

rate proposal by a separate agreement between the public utility and a non-public utility. 

See Bonneville Power Administration, et. al. v. FERC, 422 F.3d 408 (9th Cir. 2005). 

4

 Transmission Organization is defined in 18 CFR 35.35(a)(2) of this Final Rule as 

“a Regional Transmission Organization, Independent System Operator, independent 

transmission provider, or other transmission organization finally approved by the 

Commission for the operation of transmission facilities.” Electric Utility is defined in 

(continued) 
Docket No. RM06-4-000 - 4 - 

jurisdiction allows, we encourage public power entities to take advantage of the 

incentive-based rate treatments outlined in the Final Rule. 

5. Some commenters have argued that few or no incentives are needed to encourage 

new transmission investment. We reject these comments as fundamentally inconsistent 

with section 219. Section 219 reflects Congress' determination that the Commission's 

traditional ratemaking policies may not be sufficient to encourage new transmission 

infrastructure. Although section 219 does not permit approval of rates that are 

inconsistent with section 205 or 206, section 219 nonetheless constitutes a clear directive 

that "the Commission shall establish, by rule, incentive-based . . . rate treatments . . . for 

the purpose of benefiting consumers by ensuring reliability and reducing the cost of 

delivered power by reducing transmission congestion" (emphasis added). We therefore 

cannot simply rely on existing ratemaking policy to faithfully implement section 219. 

This Final Rule therefore identifies a non-exclusive list of ratemaking reforms and 

requires applicants to tailor their proposals to fit the facts of their particular case. 

6. We do agree, however, with the position of certain wholesale customers and state 

commissions that the Commission should not provide incentives that only serve to 

 

section 3(22) of the FPA as “any person or State agency (including any municipality) 

which sells electric energy; such term includes the Tennessee Valley Authority, but does 

not include any Federal power marketing agency.” 16 U.S.C. 796(22). Transmitting 

Utility is defined in section 3(23) of the FPA as “any electric utility, qualifying 

cogeneration facility, qualifying small power production facility, or Federal power 

marketing agency which owns or operates electric power transmission facilities which are 

used for the sale of electric energy at wholesale.” 16 U.S.C. 796(23). 
Docket No. RM06-4-000 - 5 - 

increase rates without providing any real incentives to construct new transmission 

infrastructure. Section 219(a) states that transmission incentives should be "benefiting

consumers by ensuring reliability and reducing the cost of delivered power by reducing 

transmission congestion" (emphasis added). The purpose of our Rule is to benefit 

customers by providing real incentives to encourage new infrastructure, not simply 

increasing rates in a manner that has no correlation to encouraging new investment. 

The Final Rule, therefore, makes clear that not every incentive identified herein will be 

necessary or appropriate for every new transmission investment. To provide guidance in 

this regard to potential applicants, we discuss below why certain incentives may, as a 

general matter, be better tailored to certain types of investments than others. 

II. Background 

7. Section 219 of the FPA requires the Commission to establish, by rule, incentivebased (including performance-based) rate treatments for the transmission of electric 

energy in interstate commerce by public utilities for the purpose of benefiting consumers 

by ensuring reliability and reducing the cost of delivered power by reducing transmission 

congestion. Section 219(b) requires that the rule: 

1. promote reliable and economically efficient transmission and generation of 

electricity by promoting capital investment in the enlargement, 

improvement, maintenance, and operation of all facilities for the 

transmission of electric energy in interstate commerce, regardless of the 

ownership of the facilities; 
Docket No. RM06-4-000 - 6 - 

2. provide a return on equity that attracts new investment in transmission 

facilities (including related transmission technologies); 

3. encourage deployment of transmission technologies and other measures to 

increase the capacity and efficiency of existing transmission facilities and 

improve the operation of the facilities; and 

4. allow the recovery of all prudently incurred costs necessary to comply with 

mandatory reliability standards issued pursuant to section 215 of the FPA, 

and all prudently incurred costs related to transmission infrastructure 

development, pursuant to section 216 of the FPA (transmission national 

interest corridors). 

8. Section 219(c) requires that the Rule provide for incentives to each transmitting 

utility or electric utility that joins a Transmission Organization and to ensure that any 

recoverable costs associated with joining may be recovered through transmission rates 

charged by the utility or through the transmission rates charged by the Transmission 

Organization that provides transmission service to the utility. Finally, section 219(d) 

provides that all rates approved under the Rule are subject to the requirements of sections 

205 and 206 of the FPA,5

 which require that all rates, charges, terms and conditions be 

just and reasonable and not unduly discriminatory or preferential. 

 5

 16 U.S.C. 824(d) and 824(e) (2000). 
Docket No. RM06-4-000 - 7 - 

9. Congress directed the Commission to issue a Final Rule establishing incentivebased rate treatments for transmission construction within one year of enactment of 

EPAct 2005, or by August 8, 2006. The Commission issued a Notice of Proposed 

Rulemaking (NOPR) on November 18, 2005 seeking comment on the Commission’s 

proposal to comply with section 219.6

 In the NOPR, the Commission proposed to amend 

Part 35 of Chapter I, Title 18 of the Code of Federal Regulations by eliminating 

paragraph 35.34(e) under Subpart F and adding paragraph 35.35 under Subpart G. The 

Commission received several hundred pages of comments. A list of the commenters 

appears in Appendix B. As explained below, based on the comments filed, the 

Commission clarifies and adopts the proposed regulations in the NOPR. 

III. Overview

A. The Need for New Transmission Facilities

1. Background

10. As indicated in the NOPR, investment in transmission facilities in real dollar terms 

declined significantly between 1975 and 1998. Although the amount of investment has 

increased somewhat in the past few years, data for the most recent year available, 2003, 

shows investment levels still below the 1975 level in real dollars.7

 This decline in 

 6

 Promoting Transmission Investment Through Pricing Reform, 70 FR 71409 

(Nov. 29, 2005), FERC Stats. & Regs., Proposed Regs. ¶ 32,593 (2005). 

7

 EEI Survey of Transmission Investment: Historical and Planned Capital 

Expenditures (1999-2008) at 3 (2005). 
Docket No. RM06-4-000 - 8 - 

transmission investment in real dollars has occurred while the electric load using the 

nation’s grid more than doubled.8

 Further, the record shows that the growth rate in 

transmission mileage since 1999 is not sufficient to meet the expected 50 percent growth 

in consumer demand for electricity over the next two decades.9

 

2. Comments

11. Many commenters agree that there is a significant need for new investment in 

transmission facilities. EEI states that, although increases in transmission investment are 

predicted over the 2004 to 2008 period, the industry still has not reached the optimal level 

of investment.10 International Transmission notes that growth in transmission capacity 

has lagged behind the growth in peak demand over the last three decades and this trend is 

projected to continue through at least 2012.11 International Transmission cites to studies 

 8

 Barriers to Transmission Investment, Presentation by Brendan Kirby (U.S. 

Department of Energy, Oak Ridge National Laboratory), April 22, 2005 Technical 

Conference, Transmission Independence and Investment, Docket No. AD05-5-000 

(April 22, 2005 Technical Conference). 

9

 Energy Policy Act of 2005: Hearings before the House Subcommittee on Energy 

and Commerce, 109th Congress, First Sess. (2005) (Prepared statement of Thomas R. 

Kuhn, President of EEI). 

10 2004 State of the Markets Report, Federal Energy Regulatory Commission, 

Staff Report by the Office of Market Oversight and Investigations, June 2005, at p 27. 

11 See Eric Hirst, U.S. Transmission Capacity: Present Status and Future 

Prospects, a study prepared for EEI and the U.S. Department of Energy Office of Electric 

Transmission and Distribution, June 2004 (Hirst) and Keeping Energy Flowing: Ensuring 

a Strong Transmission System to Support Consumer Needs for Cost-Effectiveness, 

Security and Reliability, a report of the Consumer Energy Council of America, 

Transmission Infrastructure Forum, January 2005. See also Affidavit of Jon E. Jipping, 

(continued) 
Docket No. RM06-4-000 - 9 - 

estimating the cost of power interruptions and fluctuations to range from between $29 

billion and $135 billion annually,12 the cost of the August 2003 Northeast-Midwest 

blackout to be between $4 billion and $10 billion,13 congestion costs of $4.8 billion in the 

ISO/RTO markets of California, New York, New England, the Midwest and PJM for 

1999 to 2002,14 and increases in PJM congestion costs, from $499 million in 2003 to 

$808 million in 2004.15 

12. Many transmission users and state commissions also agree that there is a need for 

additional investment in transmission infrastructure.16 

13. However, some commenters dispute the need for new transmission investment. 

They assert the Commission has overlooked that investment in transmission has 

increased in recent years.17 They also contend that investment in transmission by utilities 

 

Exhibit A to the Reply Comments of International Transmission (the transmission system 

purchased in Michigan was 2.5 to 7 years behind schedule in maintenance on key 

transmission facilities). 

12 Kristina LaCommare and Joseph Eto, Understanding the Cost of Power 

Interruptions to U.S. Electricity Consumers, Lawrence Berkeley National Laboratory 

(September 2004) at xiv. 

13 See Final Report on the August 14, 2003 Blackout in the United States and 

Canada by the U.S. – Canada Power System Outage Task Force (April 2004) at 1. 

14 See Hirst at 8. 

15 See 2004 PJM State of the Market Report at 37 (March 8, 2005). 

16 E.g., TDU Systems, APPA, and Maryland Commission. 

17 E.g., NASUCA and Connecticut DPUC. 
Docket No. RM06-4-000 - 10 - 

in RTOs and ISOs has been significant, citing to the approximately $2 billion of 

approved spending in PJM since 2000. E.ON US asserts that wide-spread system 

shortages have rarely occurred during the past 40 or more years, and that there does not 

appear to be any trend line that would suggest that it is becoming a serious problem now. 

3. Commission Determination

14. The issue of whether there is a need for new transmission investment that is 

sufficient to justify transmission incentives was put to rest by section 219. Section 219 

mandates that the Commission "establish, by rule, incentive-based (including 

performance-based) rate treatments" and, in doing so, "promote reliable and 

economically efficient transmission and generation of electricity by promoting capital

investment in the enlargement, improvement, maintenance, and operation of all facilities 

for the transmission of electric energy in interstate commerce" (emphasis added). If this 

were not enough, the legislative mandate of section 219 is supported by abundant 

evidence, as discussed above, including the fact that transmission investment in real 

dollars terms is lower today than it was in 1975 when the load was significantly smaller 

and that, even with the transmission additions of recent years, the industry still incurs 

significant congestion costs due to inadequate transmission. 

B. The Need for Incentives

1. Background

15. In section 219(a) of the FPA, Congress directed the Commission to establish 

incentive-based rate treatments to foster investment in transmission facilities. 
Docket No. RM06-4-000 - 11 - 

2. Comments

16. Several commenters argue that incentive-based rates are not necessary to 

encourage transmission construction or that incentives will not accomplish the intended 

goal.18 Others assert that reliance on incentives may increase the price of electricity 

without any real benefit.19 

17. Commenters urge the Commission to limit the scope of any incentive-based 

treatments or to adopt mechanisms to ensure that they have their intended effect. For 

example, the New Mexico AG and TAPS assert that the Commission may implement an 

incentive-based mechanism by penalizing utilities or RTOs that fail to make investments 

necessary to ensure the reliability of the transmission grid. The Delaware Commission 

contends that providing incentives without assessing penalties for failure to meet 

obligations violates the just and reasonable standard. NASUCA states that it is unfair to 

provide incentives that increase utility profits but do not hold applicants accountable for 

performance. The Missouri Commission proposes that the Commission implement a 

process that determines performance-based return on equity. Other commenters 

recommend that the Commission make approval of any incentives conditional on the 

 18 E.g., APPA, TAPS, NECOE, E.ON U.S., NARUC, and New Jersey Board. 

19 E.g., Connecticut DPUC, NASUCA, NECPUC, Delaware Commission, 

Missouri Commission, and New Mexico AG. 
Docket No. RM06-4-000 - 12 - 

applicant showing a need for the incentive or that the facility would not have been built 

absent the incentive. 

18. In contrast, a number of commenters, including EEI and a large number of utility 

and Transco commenters, argue that incentives are needed to foster investment in 

transmission facilities. EEI asserts that incentives are needed to stimulate planning and 

investment in national interest electric transmission corridors. NU states that the many 

risk factors associated with transmission investments, such as considerable time delays, 

negative public opinion of transmission construction, state siting uncertainties and 

recovery of project costs, justify incentives. 

3. Commission Determination

19. Here again, the fundamental issue raised by certain commenters – whether 

transmission incentives are necessary to encourage new infrastructure – was put to rest by 

the plain language of section 219(a), which requires the Commission issue a rule that 

adopts "incentive-based . . . rate treatments." Certain commenters urge the Commission 

to adopt "penalties" in this rulemaking for entities that do not build sufficient 

transmission. We decline to do so here. 

20. Other commenters do not oppose incentives outright, but rather are concerned with 

the extent to which incentives may increase rates to consumers. Those concerns are 

premature. The Final Rule does not grant incentive-based rate treatments or authorize 

any entity to recover incentives in its rates. Rather, it informs potential applicants of 

incentives that the Commission is willing to allow when justified. Before adopting any 
Docket No. RM06-4-000 - 13 - 

incentive-based rate treatments for a particular company, the Commission will need to 

determine that the applicant has justified its specific incentive request. In addition, 

although the Commission intends to provide flexible procedural mechanisms by which an 

applicant may obtain an early determination of which incentives it may receive (e.g., 

through an expedited declaratory order proceeding), before recovering any incentives in 

its rates, specific rates must be approved under section 205 of the FPA. 

C. Summary of the Nature and Applicability of Incentives Adopted by the 

Final Rule

21. The incentives adopted by this Final Rule are properly understood only in the 

context of the traditional regulatory principles they seek to further. The longstanding rule 

is that utility rate regulation must adequately balance both consumer and investor 

interests. It is not enough to ensure that investors are properly compensated, and it is not 

enough to ensure that consumers are protected against excessive rates. Our policies must 

ensure both outcomes and, in doing so, strike the appropriate balance between these twin 

objectives. In striking that balance, the courts have recognized that there is no single 

formula for establishing a just and reasonable rate. Rather, the test is whether the "end 

result" is just and reasonable.20 

22. The traditional policies that we re-examine here reflect both fundamental precepts: 

the need to balance investor and consumer interests and the recognition that there is no 

 20 See FPC v. Hope Natural Gas Co., 320 U.S. 591, 602-03 (1944). 
Docket No. RM06-4-000 - 14 - 

single formula for doing so. For example, in ensuring that rates produce adequate 

returns for investors, we do not set a single return on equity for all public utilities, nor do 

we presume that there is only one return on equity that is appropriate for any individual 

utility. Rather, our precedents require the establishment of a range of returns and we 

select an ROE within that range that reflects the facts and circumstances of a particular 

case. Similarly, our policies regarding the recovery of Construction Work in Progress 

(CWIP) seek to balance investor and consumer interests by allowing, in the typical case, 

50 percent of CWIP in rate base. This policy balances investor and consumer interests in 

the ordinary case by permitting investors recovery of some construction costs on a 

current basis while also protecting consumers against full rate recovery before a 

particular facility is placed into service. 

23. Our procedural regulations respecting rate recovery also seek to balance investor 

and consumer interests. For example, we allow public utilities to determine, as a general 

matter, the timing and frequency of when to seek a rate increase, which ensures that 

investors can file a rate increase when current rates are no longer adequate (e.g., when the 

utility is undergoing a large construction program). However, we also typically require a 

utility seeking a rate increase to expose all of its costs to review and therefore do not 

generally permit "single issue" rate filings (selective rate adjustment). 

24. Section 219 requires the Commission to re-examine these and other policies to 

determine whether they continue to strike the appropriate balance in encouraging new 

transmission investment given the significant need for new transmission infrastructure in 
Docket No. RM06-4-000 - 15 - 

the Nation. We do so in recognition of the unique and substantial challenges faced by 

large new transmission projects. Siting major new transmission lines is extraordinarily 

difficult, given the environmental and land use concerns associated with obtaining and 

permitting new rights-of-way. The experience of American Electric Power Corp. in 

taking 16 years to complete construction of a new high-voltage transmission line from 

Wyoming County, West Virginia to Jackson Ferry, Virginia represents an extreme 

example, but it is illustrative of the significant risks and challenges associated with siting 

large new transmission projects.21 

25. These challenges and risks are underscored by the fact that, in many instances, 

new transmission projects will not be financed and constructed in the traditional manner. 

New transmission is needed to connect new generation sources and to reduce congestion. 

However, because there is a competitive market for new generation facilities, these new 

generation resources may be constructed anywhere in a region that is economic with 

respect to fuel sources or other siting considerations (e.g., proximity to wind currents), 

not simply on a "local" basis within each utility's service territory. To integrate this new 

generation into the regional power grid, new regional high voltage transmission facilities 

will often be necessary and, importantly, no single utility will be "obligated" to build 

such facilities. Indeed, many of these projects may be too large for a single load serving 

 21 Although new section 216 of the FPA improves the siting process for certain 

new projects, it does not eliminate all risks faced by such projects nor does it address the 

risks faced by other projects that do not reside in a national interest transmission corridor. 
Docket No. RM06-4-000 - 16 - 

entity to finance. Thus, for the Nation to be able to integrate the next generation of 

resources, we must encourage investors to take the risks associated with constructing 

large new transmission projects that can integrate new generation and otherwise reduce 

congestion and increase reliability. Our policies also must encourage all other needed 

transmission investments, whether they are regional or local, designed to improve 

reliability or to lower the delivered cost of power. 

26. To address the substantial challenges and risks in constructing new transmission, 

the Final Rule identifies instances where our regulatory policies may no longer strike the 

appropriate balance in encouraging new investment. The Final Rule identifies several 

policies that should be adjusted, where appropriate on the facts of a particular case, to 

encourage new transmission investment or otherwise remove impediments to such 

investment. Although each reform adopted by the Final Rule constitutes an "incentive" 

as that term is used by section 219, this label has caused some confusion in the 

comments. It is true that our reforms adopted in the Final Rule provide "incentives" to 

construct new transmission, but they do not constitute an "incentive" in the sense of a 

"bonus" for good behavior. Rather, as we explain below, each will be applied in a 

manner that is rationally tailored to the risks and challenges faced in constructing new 

transmission. Not every incentive will be available for every new investment. Rather, 

each applicant must demonstrate that there is a nexus between the incentive sought and 

the investment being made. Our reforms therefore continue to meet the just and 

reasonable standard by achieving the proper balance between consumer and investor 
Docket No. RM06-4-000 - 17 - 

interests on the facts of a particular case and considering the fact that our traditional 

policies have not adequately encouraged the construction of new transmission. 

27. A few examples will illustrate this point. The Final Rule permits higher returns on 

equity for certain transmission investments. This may be appropriate in several contexts, 

such as where the risks of a particular project exceed the normal risks undertaken by a 

utility (and hence are not reflected in a traditional discounted cash flow (DCF) analysis) 

and where necessary to encourage creation of a Transco or participation in a 

Transmission Organization. However, this does not mean that every new transmission 

investment should receive a higher return than otherwise would be the case. For 

example, routine investments to meet existing reliability standards may not always, for 

the reasons discussed below, qualify for an incentive-based ROE. 

28. The Final Rule also adopts incentives that are designed to reduce the risks of new 

investments. For example, the Final Rule provides that the Commission will provide 

assurance of recovery of abandoned plant costs if the project is abandoned for reasons 

outside the control of the public utility. Although this qualifies as an "incentive" under 

section 219, it is perhaps more properly characterized as reducing a regulatory barrier – 

the potential lack of recovery of costs – to infrastructure development. Moreover, this 

reform adequately balances consumer and investor interests because it is available only 

when a project is abandoned for reasons beyond the control of the public utility. 

29. Our Final Rule also adopts certain reforms that affect the timing of recovery of 

new transmission investments. Given the long lead time required to construct new 
Docket No. RM06-4-000 - 18 - 

transmission, and the associated cash flow difficulties faced by many entities wishing to 

invest in new transmission, the Final Rule provides that, where appropriate, the 

Commission will allow for the recovery of 100 percent of CWIP in rate base. Here again, 

we seek to remove an impediment – inadequate cash flow – that our current regulations 

can present to those investing in new transmission. We also will permit, where 

appropriate, the recovery of the costs of new transmission through a single issue rate 

filing without requiring the public utility to re-open all its transmission rates to review. 

We do not, however, suggest that such selective rate adjustments will be appropriate in 

all cases, as discussed in more detail below. Rather, as with each incentive adopted by 

the Final Rule, an applicant must show that there is a nexus between its proposal to make 

a single issue rate adjustment and the facts of its particular case. 

D. Effective Date and Duration of Effectiveness For Incentives

1. Background

30. Congress directed the Commission to issue a rule establishing incentive-based rate 

treatments no later than one year after enactment of EPAct 2005, or by August 8, 2006. 

2. Comments

31. Certain commenters urge the Commission to apply the rule to investments made 

before August 8, 2005 while others ask the Commission to apply the rule to investments 

made after August 8, 2005. 22 Certain commenters argue that the Commission should not 

 22 E.g., Progress, NEMA, and PG&E. 
Docket No. RM06-4-000 - 19 - 

approve incentives for facilities that are pending at the time the Final Rule becomes 

effective, while others request that the Commission not allow incentives for investment in 

facilities that an applicant already has committed to build or for Transcos that already 

exist.23 

32. Several commenters argue that, once the incentives have been granted, the 

Commission should not eliminate them, or should do so only under very limited 

circumstances.24 In contrast, others argue that the Commission should grant incentives 

for a specific time period or retain the flexibility to change or review any incentives if it 

is found the incentives provide no customer benefit.25 The California Oversight Board 

requests that any authorized incentives be subject to refund. 

33. KKR explains that, under certain circumstances, investors in transmission assets 

may need favorable rate treatment for a sufficient period of time to ensure an appropriate 

return on their capital, i.e., for a 15 to 30-year period.26 KKR recommends that public 

utilities requesting incentive treatment for an extended period into the future propose 

criteria that can be used to evaluate that entity’s performance during periodic evaluations. 

KKR notes that applicants may not always be able to meet certain proposed metrics due 

 23 E.g., PG&E, Connecticut DPUC, NASUCA, TDU Systems and TANC. 

24 E.g., Progress, NEMA, EEI, Trans-Elect, and National Grid. 

25 E.g., TANC, Snohomish, Municipal Commenters, and TDU Systems. 

26 See also National Grid and EEI. 
Docket No. RM06-4-000 - 20 - 

to circumstances beyond their control. For example, a transmission owner should not 

lose its incentive rate treatments if it does not succeed in meeting desired reductions in 

congestion because the applicant may not have complete control of the factors affecting 

congestion, such as generation additions, changes in load location and operation of 

neighboring systems, and RTO policies. KKR emphasizes that the Commission should 

retain the flexibility to assess an applicant’s proposal as the facts and circumstances will 

vary case-by-case. Finally, KKR recommends that applicants be required to file a report 

on their performance every several years and that the Commission may initiate a 

proceeding to review incentives only if the criteria are not met. KKR explains that 

frequent reviews run the risk of distorting results due to the “lumpiness” of capital 

investment and the long time periods to make capital additions and for capital additions 

to have effects. Further, KKR states that frequent reviews will make long-term 

investments more uncertain and, hence, less likely. In supplemental comments, KKR 

asserts that higher ROEs are of material value for Transcos only when long-term. KKR 

cites International Transmission as an example, noting that it is only able to invest in 

excess of every dollar it earns back into its system due to the certainty afforded it by its 

rate compact, which is long-term, formula-based, and includes a reasonable ROE. The 

certainty and long-term horizon of International Transmission’s rates give debt and 

equity investors in International Transmission comfort that they will ultimately receive an 

adequate return on their capital. 
Docket No. RM06-4-000 - 21 - 

3. Commission Determination

34. Section 219 of the FPA became effective on August 8, 2005. Codification of 

section 219 on that date and the requirement for a rule authorizing investment incentives 

provided notice to the industry that Congress intended that the Commission provide 

incentive-based rate treatments promptly. Thus, the Final Rule will become effective 60 

days after publication in the Federal Register. However, we clarify that any investment 

made in, or costs incurred for, transmission infrastructure after August 8, 2005 that 

ensures reliability or lowers the cost of delivered power by reducing transmission 

congestion will be eligible for incentive-based rate treatments under this Rule. 

Applicants seeking incentive-based rate treatments for investments made or costs 

incurred after August 8, 2005 will need to satisfy the requirements of this Rule to obtain 

and recover any incentives and will need to make an appropriate filing under section 205. 

35. The fact that a proposed expansion was in a utility’s expansion plan as of August 

8, 2005 does not disqualify the project for incentive treatment. Inclusion of a facility in a 

plan does not mean that a project can or will get built. Even where a project already has 

been planned or announced, the granting of incentives may help in securing financing for 

the project or may bring the project to completion sooner than originally anticipated. 

Congress’s directive that the Commission issue a rule within one year of enactment of 

EPAct 2005 shows that Congress intended for the Commission to take steps to bring new 

transmission on line expeditiously. 
Docket No. RM06-4-000 - 22 - 

36. With respect to the issue of how long an incentive-based proposal should remain 

in effect, the Commission recognizes that it may be necessary to authorize incentives that 

may extend over several years in order to support investment in long-term transmission. 

It can be important to investors making long-term investments in long-lived facilities to 

be assured that a ratemaking proposal adopted prior to construction of those facilities will 

not later be altered in a manner that undermines the basis for the financing of those 

facilities. The Commission will therefore allow applicants to propose specific time 

periods by which their incentive-based proposals will not be "re-opened" in a manner 

incompatible with the nature of the initial approvals. However, to ensure that ratepayers 

are also adequately protected, we will require any applicants seeking such a fixed term 

for its plan to explain how ratepayers can be assured that such a plan is delivering the 

benefits that formed the basis for the Commission's initial approval of it. For example, an 

applicant may propose periodic progress assessments with appropriate metrics to measure 

how well the project is progressing and whether the proposed investment in new 

transmission is improving reliability or reducing congestion. Such metrics would provide 

the Commission a means to determine whether and how the applicant is providing the 

anticipated benefits and thus that the approved incentives need not be revisited. Because 

the scope and size of each project will differ, any applicant seeking incentive-based rate 

treatments may propose metrics for its project as well as the frequency for review of 
Docket No. RM06-4-000 - 23 - 

those metrics.27 An applicant may include its proposed metrics and any timetable for 

review in its section 205 rate filing seeking recovery of incentives.28 Where such metrics 

are found to be needed and are approved by the Commission, an applicant would be 

required to submit information filings to the Commission consistent with the approved 

metrics and timetable. We clarify, however, that the metrics reviews will not be 

opportunities to re-argue the issues addressed in proceedings granting the incentive-based 

rates; they are for the purpose of measuring whether the plan is being implemented as 

initially approved. 

IV. Discussion

A. Standard for Approval of Incentive-Based Rate Treatments 

1. The Final Rule Applies to the Recovery of Costs Incurred to Ensure 

Reliability or to Reduce Transmission Congestion, or Both. 

a. Background

37. Proposed § 35.35(d)(1) specifies that the Commission will authorize incentivebased rate treatments for investment by public utilities, including Transcos, in new 

transmission capacity that reduces the cost of delivered power by reducing congestion or 

promotes reliability, as demonstrated in an application to the Commission. 

 27 The information may include, as well as supplement, information provided in 

FERC-730, discussed in section V below. 

28 An applicant has the option to include metrics proposals in a declaratory order 

proceeding, but would also need to include them in the subsequent section 205 rate filing. 
Docket No. RM06-4-000 - 24 - 

b. Comments

38. Many commenters urge the Commission to be flexible in applying the 

incentives.29 Southern and the Nevada Companies assert the Commission should not 

require that facilities both improve regional reliability and reduce congestion to be 

eligible for an incentive ROE. They argue that the guiding factor should be to provide 

incentives that improve regional reliability and/or reduce transmission congestion. AEP 

urges the Commission to adopt a functional approach to determine whether a project 

qualifies for incentives. For example, AEP suggests that projects that connect newer 

technology generation or renewables be eligible for incentives. Upper Great Plains 

contends that incentives should be available for projects that support the development of 

new electric generation in recognition of the expected growth in electric consumption and 

the need for additional investment to keep pace. 

39. Several commenters urge the Commission to establish criteria for transmission 

projects to demonstrate that they achieve Congress’ goals before projects receive an 

incentive.30 The New York Commission asks the Commission to convene a technical 

conference to develop the criteria. 

 29 E.g., FirstEnergy, Southern, Nevada Companies, AEP. 

30 E.g., AEP and New York Commission. 
Docket No. RM06-4-000 - 25 - 

40. The Maryland Commission supports incentives that are forward-looking and 

targeted to support electric reliability, competitive markets and diversity in fuel sources, 

including renewable resources, in the short and long term. 

c. Commission Determination

41. The purpose of section 219 of the FPA is to benefit consumers by promoting 

transmission capital investments that result in reliable and economically efficient 

transmission and generation. Congress did not enact section 219 in isolation. Section 

219 is a part of a larger statutory framework in which Congress directed the Commission 

to take steps to address reliability of the bulk power system as well as to remedy the 

adverse effects of transmission congestion. For example, in new section 215 of the FPA 

Congress enacted a regulatory regime under which the Commission will, for the first time 

in its history, approve and enforce mandatory reliability standards for the nation’s power 

grid.31 In new section 216, Congress directed the Secretary of Energy to identify areas of 

the nation in which transmission congestion adversely affects consumers (national 

interest electric transmission corridors) and gave the Commission certain permitting 

authority to ensure timely construction of transmission facilities to remedy transmission 

congestion in those corridors. In section 1223 of EPAct 2005, Congress directed the 

Commission to encourage the deployment of advanced transmission technologies that 

 31 See Order No. 672, Rules Concerning Certification of the Electric Reliability 

Organization; and Procedures or the Establishment, Approval, and Enforcement of 

Electric Reliability Standards, 71 FR 8662 (Feb. 17, 2006), FERC Stats. & Regs. 

¶ 31,204 (2006). 
Docket No. RM06-4-000 - 26 - 

increase the capacity, efficiency and reliability of an existing or new transmission facility. 

In enacting these provisions of EPAct, Congress made clear that it was equally concerned 

with reliability as well as the adverse impacts of transmission congestion and that the 

Commission should take steps to address both issues. New FPA section 219, which is 

complementary to these other EPAct provisions, directs the Commission to provide rate 

incentives for the purpose of ensuring reliability and reducing transmission congestion. 

However, nowhere in section 219 does the language say that the Commission may 

provide incentives only to applicants that propose to both improve reliability and reduce 

congestion. In fact, we believe it would be contrary to the intent of the new provisions, 

taken together, to limit incentives this way. 

42. Consistent with the overall goals of Congress in EPAct 2005, and in particular its 

focus on reliability improvements and relief of transmission congestion, we interpret 

section 219 to promote capital investment in a wide range of infrastructure investments 

that can have either reliability or congestion benefits rather than investments that have 

both reliability and congestion benefits. The alternative to this reading would be to apply 

section 219 in a manner that would deny incentive-based rate treatments to a transmission 

facility that significantly enhances reliability but does not reduce the cost of delivered 

power by reducing transmission congestion. This would be contrary to a fundamental 

goal of EPAct 2005 to improve reliability of the interstate transmission grid. We do not 

consider such an interpretation to be reasonable. In any event, we expect there will be 

few transmission projects that provide one type of benefit but not the other. 
Docket No. RM06-4-000 - 27 - 

43. Commenters seeking a narrow reading of section 219 are primarily concerned with 

the impact of any incentive-based rate treatment on an applicant’s rates. These concerns 

are premature. Before the Commission will permit any applicant to recover incentives in 

its rates, the Commission will evaluate the rate impact under section 205 or 206 of the 

FPA. Interested parties may raise any rate concerns at that time. Further, our case-bycase approach ensures that the incentives granted will be tailored to particular 

circumstances. Finally, except for the rebuttable presumptions addressed below, we will 

not at this time establish more detailed criteria an applicant must meet to be eligible for 

incentive-based rate treatments. Establishing criteria now would limit the flexibility of 

the Rule or improperly pre-judge which projects are acceptable for incentives. The 

Commission will, on a case-by-case basis, require each applicant to justify the incentives 

it requests. Because these proceedings will provide ample opportunity for parties to 

comment on any incentive proposal, we do not see the need for a technical conference or 

detailed criteria now. This notwithstanding, we provide certain guidance, as described 

below, regarding the types of projects that may be particularly well suited to certain 

incentives and others that may not. 

2. Other Criteria For Approval of Incentives

a. Comments

44. Numerous commenters seek additional conditions to be considered in the grant of 

incentives. Some argue that the number of incentives should be limited while others 
Docket No. RM06-4-000 - 28 - 

recommend additional criteria that an applicant must satisfy32 or that the incentives be 

limited to certain types of facilities. For example, TDU Systems assert that the Final 

Rule should specifically identify other incentives that will be considered under § 35.35(d) 

(viii) and specify the parameters for eligibility for the incentives. EEI, however, contends 

the Commission should allow individual companies to propose any incentives on a caseby-case basis because the individual companies are in a better position to understand the 

efficacy of particular incentive mechanisms. Similarly, National Grid requests 

clarification that the incentives are not mutually exclusive and transmission owners 

should be free to propose customized rate packages that include one or more of the 

incentives in combination. 

45. With regard to additional conditions, some commenters argue, for example, that 

the Commission should authorize incentives only for proposals that recognize regional 

differences, that are the product of an open and inclusive regional transmission planning 

process, increase network capacity, or that respond to specific reliability or congestion 

concerns. TANC argues that the Commission should limit qualification for the incentives 

to those transmission projects that are 200 kV and above. NECOE argues that incentives 

should be provided to utilities that conform to good utility practice and minimize total 

costs. Also, NECOE asserts that, when more than one incentive is requested, the 

Commission should require the applicant to demonstrate why a single, appropriately 

 32 E.g., East Texas, TANC, and TAPS. 
Docket No. RM06-4-000 - 29 - 

targeted incentive is insufficient. Several commenters urge the Commission to grant 

incentives for existing facilities and for maintenance of existing facilities.33 The 

Southern Companies state that the Commission should grant incentives to proposals that 

resolve a significant inter or intra-regional constraint, or preclude or mitigate anticipated 

constraints that may or may not arise. Progress asserts that incentives should be granted 

to encourage installation of new software to better manage flowgates and calculate 

Available Transfer Capability values on existing transmission facilities. The Steel 

Manufacturers state that a utility does not deserve special rate treatment to maintain or 

upgrade its facility to comply with mandated reliability standards. 

46. Several commenters urge the Commission to condition any incentive-based rate 

treatment on the applicant, among other things, divesting the subject facility to a Transco, 

demonstrating that the subject facility solves congestion constraints on a regional basis or 

results in significant new transfer capacity, complying with the 1992 and 1994 Policy 

Statements, showing that the facilities would not have been built absent the incentives, or 

showing that the facilities were not already necessary to meet NERC reliability criteria or 

normal load growth.34 PJM proposes a tiered procedure to determine whether incentives 

are warranted. TDU Systems recommend that incentives should be denied to public 

 33 E.g., FirstEnergy, PSEG, AEP, EEI, Duquesne and MidAmerican. 

34 E.g., TDU Systems, APPA, TAPS, NRECA, NARUC, NASUCA, Connecticut 

DPUC, New Jersey Board, WPS. 
Docket No. RM06-4-000 - 30 - 

utilities that have refused to provide requested relief from transmission congestion in the 

form of transmission upgrades or otherwise, until such congestion is remedied without 

the incentive rates. 

47. Several commenters request that the Commission allow states to play a role in the 

approval or recovery of incentives because states may hinder recovery of incentives in 

bundled rates.35 National Grid asserts that the Commission and states should have an 

alignment of interests on transmission investment and, therefore, there is no basis to 

believe that the rule will warrant shifts in states’ roles. 

b. Commission Determination

48. Congress has determined that there is a need for incentives, and has directed the 

Commission to issue a rule to provide them. Most of the prerequisites and preconditions 

raised in the comments reflect a desire to limit or circumscribe the nature or applicability 

of incentives that may be granted under the rule. We have considered these comments 

and do not believe that any of them should be adopted at this time. Some of them are 

consistent with our overall policy goals (such as the emphasis on regional planning) and, 

to that extent, we explain how we will factor those considerations into an analysis of a 

proposed incentive. However, some are inconsistent with the policy goals of section 219 

because they will only serve to discourage transmission investment. Therefore, unless 

 35 E.g., CREPC, KCPL, Steel Manufacturers, Montana-Dakota, MidAmerican, and 

EEI. 
Docket No. RM06-4-000 - 31 - 

adopted in other sections of this rule, we will not require applicants to satisfy the 

requirements proposed in the comments. For example, we reject arguments that an 

applicant must show that, but for the incentives, the expansion would not occur. Those 

arguments are based on commenters’ conclusions that the Commission’s prior issuances 

(i.e., Removing Obstacles order, the 1992 Policy Statement, or the innovative rate 

proposal in Order No. 2000) required an applicant to show need prior to receiving 

incentives. However, the Final Rule is based on a clear directive from Congress that does 

not require an applicant to show that it would not build the facilities but for the 

incentives. This notwithstanding, we do require applicants to show some nexus between 

the incentives being requested and the investment being made, i.e., to demonstrate that 

the incentives are rationally related to the investments being proposed. 

49. We also consider our procedures for the approval of incentives to be 

comprehensive and, therefore, will not attempt to establish gradations regarding either 

approval requirements or the amount of incentive approved, as recommended by TANC, 

PJM, Industrial Consumers and others. Section 219 does not mandate higher returns for 

projects that are part of independent regional planning processes, nor does it require 

higher standards of review for projects that do not result from independent planning 

processes. As long as the project ensures reliability or reduces the cost of delivered 

power by reducing congestion, regardless of where it is located on the nationwide 

transmission grid, the project is eligible for incentive ratemaking. 
Docket No. RM06-4-000 - 32 - 

50. We will not impose size limits on eligible transmission projects. Projects below 

200 kV can have a significant impact on reliability or reduce congestion, and therefore 

would qualify for incentive treatment. We will also not condition approval of incentives 

on market power findings. Our regulations and penalties on market power and market 

behavior are sufficient inducements to ensure markets are not manipulated and, therefore, 

additional provisions are not necessary. 

51. We will not deny incentives to public utilities that have not built transmission 

upgrades requested by transmission customers. The scope of this Rule is restricted to 

implementing the requirements of section 219; the appropriate means to address this issue 

is to file a complaint in a separate proceeding. 

52. While the promotion of renewable energy projects supports other policy and 

regulatory objectives, we will not adopt separate rate-based incentives for renewable 

energy projects. Congress directed the Commission to issue a rule to ensure reliability or 

to reduce the cost of delivered power by reducing transmission congestion regardless of 

the nature of the energy carried over the new transmission facilities. We believe that, by 

providing incentives applicable to all transmission facilities, the Final Rule provides 

incentives for transmission to serve renewable resources and, therefore, additional 

incentives are not necessary. 

53. Because section 219 provides a new directive to the Commission to permit greater 

incentives and does not on its face require an individual showing of need by incentive 
Docket No. RM06-4-000 - 33 - 

applicants, we will not require compliance with the 1992 or 1994 Transmission Policy 

Statements as a precondition for approval of incentives. 

54. With regard to state review, the Commission recognizes that incentives for many 

utilities are incorporated into rates that must receive state commission approval and that 

many decisions on siting and permitting of new facilities are under the jurisdiction of 

state and local government authorities. Because of this, we will carefully consider the 

views of any state bodies having jurisdiction over these matters. We also will, as 

discussed below, adopt a rebuttable presumption that projects approved by an appropriate 

state commission or siting authority are eligible for incentives under section 219. We 

believe that, in these ways, we will appropriately coordinate our consideration of 

incentives with the views of responsible state agencies. We will not, however, adopt any 

further requirements regarding state approval, such as the requirement that an applicant 

receive state approval of any proposed incentives. While state approval is desirable it is 

not required by section 219. However, if state approval of a particular plan is required, 

we expect that any applicant will seek that approval in due course. 

55. Finally, we reiterate that an applicant may request any combination of the 

incentives listed in the Final Rule. Applicants also may request incentives that are not 

listed in the Final Rule. The Commission will not use the Final Rule to identify each and 

every incentive an applicant may request. However, this in no way relieves the applicant 

of fully supporting its rate request and demonstrating that its request for incentives 

satisfies section 219 and the requirements of this Final Rule. If an interested party 
Docket No. RM06-4-000 - 34 - 

believes a particular incentive is not warranted, it may raise its concerns when an 

applicant proposes that incentive in a declaratory order or in a section 205 rate 

application. 

56. Because section 219 makes clear that the Final Rule should promote capital 

investment in the operation and maintenance of all facilities for the transmission of 

electric energy in interstate commerce, new investment in existing facilities will be 

eligible for incentive-based rate treatments.36 The reliability benefits of operation and 

maintenance capital spending are obvious, and we expect applicants incurring this type of 

capital spending will be able to demonstrate reliability benefits and thereby be eligible for 

incentive treatment. 

3. Rebuttable Presumptions

57. As we discussed above, we will not adopt the variety of preconditions 

recommended by the commenters. However, we are nonetheless required to make 

findings that a particular investment falls within the scope of section 219. In making that 

finding, we have chosen to rely on existing processes to the extent practicable in 

determining whether a particular facility is needed to maintain reliability or reduce 

congestion. We describe these processes below and find that, if an applicant satisfies 

them, its project will be afforded a rebuttable presumption that it qualifies for 

 36 In addition, the Final Rule makes available incentives for joining a Transmission 

Organization. 
Docket No. RM06-4-000 - 35 - 

transmission incentives. Other applicants not meeting these criteria may nonetheless 

demonstrate that their project is needed to maintain reliability or reduce congestion by 

presenting us a factual record that would support such findings. Once we determine that 

the project is eligible for incentives, we would, as described below, consider whether the 

particular incentives being proposed are appropriate for the particular investments being 

made. 

58. The first rebuttable presumption we will adopt relates to regional planning. 

Although we will not require participation in regional planning processes as a 

precondition for obtaining incentives, as section 219 does not require such a precondition, 

we believe that regional planning processes can provide an efficient and comprehensive 

forum through which those seeking to make transmission investments can have their 

projects evaluated to see if they meet the requirements of section 219. Regional planning 

processes can help determine whether a given project is needed, whether it is the better 

solution, and whether it is the most cost-effective option in light of other alternatives 

(e.g., generation, transmission and demand response). It does so by looking at a variety 

of options across a large geographic footprint; thus, regional planning can allow for a 

broad assessment of loop flows and impacts on neighboring systems. Regional Planning 

also can serve as a forum in which states can readily participate.37 This benefit of a 

 37 State representation in stakeholder committee is a feature of the Midwest ISO, 

i.e., the Organization of MISO States (MISO States or OMS). 
Docket No. RM06-4-000 - 36 - 

regional planning process is difficult to duplicate on a utility-by-utility basis. It may 

prove difficult for applicants, on an individual basis, to timely gain access to all the 

information that might be required to make a showing that the project ensures reliability 

and/or reduces the cost of delivered power by reducing congestion. The Commission 

expressly recognized the value of regional planning when it proposed to amend the pro 

forma Open Access Transmission Tariff of jurisdictional public utilities to require 

regional planning to ensure that transmission is planned and constructed on a 

nondiscriminatory basis to support reliable and economic service to all eligible customers 

in a region. 38 Consistent with our actions in that NOPR and our belief that power 

markets are regional in nature and that the transmission systems supporting those markets 

must be supported by regional planning, we will create a rebuttable presumption for 

projects that result from regional planning. Thus, the Commission will rebuttably 

presume that transmission projects that result from a fair and open regional planning 

process that considers and evaluates projects for reliability and/or congestion and is found 

 38 Preventing Undue Discrimination and Preference in Transmission Service, 

Notice of Proposed Rulemaking, 71 FR 32,636 (June 6, 2006), FERC Stats. & Regs., 

Regs. Preambles ¶ 32,603 at P 36 (2006) (OATT Reform NOPR): 

We conclude that the inadequacy of the existing obligation to conduct joint 

and regional transmission system planning, coupled with the lack of 

transparency surrounding system planning generally, require reform of the 

pro forma OATT to ensure that transmission infrastructure is constructed 

on a nondiscriminatory basis and is otherwise sufficient to support reliable 

and economic service to all eligible customers. 
Docket No. RM06-4-000 - 37 - 

to be acceptable to the Commission satisfy the requirements of this Rule.39 In addition, 

the Commission will adopt the following other rebuttable presumptions. We will also 

attach a rebuttable presumption that an applicant has met the requirements of section 219 

if a proposed project is located in a National Interest Electric Transmission Corridor or 

where a project has received construction approval from an appropriate state commission 

or state siting authority. 

4. Applicants Seeking Incentive-Based Rates Will Not Be Required To File A 

Cost-Benefit Analysis

a. Background

59. The NOPR explained that no cost-benefit analysis would be required to obtain 

incentives because customers will be protected by the Commission’s review of 

applications pursuant to sections 205, 206 and 219 of the FPA, which require that all 

rates be just and reasonable and not unduly discriminatory or preferential.40

b. Comments

60. Certain commenters argue that judicial precedent requires that incentive rates be 

supported by a showing of a quantifiable relationship between the incentive and the result 

 39 An applicant may wish to file a request for incentive treatment for a project 

which is undergoing consideration in a regional planning process. The Commission will 

consider such requests, but may make any requested rate treatment contingent upon the 

project being approved under the regional planning process. As discussed elsewhere in 

this Final Rule, different types of projects and the circumstances under which they are 

undertaken may warrant different rate treatments and incentives. 

40 NOPR at P 16. 
Docket No. RM06-4-000 - 38 - 

the incentive is intended to achieve.41 They also argue that the level of the incentive must 

be calibrated to a level that it is no more than needed to achieve the outcome that the 

incentive is supposed to produce.42 They further argue that section 219 does not require 

significant changes to the Commission’s existing rules and ratemaking policies governing 

incentive rates, such as its 1992 Policy Statement43 and Order No. 2000,44 in which the 

Commission required that applications for incentives be supported with cost-benefit 

analyses. They contend that the Commission’s existing rules and policies already satisfy 

the Commission’s obligations under the FPA, even as amended by section 219, and 

should be retained.45 

61. Several commenters state that, without a cost-benefit analysis, the Commission 

has no basis for concluding that a particular incentive provides customers with a net 

 41 E.g., NECOE, PSE&G, and WPC Companies. 

42 E.g., NECOE. 

43 Incentive Ratemaking for Interstate Natural Gas Pipelines, Oil Pipelines, and 

Electric Utilities: Policy Statement on Incentive Regulation, 61 FERC ¶ 61,168 at 61,590 

(1992). 

44 Regional Transmission Organizations, Order No. 2000, 65 FR 809 (Jan. 6, 

2000), FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,089 

(1999), order on reh'g, Order No. 2000-A, 65 FR 12,088 (Mar. 8, 2000), FERC Stats. & 

Regs., Regulations Preambles July 1996-December 2000 ¶ 31,092 (2000), aff'd sub nom.

Public Utility District. No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 

(D.C. Cir. 2001). 

45 E.g., TDU Systems, NRECA, NECOE, and SMUD. 
Docket No. RM06-4-000 - 39 - 

benefit or will be just and reasonable.46 The New York Commission suggests that criteria 

for a cost-benefit analysis be established through a separate technical conference or 

rulemaking. 

62. PJM argues that the Commission should provide incentives for transmission 

owners’ participation in robust regional transmission planning that identifies both the 

costs and economic benefits of a given project. PJM proposes that such a process should 

support a rebuttable presumption that the decision to build is prudent and warrants an 

ROE incentive. 

63. East Texas states that utilities engaged in meeting reliability standards, 

constructing projects across designated corridors and joining qualified Transmission 

Organizations should be allowed the incentive rates on the simple showing that they seek 

to recover no more than their prudently incurred costs. SMUD states that, under section 

219, an incentive is appropriate only when it results in lower power costs to consumers. 

The Oklahoma Commission states that the Commission should give direction as to the 

showing by applicants that is acceptable in lieu of the cost-benefit analysis. 

64. Other commenters argue that a cost-benefit analysis is unnecessary.47 National 

Grid states that the Commission already recognized generically the benefits of using ROE 

 46 E.g., NRECA, NARUC, TAPS, East Texas, Connecticut AG, Industrial 

Customers, NECPUC, California Oversight Board, MISO States, DTE Energy, Wyoming 

Consumer Advocate, and New York Commission. 

47 E.g., National Grid. 
Docket No. RM06-4-000 - 40 - 

adders as an incentive for needed transmission investment in the Removing Obstacles

order.48 FirstEnergy asserts that consumers benefit by strengthening the transmission 

grid and by encouraging new investment in transmission and that the benefits of these 

factors potentially far exceed the costs. International Transmission asserts that requiring 

a cost-benefit analysis could delay needed transmission upgrades. 

c. Commission Determination

65. We reaffirm the NOPR’s determination not to require applicants for incentivebased rate treatments to provide cost-benefit analyses. The courts have long recognized 

that a primary purpose of the FPA, and its counterpart the Natural Gas Act, is to 

encourage the orderly development of plentiful supplies of electricity and natural gas at 

reasonable prices.49 To carry out this purpose, the Commission may consider non-cost 

factors as well as cost factors.50 Moreover, Congress’s enactment of section 219 reflects 

its determination that incentives generally can spur transmission investment which will, 

in turn, provide the benefits of a robust transmission system identified by the 

 48 Removing Obstacles to Increased Electric Generation and Natural Gas Supply in 

the Western United States, 94 FERC ¶ 61,272, reh’g denied, 95 FERC ¶ 61,225, order on 

reh’g, 96 FERC ¶ 61,155, further order on reh’g, 97 FERC ¶ 61,024 (2001). 

49 See, e.g., Pub. Utilities Comm’n of the State of California v. FERC, 367 F.3d 

925, 929 (D.C. Cir. 2004) (CPUC v. FERC), citing NAACP v. FPC, 425 U.S. 662, 670 

(1976). 

50 Id., citing Permian Basin Area Rate Cases, 390 U.S. 747, 791, 815 (1968); 

Maine Public Utilities Commission v. FERC, No. 05-1001, slip op. at 19 (D.C. Cir., 

June 30, 2006). 
Docket No. RM06-4-000 - 41 - 

commenters. The Commission will consider the justness and reasonableness of any 

proposal for incentive rate treatment in individual proceedings. 

5. Procedural Requirements for Obtaining Incentive-Based Rate Treatments

a. Background

66. Section 35.35(c) in the NOPR proposed that all rates approved under the rule 

would be subject to sections 205 and 206 of the FPA. Section 35.35(d) in the NOPR 

proposed certain options by which an applicant may seek incentive-based rate treatments. 

The NOPR proposed that applicants must explain whether the proposed facilities are part 

of an independent regional planning process. The Commission also sought comment on 

whether the Final Rule should establish a definition of “independent regional planning 

process” or if the Commission should consider this issue on a case-by-case basis. 

b. Comments

67. Most transmission owners request that the Commission implement a streamlined 

process to review and approve incentive-based rate treatments. For example, some 

suggest that the Commission adopt a pre-approval procedure that provides a preliminary 

determination of a project’s rate treatment, similar to the expedited pre-approval in the 

Path 15 upgrade in California,51 to promote timely construction of additional needed 

transmission facilities.52 

 51 See Western supra note 2. 

52 E.g., Mid-American, Nevada Companies, PacifiCorp, and Northwestern. 
Docket No. RM06-4-000 - 42 - 

68. A number of commenters urge the Commission not to require transmission owners 

to make section 205 filings to implement incentive-based rates. They argue that such 

proceedings may result in unreasonable delay and uncertainty and thereby discourage, if 

not preclude, incentive-based rate proposals.53 Many of these parties urge the 

Commission automatically to approve incentives once the facilities or investment have 

been shown to ensure reliability or reduce congestion.54 Other commenters suggest that 

the Commission create a category of incentives that would not require any review under 

section 205 and then hold paper hearings only for those incentives that do not fall within 

the designated category of incentives.55 Other commenters request that the Commission 

establish a rebuttable presumption that each incentive is just and reasonable or allow 

transmission owners to self-certify that they meet the criteria of section 219.56 Others 

similarly ask that there be a presumption that facilities included in a regional planning 

process are eligible for incentives.57 Another group of commenters argue that projects 

 53 E.g., United Illuminating, Vectren, NSTAR, and EEI. 

54 E.g., Nevada Companies and MidAmerican. 

55 E.g., EEI, NU, New England TOs, NYSEG, and RGE. 

56 E.g., Southern and FirstEnergy. 

57 E.g., BG&E, PEPCO, KCPL, National Grid, PJM, PJM TOs, United 

Illuminating and Vectren. 
Docket No. RM06-4-000 - 43 - 

need not be part of an independent regional planning process to receive an incentive 

because other regional processes will also provide the same benefits.58

69. EEI argues that public utilities should be permitted to make limited section 205 

filings to specifically address recovery of incentives in rates, regardless of the form of 

rate. 

70. National Grid requests clarification that the Commission will continue to accept 

incentive and rate reforms that are tailored to the specific needs of the transmission 

owner, so that transmission owners can be allowed more traditional rate treatment, such 

as accruing the allowance for funds used during construction, capitalization of precommercial costs and a 30-year depreciation. 

71. BG&E requests clarification that, once the Commission approves an incentivebased ROE for a particular regional planning process, any entity within that planning 

process will be authorized to receive the approved incentive-based ROE without being 

required to individually apply for, or rejustify, the incentive. 

72. Some commenters argue that the Commission must review all elements of an 

applicant’s cost of service before authorizing any incentives.59 The Steel Manufacturers 

assert that applicants must justify each incentive they request under sections 205, 206, 

 58 E.g., EEI, Progress, Nevada Companies and FirstEnergy. 

59 E.g., Dairyland, TDU Systems, and NASUCA. 
Docket No. RM06-4-000 - 44 - 

and 219 and that those applications seeking more than one incentive must demonstrate 

that the overall package results in rates that satisfy the same criteria. 

73. TAPS asserts that, when an applicant files a facility-specific incentive filing the 

load divisor and depreciation reserve should be updated, in the circumstance that existing 

rate inputs are known; and, if they are not known because they are part of a “black box” 

settlement, they should be imputed. TAPS suggests ways in which this can be done. 

74. Snohomish argues that applicants should be required to submit a schedule of 

lower-cost alternatives, including potential non-wires solutions, and to explain why these 

alternatives were not chosen. The Oklahoma Commission recommends that state 

commissions make the determination as to whether the cost of the project, including the 

cost of the incentive, is more beneficial for ratepayers than if a generation facility were 

built closer to avoid the cost of transmission. 

75. Finally, several commenters urge the Commission to adopt a generic definition of 

independent regional planning as well as guidelines and minimum criteria for acceptable 

independent regional planning processes.60 Other commenters ask the Commission to be 

flexible in determining what constitutes a satisfactory “regional planning process,” and to 

take into consideration any differences among regions on a case-by-case basis.61 

 60 E.g., PJM TOs, APPA, International Transmission, MidAmerican, Pacificorp, 

National Grid, Kentucky Commission, PJM, OMS, NRECA and Semantic. 

61 E.g., Consumer Energy Council, Ameren, SDG&E, Southern Companies, 

NorthWestern and PEPCO, Dairyland, and Vectren. 
Docket No. RM06-4-000 - 45 - 

c. Commission Determination

76. Our goal is to provide procedural options that offer applicants flexibility to address 

their construction and investment opportunities while at the same time ensuring that the 

resulting rates are just and reasonable and not unduly discriminatory or preferential. The 

Commission offers two ways to accomplish this. An applicant may obtain these rulings: 

(1) through a combination of a petition for a declaratory order and a subsequent section 

205 filing or (2) by filing only a section 205 filing. For both of these options, the 

applicant must demonstrate that the facilities for which it seeks incentives either ensure 

reliability or reduce the cost of delivered power by reducing transmission congestion 

consistent with the requirements of section 219, that there is a nexus between the 

incentive sought and the investment being made, and that the resulting rates are just and 

reasonable. 

77. The Commission has found that the first option – petition for declaratory order 

followed by a section 205 filing – to be a valuable tool. In certain instances, it is valuable 

for an applicant to obtain an order indicating it qualifies for incentive-based rates prior to 

making a formal section 205 filing and prior to commencing siting, permitting and 

construction activities because such orders facilitate financing and investment in new 

facilities.62 To provide applicants with as much flexibility as possible, the Commission 

will permit applicants to seek a declaratory order prior to construction of the facilities to 

 62 See Western supra note 2. 
Docket No. RM06-4-000 - 46 - 

request a finding that the facilities qualify for incentive-based rate treatments. The 

petitioner would have to demonstrate that its proposal will either ensure reliability or 

reduce the cost of delivered power by reducing transmission congestion. The petitioner 

may rely on one of the rebuttable presumptions outlined above or make an independent 

demonstration. The applicant may also use the petition to justify which incentives it 

seeks to implement. We clarify that any declaratory order will only rule on whether the 

applicant’s proposal qualifies for incentive-based rate treatment and, if requested, which 

incentives the applicant may adopt. The applicant must seek to put the rates into effect 

through a separate single-issue or comprehensive section 205 filing. The Commission’s 

expectation is that, based on past practice, a declaratory order finding that the applicant is 

eligible for incentive-based rate treatments would be sufficient for the applicant to obtain 

funding or otherwise acquire financing for the project. The Commission will seek to 

process petitions for declaratory order quickly. While we cannot guarantee Commission 

action within 60 days of the request (as is statutorily required for section 205 filings), we 

will strive to meet that standard. 

78. If an applicant obtains a declaratory order finding that the proposal qualifies for 

incentive-based rate treatment, the subsequent section 205 proceeding would be limited 

to a review of the applicant’s rates and would not include a review of whether the 

applicant’s facility qualifies to receive incentive-based rate treatments. If the petition 

addresses the applicant’s incentives or finds that the required nexus has been 

demonstrated, the applicant would not be required to re-justify those findings in the 
Docket No. RM06-4-000 - 47 - 

section 205 filing. Therefore, if an interested party believes a petitioner’s proposal does 

not qualify for incentive-based rate treatments or that the incentives requested are not 

justified, the party must raise its objections when the petition is filed and not wait to raise 

them in the subsequent section 205 proceeding. If an applicant obtains a declaratory 

order and the proposal changes from the facts on which the declaratory order was issued, 

the applicant may seek another declaratory order or wait to seek approval of the changes 

in the subsequent section 205 filing. In that event, interested parties may challenge the 

changes in the section 205 proceeding. 

79. The second option involves filing only a section 205 filing (either “single-issue” or 

comprehensive) to request all of the required approvals. Prior to recovering any 

incentive-based rate treatments in rates, an applicant must demonstrate that the rates in 

which the applicant seeks to recover any incentives are just and reasonable and not 

unduly discriminatory. However, the applicant will have the option of filing a 

comprehensive section 205 rate case in which all of the utility’s rates would be reviewed 

in conjunction with the proposed recovery of the incentive-based rate treatments or filing 

a single-issue section 205 rate filing in which only the impact of the incentive-based rate 

treatment for the facility granted the incentive will be addressed. As explained below in 

section IV.B.7 (the discussion of single-issue section 205 proceedings), the Commission 

believes there is a sufficient need for timely investment in transmission infrastructure to 

justify, in certain circumstances, a departure from our past practice by allowing an 

applicant to seek to recover any incentive in a single-issue section 205 rate proceeding. 
Docket No. RM06-4-000 - 48 - 

Single issue section 205 proceedings, as well as the declaratory order procedural option 

discussed above, can remove obstacles to new investments by allowing for timely cost 

recovery. Single issue filings also can support new investment by allowing applicants to 

compare the returns of such investments with the risks of the project itself, as opposed to 

having to compare those returns to both the risks of the project being pursued and the 

risks associated with re-opening all their rates, which is ordinarily a time-consuming, 

expensive, litigious and uncertain process. Additionally, in further facilitating these 

goals, the Commission does not intend to routinely convene trial-type, evidentiary 

hearings to review either a comprehensive or a single-issue section 205 filing but will 

attempt to render a decision based on the paper submissions whenever possible. 

80. We clarify that no incentives will be granted on a final basis without a section 205 

filing. Therefore, an RTO member will not automatically receive incentives granted to 

another RTO member. However, when evaluating applications for incentive-based rate 

treatments filed by an RTO member, the Commission will take into account incentives 

granted to other RTO members, particularly in cases where investments being made by 

that other RTO member pursuant to a regional plan also lead to the need for expansions 

by the applicant in its own footprint. 

81. We will not specify the rate calculations for section 205 proceedings, as requested 

by TAPS. These issues are appropriately addressed in individual section 205 

proceedings. 

82. The Commission will require applicants to justify each of the incentive-based rate 
Docket No. RM06-4-000 - 49 - 

treatments it proposes by showing how the proposed incentive satisfies section 219.63 

For example, an applicant will be required to show how the granting of the incentive will 

promote reliable and economically efficient transmission and generation of electricity, 

attract new investment, or increase capacity and efficiency of existing transmission 

facilities or improve their operation. The Commission, as set forth above, provides 

several vehicles for making this showing, including reliance on a Commission accepted 

regional planning process. We also will require the applicant to show that there is a 

nexus between the incentives being proposed and the investment being made. 

83. With respect to procedures applicable to joining Transmission Organizations in § 

35.35(e), we clarify that applicants also may file a petition for declaratory order as to 

whether the applicant qualifies for incentives under section 219(c) and then submit a 

comprehensive or single-issue section 205 filing to obtain approval of the rates, or simply 

file a comprehensive or single-issue section 205 case to obtain all necessary approvals. 

B. Incentives Available To All Jurisdictional Public Utilities

84. In the NOPR, the Commission proposed eight incentive-based rate treatments for 

transmission infrastructure investments for all public utilities, including Transcos. As 

discussed below, the Commission will adopt these in the Final Rule. 

 63 An applicant would not be required to demonstrate that, but for the incentive, 

the project would not be completed. Section 219 does not require such a condition. 
Docket No. RM06-4-000 - 50 - 

1. ROE Sufficient to Attract Capital

a. ROE

i. Background

85. The Commission proposed to consider granting an incentive-based ROE to all 

public utilities (i.e., traditional public utilities and Transcos) that build new transmission 

facilities that benefit consumers by ensuring reliability and reducing the cost of delivered 

power by reducing transmission congestion thereby fulfilling the requirements of section 

219. As proposed, to receive an incentive-based ROE, a public utility must submit a 

request in an application under section 205 of the FPA and must support the ROE request 

by demonstrating how the new facilities will improve regional reliability and reduce 

transmission congestion. In addition, the application must explain whether the facilities 

are part of an independent regional planning process, such as that administered by an 

RTO or ISO or another independent regional planning process recognized by the 

Commission and how the proposed ROE was derived and why it is appropriate to 

encourage new investment. (NOPR at P 22) Recognizing that the Commission had 

approved higher ROEs (referred to in the NOPR as an “adder”) for certain projects that 

were designed to increase transfer capability or reduce congestion, the Commission 

sought comments on the appropriateness of a higher ROE as a mechanism for increasing 

investment in new capacity. 
Docket No. RM06-4-000 - 51 - 

ii. Comments

86. Numerous Commenters64 express general support for the proposal to grant 

incentive-based ROEs to encourage transmission investment stating that it is the most 

direct and effective means of attracting needed capital to improve the nation’s 

transmission infrastructure. Southern Companies assert that allowing an incentive ROE 

only “within the zone of reasonableness” is inconsistent with Congress’ mandate in 

section 219 that the Commission provide incentive ROEs for transmission investment. 

NSTAR and Vectren state that an incentive need not be cost-based; an incentive is 

justified under the statute as just and reasonable if it serves the statutory purpose of 

improving reliability or reducing the overall cost of delivered power. 

87. Other commenters oppose the Commission’s proposal to grant incentive-based 

ROEs for investment in new transmission facilities. For example, APPA states that an 

ROE adder is basically a bonus payment to reward transmission providers for doing the 

job for which they are already getting paid an adequate ROE under current Commission 

standards and relevant FPA requirements. Connecticut DPUC argues ROE adders are not 

a useful policy tool for improving transmission and the Commission’s standard rate 

review process of assessing the firm’s risk-adjusted cost of capital assures a completely 

adequate ROE without any adders. TDU Systems and New Mexico AG contend that 

 64 E.g., National Grid, FirstEnergy, EEI, KCPL, Xcel, Kentucky Commission, 

Nevada Companies, Progress, and Southern Companies. 
Docket No. RM06-4-000 - 52 - 

ROE adders will fail the judicial mandate that rates be just and reasonable. CREPC 

maintains that a blanket ROE increase generally runs counter to the Commission’s goal 

of encouraging transmission investment because it will either unnecessarily increase the 

cost of electricity to end-users or render an otherwise economic transmission project 

uneconomic in comparison to its alternatives. The California Commission states that the 

Commission’s reliance on incentives granted to Trans-Elect with respect to financing the 

critical Path 15 upgrade in California several years ago is misleading since the special 

consideration accorded to Trans-Elect was a direct consequence of the unique, emergency 

energy crisis facing California and the Western United States in 2001. 

88. Some commenters65 assert that the Commission must consider the certainty of rate 

recovery for investment in new transmission facilities and associated lower risk -- 

providing the basis for a lower ROE -- before granting incentive-based ROEs. Others, 

however, such as MidAmerican and PacifiCorp, state that the Commission should 

consider ROE adders or other forms of enhanced returns if a project investment entails 

levels of risk to investors and consumers that a traditional rate of return would not cover 

or otherwise lacks the economic or commercial incentives necessary to attract needed 

capital. PJM recommends the Commission establish an equity return range based on a 

generic analysis of investor expectations concerning transmission investment as opposed 

 65 E.g., NRECA, CREPC, AWEA, the Delaware Commission, New Mexico AG, 

NY Association, the New York Commission, the California Commission and SMUD. 
Docket No. RM06-4-000 - 53 - 

to an analysis of a vertically integrated company or, as an alternative, recognize the 

overall risk of each project, such as the risk of delayed recovery at the state level. 

89. TAPS states that any incentive-based adjustment to transmission returns should 

take the form of an equivalent adjustment to total return (i.e., return on both debt and 

equity), rather than making the value of the adjustment vary with the transmitter’s capital 

structure. TDU Systems state that if the Commission allows ROE adders, it should 

consider applying the adders to the overall rate of return as an alternative to estimating 

equity returns using public utility returns as a proxy. 

90. MISO States argues that the Commission should make clear that proposed ROE 

incentives are on investments in new transmission, as contrasted with all of a public 

utility’s transmission investment. TAPS claims that increasing the ROE for existing 

facilities does nothing to encourage investment in new transmission facilities. TDU 

Systems recommends limiting ROE adders to the portion of rate base related to the new 

investment. 

iii. Commission Determination

91. Consistent with the proposal in the NOPR, the Commission will allow, when 

justified, an incentive-based ROE to all public utilities (i.e., traditional public utilities and 

Transcos) for new investments in transmission facilities that benefit consumers by 

ensuring reliability or reducing the cost of delivered power by reducing transmission 

congestion. By including this provision in the Final Rule, we meet the requirement of 

section 219 to provide an ROE that attracts new investment in transmission facilities 
Docket No. RM06-4-000 - 54 - 

(including related transmission technologies). Public utilities making investments in 

transmission infrastructure have made clear, both in their applications for new projects 

and in their comments on this Rule, that the ROE incentives encourage investment. We 

expect that an incentive ROE will make transmission projects more attractive, and 

therefore more likely, when transmission projects must compete for capital in verticallyintegrated utilities as well as in transmission and delivery utilities. Accordingly, the 

Commission will approve an ROE at the upper end of the zone of reasonableness for new 

infrastructure investments that meet the requirements of section 219 as discussed 

elsewhere in this Final Rule. 

92. Concerns of blanket ROE increases and ROEs that exceed the DCF determined 

ROE are misplaced. The NOPR’s use of the term “adder” may have contributed some 

confusion regarding the Commission’s proposal. The Commission, as discussed later in 

this section, will continue to use the DCF analysis for ROE determinations. That analysis 

can result in a range of returns (e.g., 9 percent to 13 percent), any of which falling within 

the range are just and reasonable. This analysis, undertaken in individual rate 

applications, assesses representative proxy companies and the impact of other factors, 

including risk, on the zone of reasonableness for ROE. Thus, contrary to certain 

comments, our justification for a higher ROE is not based on a risk assessment; the risk 

assessment is part of the traditional DCF analysis. 

93. Under the Rule adopted herein, the Commission will provide ROEs at the upper 

end of the zone of reasonableness for transmission investments that meet the 
Docket No. RM06-4-000 - 55 - 

requirements of section 219 as discussed elsewhere in this Final Rule. Incentive-based 

ROEs, like other incentives offered in this Rule, are to be filed with the Commission for 

approval before rates that reflect such incentives can be charged. Accordingly, because 

the approved ROE, including the impact of an incentive, will be within the zone of 

reasonableness, we consider this provision consistent with section 205 of the FPA. We 

will not create specific ROE adders (e.g., 100 basis points); the Commission has always 

considered a range of returns in determining the appropriate ROE and we see no reason 

to depart from this practice. Though some commenters assert that the incentive need not 

be cost-based and therefore can justifiably be above the upper-end of the zone of 

reasonableness, we believe a return within the zone will be adequate to attract new 

investment and consistent with the intent of Congress in section 219. The Commission 

will determine the level of the ROE on a case-by-case basis when an application for an 

incentive-based ROE is filed with the Commission. This is consistent with the approach 

the Commission has employed to date, which has been found to be just and reasonable.66 

94. The foregoing does not mean, however, that we will grant incentive-based ROEs 

to every new investment that increases reliability or reduces congestion. The purpose of 

section 219 was, as described above, to require the Commission to re-examine whether 

its current policies are adequate to encourage new investment and strike the appropriate 

 66 Public Utilities Commission of the State of California v. FERC, 367 F.3d 925 

(D.C. Cir. 2004). 
Docket No. RM06-4-000 - 56 - 

balance between the investor and consumer interests. In many instances, an incentivebased ROE is appropriate because our traditional policies are not sufficient to encourage 

new investment. For example, a large new interstate transmission project that reduces 

congestion or increases reliability can face substantial risks that the ordinary transmission 

investment does not. Further, such projects will often be undertaken only at the election 

of investors, given that no single entity is "required" to undertake them, and thus an 

incentive-based ROE is appropriate to encourage proactive behavior. Other projects also 

may present special risks or considerations that merit an incentive-based ROE. By 

contrast, there are certain projects that may not merit such an incentive. For example, 

routine investments made to comply with existing reliability standards may not always 

qualify for an incentive-based ROE. These are the types of investments that have, as a 

general matter, been adequately addressed through traditional ratemaking because there is 

an obligation to construct them and high assurance of recovery of the related costs. For 

these and other reasons, traditional ROE determinations may continue to be appropriate 

for these investments. This does not mean that other incentives may not be appropriate 

for such investments (such as 100 percent CWIP recovery) or that other reliability 

investments (e.g., substantial new investments to meet new standards) would not qualify 

for incentive-based ROE determinations. 

95. We decline to apply incentives to total return, including debt, as requested by 

TAPS. Section 219 directs the Commission to focus on ROE, not total return; and this 

focus is proper. In a competitive market for debt financing, any incentives added to the 
Docket No. RM06-4-000 - 57 - 

actual costs of debt will flow to equity investors without actually increasing the returns of 

debt capital providers. Unlike debt investors who do not propose new investment or 

make direct investment decisions, equity investors make investment decisions directly or 

by giving management their proxy. Thus the opportunity for a higher ROE will directly 

and more transparently influence the actions of those in the position to make initial 

investment decisions. 

96. With regard to questions about whether the opportunity to earn an incentive-based 

ROE applies to all of a public utility’s transmission investment, we clarify that it applies 

to new transmission investment including investment that results in the enlargement of or 

improved operation and maintenance of all facilities, consistent with section 219 as 

discussed elsewhere in this Final Rule. 

b. Alternatives to DCF Analysis 

i. Background

97. While the Commission has typically utilized a DCF analysis, the NOPR (at P 20) 

sought comment on whether it should consider alternatives to the DCF analysis as a way 

to provide incentives for investment in new transmission capacity. 

ii. Comments

98. A number of commenters67 do not support a departure from the DCF method that 

the Commission currently uses to determine allowed ROE. APPA , for example, states 

 67 E.g., APPA, the Kentucky Commission, New Mexico AG, NY Association, 

New York Commission, TDU Systems and TAPS. 
Docket No. RM06-4-000 - 58 - 

that the DCF approach is generally analytically sound and has produced consistent, 

predictable results over time, eliminating some of the subjectivity and randomness in 

equity forecasts that might occur if the Commission were to change methods on a caseby-case basis. The New York Commission supports the use of a DCF analysis as an 

appropriate means to determine an ROE that reflects commensurate risks and thus would 

attract new investments. 

99. A number of commenters,68 request that the Commission adopt additional 

methodologies, such as risk premium, comparable earnings, Fama-French, and/or capital 

asset pricing, to use along with the current DCF analysis because a multiple model 

approach will result in a more representative ROE range. These commenters contend that 

the Commission should make clear that it will consider and use alternative methods of 

calculating ROEs. They argue that the Commission’s final determination of a just and 

reasonable ROE should be based on a combination of the results from those alternative 

methods of calculating ROEs, not on the result from any single method, because each 

method has its own set of theoretical deficiencies and a range of methods ensures all 

applicable variables are considered. 

 68 E.g., AEP, Ameren, EEI, California Commission, KCPL, PacifiCorp, PEPCO, 

PJM TOs, Progress Energy, NSTAR, SDG&E, SCE, Southern Companies, Trans-Elect, 

Vectren and WPS. 
Docket No. RM06-4-000 - 59 - 

100. Other Commenters69 ask that the Commission consider changes to how it 

determines proxy groups in the DCF analysis, by permitting adjustments for leveraging 

effects, or adopting modified or expanded proxy groups, as appropriate on a case-by-case 

basis, and by looking more to companies in the primary or sole business of providing 

electric delivery service or by isolating those activities from the other activities of public 

utilities included in proxy groups. EEI recommends that the Commission should use 

after-tax weighted average cost of capital to adjust for leverage differences among sample 

companies and recommends applying DCF results to the market value of equity rather 

than to the book value of equity. 

101. NSTAR and New England TOs assert that any changes to the Commission’s ROE 

methodology should not be considered an incentive because updating the ROE 

methodology including appropriate recognition of risk is not an incentive, but rather is 

necessary to assure that the ROEs received by transmission-owning utilities are 

compensatory and fair under current market conditions and recover their cost of capital. 

iii. Commission Determination

102. While commenters note that every alternative method has a theoretical deficiency 

and there is a benefit to introducing more information into the analysis process, we do not 

see any basis to conclude that the alternative methods would encourage more 

transmission investment than continued reliance on the DCF analysis. Our past practice 

 69 E.g., PEPCO, APPA, PJM, AEP, FirstEnergy, and Ameren. 
Docket No. RM06-4-000 - 60 - 

of using the DCF approach has yielded just and reasonable results and is consistent with 

long-standing ratemaking principles. Therefore, at this time, we will not make broadly 

applicable changes to how the Commission has traditionally performed its DCF analysis 

on companies in the electric industry. However, we will consider on a case-by-case basis 

whether the application of the traditional DCF analysis should be modified and entertain 

proposals to use different proxy groups as a way of capturing different business models. 

2. Construction Work in Progress (CWIP) and Pre-Commercial Expenses

a. Background 

103. In the NOPR, the Commission noted that the long lead times required to plan and 

construct new transmission can impact utility cash flow, in turn affecting the overall 

financial health of a company and its ability to attract capital at reasonable prices. The 

Commission proposed including 100 percent of CWIP in rate base;70 and expensing 

rather than capitalizing pre-commercial operations costs associated with new 

transmission investment in order to relieve the pressures on utility cash flows associated 

with transmission investment programs. 

 70 CWIP is a return on capital. Since 1987, the Commission’s general policy has 

been to allow only 50 percent of the non-pollution control/fuel conversion construction 

costs as CWIP in rate base. The remaining construction costs, including an allowance for 

funds used during construction (AFUDC) which provides a return on those expenditures, 

generally would have been capitalized and included in rate base only when the plant went 

into commercial operation, i.e., when the plant became used and useful. Allowing some 

portion of the costs in rate base prior to commercial operation provides utilities with 

additional cash flow in the form of an immediate earned return. See 18 CFR 35.25(c)(3). 
Docket No. RM06-4-000 - 61 - 

104. In 2004, the Commission accepted a proposal by American Transmission 

Company (American Transmission) to include 100 percent of CWIP in the calculation of 

transmission rates and to expense pre-commercial operations costs for new transmission 

investment, instead of capitalizing those costs and earning a return.71 American 

Transmission stated that these incentives would help maintain adequate cash flow during 

the construction process and that without these incentives it could face a downgrade of its 

fixed income rating over the next several years due to inadequate cash flow, thereby 

increasing its capital costs by $176 million over a twenty-year horizon. 

105. The Commission stated in the NOPR that allowing public utilities, on a case-bycase basis, to include up to 100 percent of prudently incurred transmission-related CWIP 

in rate base and permitting them to expense prudently incurred pre-commercial 

operations costs will further the goals of section 219 by relieving the pressures on utility 

cash flows associated with their transmission investment programs and providing upfront regulatory certainty. The Commission specifically requested comment on (1) the 

types of costs that should be considered “pre-commercial” operation costs; and (2) 

whether there should be a presumption that these incentives meet the requirements of 

FPA section 219 that investments ensure reliability and reduce the cost of delivered 

power. 

 71 See American Transmission, supra note 2. 
Docket No. RM06-4-000 - 62 - 

b. Comments

106. Most of the commenters,72 support including 100 percent of prudently-incurred 

CWIP in rate base and expensing all pre-commercial operation costs, stating that these 

incentives will encourage transmission investment through improved cash flow, greater 

rate stability and lower rates to future customers. Additionally, SDG&E notes that this 

incentive will balance short-term rates and long-term rates by increasing the rates during 

construction but lowering the rates during operation of a facility. 

107. Opponents, such as the New Mexico AG and California Commission, state that 

maintaining the status quo would be in keeping with the long-standing ratemaking 

doctrine that recovery of utility plant costs should be based on utility plant that is “used 

and useful.” They also oppose expensing pre-commercial costs instead of capitalizing 

such costs because there will be no opportunity for a comprehensive review of project 

costs before those costs are passed on to ratepayers. 

108. Snohomish argues that the Commission must implement a procedure to handle 

refunds where the project is never ultimately completed, and must condition inclusion of 

CWIP and other pre-operation costs in rates on adherence to the construction schedule 

submitted with the application. 

 72 E.g., EEI, American Transmission, AWEA, PG&E, AEP, NSTAR, WPS and 

TDU Systems. 
Docket No. RM06-4-000 - 63 - 

109. In its supplemental comments, EEI recommends the Commission waive the 

requirement that a utility requesting CWIP must provide a forward-looking allocation 

that estimates the average use a wholesale customer will make of the utility system over 

the life of a project, as currently required by 18 CFR 35.25(c)(4). EEI states the purpose 

of the required forward-looking allocation is to protect wholesale customers against a 

double whammy (i.e., being required to pay for the construction of new generation 

facilities if the customer switched supplier). EEI states that the double whammy concern 

is not present with transmission facilities because the customer will almost certainly not 

switch transmission suppliers. 

110. TDU Systems assert that CWIP should not be allowed for projects for which the 

public utility receives upfront interconnection payments, nor for any project for which the 

funds have been provided by a third party, except in tandem with crediting-back of such 

prepayments or investments on a schedule to which the transmission customer agrees. 

TDU Systems assert that if formula rates are in place for the public utility seeking to 

expense the cost of capital assets, inter-generational inequity is even more egregious 

since the public utility may well receive a one-year amortization of that expense although 

future rate payers will benefit from the use of those facilities for years to come. 
Docket No. RM06-4-000 - 64 - 

111. Other commenters state that pre-commercial costs should be defined and the 

Commission should provide guidance.73 Commenters’ proposals for pre-commercial 

costs definitions include all costs associated with pre-construction activities, such as 

planning, related studies, and siting costs, including (1) costs of routing studies for 

placement of transmission lines, (2) costs of certification associated with regulatory 

approvals including legal and consulting costs, (3) costs of public hearings and 

informational hearings, (4) costs for design, planning, drafting, surveying services, 

material procurement and labor in support of project construction, and (5) costs 

associated with development and implementation of interim measures to maintain 

adequate reliability level due to the delayed completion of the proposed project. 

112. Additionally, EEI argues the Commission should also include as pre-commercial 

costs other costs that have been traditionally expensed such as costs of resetting relays, 

using a mobile transformer, making payments to other transmission owners for upgrades 

to their lines, and the write-offs of the undepreciated cost of facilities that are being 

replaced with new transmission investment. 

113. NRECA states that these costs should be limited to prudently incurred direct 

transmission investment costs. TDU Systems states that in no event should the 

 73 E.g., EEI, SCE, AEP, NSTAR, WPS, NU, FirstEnergy, the Nevada Companies, 

KCPL, NRECA and Ameren. 
Docket No. RM06-4-000 - 65 - 

Commission allow public utilities to expense costs associated with transmission facilities 

such as land, towers, transformers, lines, and substations. 

114. PJM recommends that costs of developing a transmission proposal through a 

planning process should be considered a pre-commercial cost. 

c. Commission Determination

115. After considering all the comments, we adopt in this Final Rule the proposal from 

the NOPR to give public utilities, where appropriate, the ability to include 100 percent of 

prudently incurred transmission-related CWIP in rate base and to expense prudently 

incurred “pre-commercial” costs. These rate treatments will further the goals of section 

219 by providing up-front regulatory certainty, rate stability and improved cash flow for 

applicants thereby easing the pressures on their finances caused by transmission 

development programs. As noted by many commenters, these proved effective for 

American Transmission by easing the pressures on American Transmission’s finances 

caused by its transmission development program allowing American Transmission to, 

among other things, stay on schedule with its development program. For American 

Transmission, this also meant a higher credit rating and lower cost of capital, thus 

benefiting customers. Similar results can be expected for other transmission developers 

availing themselves of such opportunities. 

116. We appreciate the concerns, as expressed by the California Commission and 

others, that the proposal is a departure from existing ratemaking doctrine that rates should 

be based on plant that is “used and useful.” However, as times and circumstances 
Docket No. RM06-4-000 - 66 - 

warrant, the Commission has revised its ratemaking policies. In fact in Order No. 298,74

the Commission did just that when it decided to allow any public utility engaged in the 

sale of electric power for resale to file to include in rate base up to 50 percent of CWIP, 

subject to limitations. Thus, the Commission already allows inclusion of some CWIP in 

rate base. The Commission also departed from existing principles in the American 

Transmission and Southern California Edison cases.75 The nation has suffered a decline 

0in transmission investment and it is time that the Commission revisit ratemaking 

policies that may serve as a barrier to investment and revise them accordingly while 

ensuring that customers are protected and rates remain just and reasonable. Finally, we 

note that 100 percent recovery of CWIP costs is already provided for pollution control 

facilities of public utilities.76 

117. Allowing public utilities the opportunity, in appropriate situations, to include 100 

percent of CWIP in the calculation of transmission rates and to expense pre-commercial 

operations costs for new transmission investment (instead of capitalizing these costs and 

earning a return) removes a disincentive to construction of transmission, which can 

 74 Construction Work in Progress for Public Utilities; Inclusion of Costs in Rate 

Base, Order No. 298, FERC Stats. & Regs. ¶ 30,455 (1983), order on reh’g, 25 FERC 

¶ 61,023 (1983). 

75 See American Transmission, supra note 2; Southern California Edison Co., 

112 FERC ¶ 61,014, at P 61, reh’g denied, 113 FERC ¶ 61,143 (2005) (SCE).

76 See 18 CFR 35.25(c)(1). 
Docket No. RM06-4-000 - 67 - 

involve very long lead times and considerable risk to the utility that the project may not 

go forward. The fact that public utilities have the opportunity to recover these costs in 

rates in a different manner than in the past does not mean that the rates are not subject to 

review under FPA sections 205 and 206. Even for rates that are formulaic, it may be 

necessary for the utility to revise the rate formula under section 205 to capture the 

recovery of these types of costs to the extent that they are not provided for in the formula. 

Moreover, as the D.C. Circuit has found, the Commission can depart from the norm as 

long as it reasonably balances consumers’ interest in fair rates against investors' interest 

in "maintaining financial integrity and access to capital markets."77 Finally, if the 

transmission facility never enters service (i.e., is never used or useful), the transmission 

owner may still seek recovery of the expenses associated with the construction work in 

progress (i.e., the return on capital) under our abandoned plant incentive, as discussed 

below. Accordingly, we find that the “used and useful” ratemaking principle is not a 

sufficient basis to deny adoption of the NOPR’s proposal. However, as explained above, 

we will require each applicant to demonstrate that there is a nexus between its request for 

 77 Jersey Central Power & Light Co. v. FERC, 810 F.2d 1168, 1178 (D.C. Cir. 

1987) (Jersey Central). “Although a utility's rate base normally consists only of items 

presently "used and useful" (see New England Power Co. Mun. Rate Comm. v. FERC, 

668 F.2d 1327, 1333 (D.C. Cir. 1981), cert. denied, 457 U.S. 1117 (1982)), a utility may 

include "prudent but canceled investments" in its rate base as long as the Commission 

reasonably balances consumers' interest in fair rates against investors' interest in 

"maintaining financial integrity and access to capital markets." Jersey Central, 810 F.2d 

1168, 1178 (D.C. Cir. 1987). 
Docket No. RM06-4-000 - 68 - 

100 percent CWIP recovery and the investments being made. Ordinarily, such an 

incentive would be appropriate for large new investments or in situations, as occurred 

with ATC, where denying such an incentive would adversely affect the utility's ratings. 

There may be other situations as well where such an incentive is appropriate and we will 

consider each proposal on the basis of the particular facts of the case. 

118. With regard to requests that the Commission condition inclusion of CWIP and preoperation costs on adherence to the construction schedule submitted with the application 

and that we implement a procedure to handle refunds in the event the facility is not put 

into service, we find them to be unnecessary and/or inconsistent with the other measures 

we adopt in this Final Rule. As discussed further below, the Commission is proposing to 

provide a public utility with the opportunity to file for abandoned plant costs. Thus, 

requiring a refund procedure that raises perceived risks of proposing new transmission at 

this time would be inconsistent. We also do not see the need to condition inclusion of 

CWIP on adherence to a construction schedule. Because the actual recovery of CWIP 

will occur either under a rate on file or a rate to be filed under FPA section 205, parties 

will have an opportunity to raise any concerns with regard to actual expenditures vis-avis construction progress at that time. Accordingly, we see no reason to condition 

inclusion of CWIP on adherence to a construction schedule. 

119. The Commission’s current CWIP regulations were developed in an era of bundled 

wholesale services and apply to any rate schedule. Since that time, most wholesale 

transmission service subject to the Commission’s jurisdiction is provided at unbundled 
Docket No. RM06-4-000 - 69 - 

rates under open access transmission tariffs. EEI points out that the requirement for a 

forward looking allocation that estimates the average use a wholesale customer will make 

of the utility system over the life of the project is not necessary with transmission 

facilities. We agree. The forward looking allocation ratio was to prevent a customer that 

was switching power plant suppliers from having to share in the cost of CWIP of a 

particular plant if the customer had no responsibility in the decision of the utility to build 

the plant. We believe it highly unlikely that transmission customers will be faced with 

such an opportunity. Accordingly, because we do not view the “double whammy” to be a 

concern in the transmission context, we grant EEI’s request and waive the requirement in 

18 CFR 35.25(c)(4) as it pertains to preventing double whammy with regard to CWIP 

associated with new investment in transmission.78 Further, we clarify § 35.35(d)(1)(ii) to 

state that other provisions of § 35.25 apply, unless waived by the Commission on a caseby-case basis. We believe that these clarifications to the regulatory text will avoid 

uncertainty expressed by commenters regarding the procedures for obtaining the CWIP 

incentive. 

120. In response to comments, we clarify that pre-payments, i.e., payments prior to the 

start of construction, for project costs by third-parties should not be included in CWIP. If 

 78 However, this waiver does not relieve transmission owners from supplying the 

necessary information required in § 35.25(c) (4) that pertains to CWIP-induced price 

squeeze. The Commission will evaluate CWIP-induced price squeeze concerns on a 

case-by-case basis. 
Docket No. RM06-4-000 - 70 - 

a customer is making contributions in aid of construction, these amounts should not be 

included in rate base. Similarly, in the instance of generator interconnect, the up-front 

amount paid by the customer should not be included in rate base; rather it is included in 

rate base over time as the transmission provider provides credits to the customer. 

121. The Commission has previously determined that recovery of CWIP on a formulary 

basis is not permitted without prior Commission review to ensure that the Commission’s 

CWIP standards are met.79 The Commission in Maine Yankee allowed Maine Yankee to 

propose a method to limit its filing obligation to once a year so that Maine Yankee did 

not have to file each month that it changed the CWIP balances in its monthly formula 

charges.80 Likewise, we will allow public utilities to propose a method to limit their 

filing requirement related to CWIP to an annual filing. These annual filings may be 

limited to CWIP and will not subject public utilities to a comprehensive rate review.81

 79 Maine Yankee Atomic Power Co., 66 FERC ¶ 61,375, at 62,252-53 & n.10 

(1994) (Maine Yankee). 

80 Id., at 62,252. 

81 We deny the request to limit recovery of these incentives to the amount 

originally budgeted. We note that, as a practical matter, it would be difficult to hold 

electric transmission projects to the original budget estimate when it can be 10 to 15 

years between the time the project is proposed and lines are actually built. Also, if public 

utilities are held to recovering only originally estimated budgets, they would either have 

incentives to overestimate costs or to avoid the risky projects which the policy is intended 

to facilitate. 
Docket No. RM06-4-000 - 71 - 

122. With respect to the types of pre-commercial operations costs that we will allow to 

be expensed rather than capitalized, we will allow, on a generic basis, the same types of 

costs that we approved in the American Transmission settlement.82 Further, we will 

entertain proposals by public utilities to expense other types of costs for consideration on 

a case-by-case basis. 

3. Hypothetical Capital Structure

a. Background

123. The Commission stated in the NOPR (at P 29) that it has largely relied on the 

actual capitalization of a utility in setting its rate of return, but recognized that an overly 

rigid approach to evaluating a proposed capital structure could be a disincentive to 

investment in new transmission projects and Transco formation. Each project or 

company may have unique financial and cash flow requirements, and a rigid approach to 

acceptable capital structures could threaten the viability of some projects. Accordingly, 

the Commission proposed allowing applicants to file an overall rate of return based on a 

hypothetical capital structure, and giving them the flexibility to refinance or employ 

different capitalizations as may be needed to maintain the viability of new capacity 

additions. The Commission stated that it expected applicants to develop their proposals 

 82 American Transmission, in its application approved in American Transmission

defined pre-certification costs as preliminary survey and investigation costs in Account 

183. These costs include all expenditures for, preliminary surveys, plans and 

investigations, made for the purpose of determining the feasibility of utility projects and 

costs of studies and analyses mandated by regulatory bodies related to plant in service. 
Docket No. RM06-4-000 - 72 - 

based on the specific requirements and circumstances of their projects, and that the 

Commission would evaluate proposals for this incentive on a case-by-case basis. The 

Commission required public utilities to provide support in their application for why the 

hypothetical capital structure incentive is needed to promote investment consistent with 

the goals of section 219. The Commission required the applicant to provide its 

transmission investment plan and explain the specific projects to which the proposed 

return will apply. 

b. Comments

124. Many commenters support the hypothetical capital structure as an incentive.83 

Both American Transmission and Trans-Elect note that they received approval to use a 

hypothetical capital structure and that they had been able to stay on schedule for 

extensive transmission construction programs. 84 

125. Several parties, including EEI, NSTAR and NU argue in a similar vein that 

hypothetical capital structures can aid investments by companies that are entering a large 

capital expenditure program or are emerging from financial distress and may be aiming 

 83 American Transmission, EEI, First Energy, KCPL, Nevada Companies, 

NSTAR, NU, NYSEG and RGE, PJM, PG&E, Progress, Semantic, Trans-Elect, United 

Illuminating and Xcel support the proposal. 

84 Trans-Elect cites Western, 99 FERC ¶ 61,306 at 62,280, reh’g denied, 

100 FERC ¶ 61,331 at P 7, 9 (stating that rate treatments including hypothetical capital 

structure were necessary for the Path 15 project to be built). See also, METC, 105 FERC 

¶ 61,214 at P 20 (Commission recognized the need to encourage, through regulatory ratemaking policy, the independent business model). 
Docket No. RM06-4-000 - 73 - 

for a capital structure they have not yet realized. Semantic suggests a 75 percent equity 

and 25 percent debt capital structure be used to reflect the higher risks of early adoption 

of advanced technologies. 

126. PJM and NSTAR state that hypothetical capital structures are particularly useful 

for projects involving consortia. PJM cites its proposed consortium approach to building 

transmission, where a capital structure could be based on the project as a whole rather 

than piecemeal based on the individual capital structures of each participant in individual 

rate cases.85 

127. A number of commenters oppose hypothetical capital structures.86 APPA and 

CREPC argue hypothetical capital structures could result in a windfall to public utilities 

by increasing actual return far in excess of the Commission’s allowed return on equity. 

Commenters also express concern that the proposed incentive represents a departure from 

Commission precedent and could result in unjust and unreasonable rates. 

128. Other commenters, such as the Kentucky Commission, Dairyland and MISO 

States, assert that the Commission should preclude a public utility from receiving both 

hypothetical capital structure and the ROE incentive because combining the incentives 

 85 PJM TOs concur that the incentive could be helpful in project-specific rates. 

86 E.g., California Commission, TDU Systems, APPA, CREPC, Steel 

Manufacturers, New Mexico AG, the Oklahoma Commission, PPC, NECOE, 

Connecticut AG, and the Delaware Commission. 
Docket No. RM06-4-000 - 74 - 

could result in adopting a cost of equity well in excess of the DCF range of 

reasonableness. 

129. Because of concerns about the criteria to be used in evaluating proposals for 

hypothetical capital structures, many parties, including CREPC, California Commission, 

NRECA and California Oversight Board, recommend evaluating the proposal on a caseby-case basis, with California Oversight Board arguing for standard of proof much higher 

than merely having to support the proposal as the NOPR proposes. 

130. NECOE states that the Commission should categorically prohibit verticallyintegrated utilities from using a hypothetical capital structure. MISO States argues that 

this incentive is not reasonable, especially if applied to a company’s entire rate base, 

instead of just its new transmission. APPA states that if a specific transmission project is 

financed separately from other projects within a transmission network (e.g., merchant 

transmission line), it may be appropriate to evaluate its capitalization separately from 

other affiliates; however, the evaluation should be based on actual capitalization instead 

of hypothetical capitalization. In contrast, Ameren asserts that hypothetical capital 

structures beyond project-financed investments can be supported and should be 

considered on a case-by-case basis.87 

 87 Ameren states that the Commission has approved the use of a hypothetical 

capital structure to better reflect the risk profile of a regulated enterprise. See High Island 

Offshore Systems, L.L.C., 110 FERC ¶ 61,043, at P 143, order on reh’g, 112 FERC 

¶ 61,050 (2005) (High Island). 
Docket No. RM06-4-000 - 75 - 

c. Commission Determination

131. The Commission finds that hypothetical capital structures can be an effective tool 

available to public utilities to foster transmission investment in appropriate 

circumstances. As some commenters point out, use of a hypothetical capital structure is 

not new. For example, the Commission has allowed independent transmission companies 

to use a hypothetical capital structure to recognize the significant benefits of independent 

ownership and operation of transmission including, among other things, improved access 

to capital markets for transmission investment88 and the Commission has allowed its use 

for specific projects when shown to be necessary for project financing, among other 

things.89 Further, as PJM argues in its comments, hypothetical capital structures may be 

effective for development of consortium projects. This can be especially important for 

projects with a diverse set of sponsors, some of which have different capital structures, 

(e.g., a power marketing agency that contributes access but no equity compared to a 

project sponsor that brings only equity to a proposed investment). We note the rise in 

interest in these types of projects, including such large-scale, multiple-developer projects 

as the Frontier Line and TransWest proposals. Thus, the Commission finds that, in certain 

contexts, this incentive is appropriate for consideration under section 219 because it has 

 88 METC, 105 FERC ¶ 61,214 at P 20. 

89 Western, supra note 2. 
Docket No. RM06-4-000 - 76 - 

been demonstrated to foster the development of transmission investment, as indicated by 

the experience of American Transmission and Trans-Elect. 

132. The Commission continues to believe that an overly rigid approach to evaluating 

proposed capital structures may discourage the development of new transmission 

projects. Therefore, the Commission will evaluate each proposal on a case-by-case basis 

but will not prescribe specific criteria or set target debt/equity ratios for evaluating 

hypothetical capital structures, as requested by some commenters.90 

133. We will not categorically deny the incentive to vertically-integrated utilities, as 

recommended by NECOE. We agree with Ameren that there may be circumstances in 

which a hypothetical capital structure may be appropriate for a transmission investment 

by a vertically-integrated utility. However, we are not suggesting that hypothetical 

capital structures will become the norm. As with the other incentives, we will require 

that the applicant demonstrate a nexus between its proposed incentive and the facts of its 

particular case. 

134. In this regard, we note that many of the instances in which hypothetical capital 

structures are used and can be used reflect unique circumstances, such as a project or 

consortium that requires a special capital structure where the capital structure may change 

significantly with new investments. We disagree with TDU Systems that the 

 90 We note that many commenters support case-by-case review and recognize the 

merits of evaluating the specific circumstances of hypothetical capital structure 

proposals. 
Docket No. RM06-4-000 - 77 - 

Commission has (or should adopt) a general policy on when to use hypothetical capital 

structures. Moreover, we do not believe that the Commission’s recent approvals of 

hypothetical capital structures for electric transmission companies have resulted in 

abnormally high equity ratios or over-compensation for the equity holder at the expense 

of the ratepayer. 

4. Accelerated Depreciation

a. Background

135. In the NOPR (at P 30), the Commission proposed accelerated depreciation as 

another way to increase cash flow to utilities, thereby removing a potential disincentive to 

investing. The Commission has determined that in some circumstances allowing 

accelerated depreciation is warranted to encourage investment in transmission 

infrastructure because it provides improved cash flow and better positions public utilities 

for longer-term transmission investments.91 The Commission stated that permitting 

accelerated depreciation more broadly than just for emergency conditions or special 

projects may further the goals of section 219 by providing incentives to undertake 

transmission projects that have the potential to reduce the cost of delivered power and 

ensure reliability, and, therefore, proposed to allow transmission facilities to be 

 91 See Removing Obstacles and Western, supra note 2. 
Docket No. RM06-4-000 - 78 - 

depreciated over a period of 15 years, in place of the typical Commission practice to 

allow depreciation over the useful life of the facilities. 92 

136. The Commission also sought comment on two issues. The Commission asked 

whether 15 years is an appropriate time period for cost recovery or whether the 

Commission should establish a presumption of a shorter or longer depreciable life for 

new transmission facilities.93 The Commission also requested comment on whether 

accelerated depreciation has any longer-term negative impacts that would undermine the 

goals of section 219. 

b. Comments

137. A number of commenters support the proposal to allow accelerated depreciation of 

15 years for the reasons set forth in the NOPR.94 Some of the supporters, such as the 

Delaware Commission, KCPL, International Transmission, NYSEG and RGE, Progress, 

Siemens, Upper Great Plains, and United Illuminating recommend that the incentive 

should be optional. 

 92 Removing Obstacles, 94 FERC ¶ 61,272, at 61,968-69. 

93 For example, in Removing Obstacles, the Commission permitted a 10-year 

depreciable life for facilities that will increase transmission capacity to relieve existing 

constraints and could be in service within a few months. 

94 E.g., Ameren, EEI, BG&E, FirstEnergy, NSTAR, PG&E, PJM, PJM TOs, SCE 

and WPS. Ameren, MidAmerican and Nevada Companies assert that the Commission 

should be receptive to a shorter depreciable life or that a different life may be appropriate, 

possibly tied to the term of a service agreement. 
Docket No. RM06-4-000 - 79 - 

138. Other commenters oppose the proposal to allow accelerated depreciation of 

transmission facilities. 95 For example, Connecticut AG, NECOE and TANC assert the 

accelerated depreciation incentive will increase costs and rates and result in gold-plating 

and over-building of transmission infrastructure. APPA claims that after new 

transmission facilities have been depreciated over the shorter time period proposed by the 

Commission, the transmission owners will essentially be providing transmission service 

for free. APPA is concerned that when this happens the transmission owners will 

propose to “recalibrate” (i.e., increase) the transmission rate base to depreciate the same 

facilities yet another time at ratepayer expense. 

139. Additionally, TAPS opposes accelerated depreciation because transmitting utilities 

will no longer earn a return on their investments after the facility has been depreciated 

and would potentially seek to recover a management fee which would deny ratepayers of 

the supposed benefits of accelerated depreciation.96 TAPS claims that given the 

likelihood of this management fee, the Commission cannot refer to accelerated 

depreciation as a timing difference. Ameren, on the other hand, states the one drawback 

to accelerated depreciation is that once the asset has been fully depreciated, the public 

 95 E.g., TDU Systems, the California Commission, APPA, the Connecticut AG, 

NY Association, NECOE, TAPS, the New York Commission and TANC. 

96 TAPS cites High Island, 110 FERC ¶ 61,043, at P 105-115. 
Docket No. RM06-4-000 - 80 - 

utility can not earn a return.97 Ameren states the Commission should consider generic 

procedures for the establishment of compensatory management fees for fully depreciated 

transmission assets. 

140. TAPS also argues that accelerated depreciation would skew investments towards 

depreciable plant and away from non-depreciable land even if acquisition of rights-ofway was the cheaper alternative. TAPS states that, if the Commission is intent on 

permitting accelerated depreciation, the Commission should require the utility to auction 

off the fully depreciated facilities at full market value with the proceeds credited to 

ratepayers. 

141. California Commission opposes accelerated depreciation because when a facility 

is placed into service, the value of the undepreciated plant is at its highest; therefore, the 

company earns a high return on the plant. As a result, the company has immediate cash 

flow that does not need to be enhanced. California Commission, TAPS and TDU 

Systems express concern that accelerated depreciation may cause generational inequities 

between those who pay for the facilities now and those who do not have to pay later. 

142. EEI states that this incentive should not be dependent on corporate structure, 

should not be limited to 15 years when it may be appropriate to use a shorter depreciable 

life for certain facilities, and when 15 years is used by a public utility, the company 

should be able to match the tax law depreciation methodology, which weights the tax 

 97 AEP and International Transmission also note this concern. 
Docket No. RM06-4-000 - 81 - 

depreciation more heavily toward the beginning of the life of the project rather than 

spreading it evenly over 15 years. 

143. APPA cites to a number of concerns including the effect of such accelerated 

depreciation on book-tax timing differences, and the associated deferred tax accounts, 

and complications in calculating inter-period income tax allocations. APPA also 

contends that, if the Commission allows rate recovery over a 15 year life for transmission 

assets, then there should be no provision for deferred income taxes allowed with respect 

to such assets in any rate case (and no deduction from rate base), because such book and 

taxable income with respect to such assets would then be matched. 

144. International Transmission asserts that in Order No. 618, the Commission 

correctly determined that the choice of depreciation method should be left to industry.98 

International Transmission argues that flexibility in determining depreciation methods is 

particularly important when new technologies are deployed that may not be proven, may 

cost more or have uncertain useful lives, and may be needed to accommodate ongoing 

industry restructuring or regulatory innovation. 

 98 Depreciation Accounting, Order No. 618, FERC Stats. and Regs. ¶ 31,104, at 

31,694 (2000)(Order No. 618). According to International Transmission, in Order No. 

618, the Commission modified its initial proposal to require straight-line depreciation to 

permit other methods of depreciation that allocated the cost of utility property over its 

useful life in a systematic and rational manner. The Commission recognized that this 

approach would “[allow] flexibility in a changing business environment.” 
Docket No. RM06-4-000 - 82 - 

145. International Transmission states that accelerated depreciation does not increase 

cash flow for companies with formula rates as it would for companies with stated rates, 

because the formula rates reset every year. International Transmission urges the 

Commission to clarify that any changes to depreciation rates for a company using a 

formula rate will be accepted as a ministerial filing with issues limited only to estimation 

of the depreciation life and salvage parameters; and that an added bonus of this approach 

would permit companies with formula rates to remove from their formula rates, in 

ministerial filings, accumulated deferred income tax balances from rate base. 

International Transmission argues that to do so would increase cash coverage ratios and 

the return on equity during the early years of an asset’s life and thereby create a taxrelated incentive that furthers the Congressional intent to encourage transmission 

investment.99 International Transmission states that if it allows companies to use 

accelerated depreciation, the Commission will need to revisit its Accounting Directive in 

Order No. 618, in which the Commission stated that recovery over the useful life 

generally best matches benefits with costs. International Transmission offer that 

accelerated depreciation could lead to the following problems: 1) depreciation would no 

longer be representative of the useful life of assets, 2) the representation of net fixed asset 

value in financial statements could be distorted; 3) there would be a divergence between 

 99 International Transmission notes that Congress reduced the tax depreciable life 

on transmission investments from 20 years to 15 years to encourage transmission 

investment. EPAct 2005, section 1308. 
Docket No. RM06-4-000 - 83 - 

Generally Accepted Accounting Principles and Commission reporting and 4) efforts by 

FASB, the Commission and others to clarify financial reporting could be frustrated. 

c. Commission Determination

146. After considering all comments, we will adopt the NOPR proposal to allow, as an 

option, accelerated depreciation for new transmission facilities that meet the goals of 

section 219. Accelerated depreciation increases the cash flow of public utilities thereby 

providing an incentive to undertake transmission investment. However, we are not 

proposing to grant accelerated depreciation on a generic basis; rather, as with the other 

incentives, the applicant must demonstrate a nexus between its proposal and the facts of 

its particular case (e.g., the need for additional cash flow produced by accelerated 

depreciation in order to fund new transmission investment). 

147. We do not share the commenters’ concerns that this incentive will result in 

intergenerational inequity. Most transmission customers are dependent upon the 

transmission system serving them and are likely to continue to receive transmission 

service over the long-term. Thus, unlike in power supply situations where there are 

greater options to change suppliers, there is little likelihood of intergenerational impact 

through the use of accelerated depreciation for transmission investment. In the event 

accelerated depreciation results in higher rates in the near-term, most of the same 

customers paying the higher rates will benefit from lower transmission rates in the 

longer-term. We clarify that the use of accelerated depreciation may be proposed for new 

transmission facilities including additions to capacity on existing facilities. 
Docket No. RM06-4-000 - 84 - 

148. Given the long-term under-investment in transmission, we disagree with the 

comments of the California Commission that existing policy is sufficient to encourage 

transmission investment in all situations. As the California Commission is aware, TransElect stated that accelerated depreciation was a necessary component for its participation 

in the Path 15 project. In response to the mandate of section 219, we believe it is 

appropriate to offer this rate treatment more broadly to encourage the same successful 

outcome that was achieved with Path 15. This does not mean that accelerated 

depreciation is necessary or will be granted for every project. Instead, the applicant will 

be required to demonstrate that there is a need for the additional cash flow produced by 

the accelerated depreciation or that the incentive is appropriate for other reasons. 

Likewise, at this juncture, concerns expressed by some commenters about the potential 

for overbuilding of transmission facilities as a result of this rate treatment are 

unsupported and highly speculative. 

149. We concur with the comments that suggest the need for flexibility in the length of 

the depreciable life. Therefore, public utilities may propose using accelerated 

depreciation for rate purposes over a period of time as short as 15 years. Moreover, we 

will consider, on a case-by-case basis, depreciable lives of less than 15 years because 

shorter depreciable lives may be appropriate in certain cases, such as advanced 

technologies for which the useful life is not necessarily known. 

150. Based on the comments, we are mindful of the potential consequences of this rate 

treatment when the facilities are fully depreciated. Commenters express concern that the 
Docket No. RM06-4-000 - 85 - 

Commission will allow public utilities to recalibrate the amount of depreciation, or 

institute a management fee. Other commenters state the Commission should require 

certain rules for sale of the facilities because of complications that will arise from selling 

fully depreciated assets. We will not address those issues here but will address such 

issues if and when they occur. 

151. Commenters raise various accounting issues. With respect to the effect of this rate 

treatment on ADIT (accumulated deferred incomes taxes), we disagree that this proposal 

will necessarily require that no provision for deferred incomes taxes be allowed with 

respect to such assets (and no deduction from rate base). As stated previously, we are 

going to be flexible with respect to the depreciable lives of qualifying assets; therefore, 

public utilities may choose 30 years as Trans-Elect did with Path 15 and as a result 

deferred income taxes may still be necessary. Moreover, even if public utilities choose 

15 years, depreciation expense for rate recovery purposes will likely be calculated using 

the straight-line method over those 15 years,100 while accelerated depreciation for tax 

purposes may be calculated using a different method (e.g., double declining balance) over 

15 years. Therefore, despite the use of the same 15 year life, method differences could 

continue to create timing differences for which deferred income taxes would be required. 

 100 The straight-line method is typically used by utilities and will likely continue to 

be used for most utility property. However, consistent with Order No. 618 we will not 

require its universal use, as that may be overly prescriptive. Order No. 618 at 31,694. 
Docket No. RM06-4-000 - 86 - 

152. With respect to APPA’s concern about potential difficulties in applying SFAS 

71,101 the Commission and other rate regulatory authorities often include amounts in 

allowable costs for ratemaking purposes in periods other than the period in which those 

amounts would ordinarily be charged to expense or included in income for financial 

accounting purposes. In those instances, the rate actions of regulators have economic 

consequences that must be recognized in financial statements. Under both SFAS 71 and 

the Commission’s Uniform System of Accounts, if regulation provides reasonable 

assurance that incurred costs will be recovered in future periods, companies must 

capitalize the costs. If current recovery is provided for costs that are expected to be 

incurred in the future, companies must recognize the current receipts as a credit amount 

on the balance sheet. Therefore, because the accounting requirements for accelerated 

depreciation are no different than accounting for the economic consequences of other rate 

actions, we do not see an impediment to implementing accelerated rate recovery of 

transmission assets. 

153. We are not persuaded that we need to revisit Order No. 618 in this proceeding as 

some commenters suggest. In Order No. 618, the Commission established standards for 

determining depreciation expense for book purposes. Here we are establishing a standard 

 101 SFAS 71 applies to general-purpose external financial statements of an 

enterprise that has regulated operations. The Commission’s Uniform System of Accounts 

for Public Utilities and Licensees (18 C.F.R. Part 101) contains provisions similar to 

SFAS 71 that apply to financial statements public utilities must file with the Commission. 
Docket No. RM06-4-000 - 87 - 

for determining depreciation expense allowable for rate purposes. Although accounting 

and cost-based rate setting generally share common standards, there are instances, and 

this is one, where different standards should be used by each discipline and the difference 

bridged by recognition of regulatory assets or liabilities as provided for in our Uniform 

System of Accounts.102 Therefore, companies will continue to depreciate transmission 

assets over their economic service life in a systematic and rational manner for accounting 

purposes and separately recognize as a regulatory liability any difference between 

depreciation expense recognized for accounting purposes and accelerated depreciation 

expense included in the development of rates. In order to clarify this distinction the 

Commission shall revise § 35.35(d)(1)(v) of the regulatory text proposed in the NOPR 

which read “(v) accelerated regulatory book depreciation.” The revised regulatory text 

shall read “(v) accelerated depreciation used for rate recovery.” 

154. We deny International Transmission’s request to alter our section 205 filing 

requirements for public utilities operating under formula rates. In Order No. 618, the 

Commission permitted utilities to not make a filing to change depreciation rates for 

accounting purposes but maintained the filing requirement for changes in depreciation 

rates for rate purposes.103 The Commission said it would monitor changes in depreciation 

rates for accounting purposes when companies filed for rate changes. We decline in this 

 102 18 CFR Part 101. 

103 Order No. 618 at 31,695. 
Docket No. RM06-4-000 - 88 - 

Final Rule to adopt International Transmission’s requested changes to formula rates. 

International Transmission is free to petition the Commission to revise its formula rate to 

allow flexibility going forward, but we decline to make such a generic determination here 

because to do so would presume that all formula rates worked in the same manner. 

5. Recovery of Costs of Abandoned Facilities

a. Background

155. The Commission noted that public utilities, in considering investments that fulfill 

the requirements of FPA section 219, may encounter investment opportunities with 

significant risk associated with factors beyond their control, such as generation 

developers’ decisions to develop or terminate the development of potential resources or 

difficulty obtaining state or local siting approvals. In these circumstances, the 

Commission stated that it may be appropriate to consider ways to reduce the risk 

associated with potential upgrades or other improvements to the transmission system. To 

reduce the uncertainty associated with higher risk projects, thereby facilitating investment 

in these projects, the Commission proposed allowing recovery of 100 percent of the 

prudently incurred costs of transmission facilities that are cancelled or abandoned due to 

factors beyond the control of the public utility. 
Docket No. RM06-4-000 - 89 - 

156. The Commission’s proposal was an extension of a recent Commission decision to 

allow Southern California Edison Company104 to recover all prudently incurred costs 

related to certain proposed transmission facilities if those facilities were later cancelled or 

abandoned.105 The Commission noted that the company’s management did not control 

the decision to develop or cancel the wind farm generation project and that the 

company’s shareholders did not share in the earnings associated with the generation 

project. The Commission further determined that the company might be at a higher risk 

in developing the project because of factors beyond its control. It also noted that SCE 

was not a wind farm developer and therefore would not directly benefit from the 

facilities. Thus, the Commission concluded that SCE should not shoulder the risk of the 

project.106

 104 SCE, 112 FERC ¶ 61,014 at P 58-61, reh’g denied, 113 FERC ¶ 61,143 at 

P 9-15. 

105 Prior to SCE, the Commission’s policy with respect to recovery of cancelled 

plant costs provided that 50 percent of the prudently incurred costs of a cancelled 

generating plant should be amortized as an expense over a period reflecting the life of the 

plant if it had been completed and that the remaining 50 percent of the prudently incurred 

costs of the cancelled plant should be written off as a loss. Under this policy, ratepayers 

are entitled to the income tax deduction associated with that portion of the loss for which 

they are paying. In addition, they are entitled to a rate base reduction to reflect the 

accumulated deferred income tax amounts associated with 50 percent of the abandonment 

loss. See New England Power Co., Opinion No. 295, 42 FERC ¶ 61,016 at 61,068, 

61,081-83, order on reh’g, 43 FERC ¶ 61,285 (1988). See also, Public Service Company 

of New Mexico, 75 FERC ¶ 61,266 at 61,859 (1996) (PSNew Mexico). 

106 SCE. at P 61. 
Docket No. RM06-4-000 - 90 - 

b. Comments

157. A number of commenters support the 100 percent recovery of prudently incurred 

costs of transmission projects that must be abandoned for reasons beyond the 

transmission provider’s control as a way to reduce the up-front risk associated with 

important regional projects.107 Some, like the Kentucky Commission,108 advocate that 

the Commission should adopt a case-by-case approach to recovery of costs related to 

cancelled plant.109 Kentucky Commission agrees that this incentive should be evaluated 

on a case-by-case basis to ensure that the decision to abandon the facility was truly 

beyond the utility’s control. California Commission and CADWR do not oppose the 

recovery of 100 percent of the recovery of prudently incurred costs as long as the 

determination is made on a case-by-case basis. International Transmission states that 

preliminary surveys and investigations should also be included in the costs that can be 

recovered. 

 107 E.g., AWEA, Ameren, AEP, EEI, KCPL, NSTAR, Vectren, International 

Transmission, WPS, APPA, NYSEG-RGE, NorthWestern, National Grid, New York 

Commission, NY Association, Progress, PNM and TNMP, SDG&E, and Upper Great 

Plains. 

108 E.g., California Commission and CADWR. 

109 Trans-Elect supports the case-by-case approach and cites San Diego Gas & 

Elec. Co., 98 FERC ¶ 61,332 at 62,408, reh’g denied, 100 FERC ¶ 61,073 (2002) 

(“claims for full recovery of any infrastructure projects that are ultimately cancelled will 

be addressed by the Commission on a case-specific basis”). 
Docket No. RM06-4-000 - 91 - 

158. SCE supports the recovery of abandoned plant and recommends specific standards 

to facilitate the recovery. SCE states that 100 percent of prudently incurred costs should 

be approved for recovery if the facility was initially proposed and sited through a process 

involving stakeholder input and the subsequent decision to abandon is not under the 

control of management. Additionally, SCE states that utilities should be able to recover 

the costs of abandoned plant even when they have some control over the decision to 

abandon but the project was cancelled or abandoned due to problems in obtaining 

regulatory or other approvals. SCE also supports recovery where economic 

circumstances have changed, causing there to be no demonstrable net benefits. 

159. Others110 oppose the incentive. For example, CREPC states that guaranteeing the 

cost recovery of cancelled plant allows investors to ignore risk and places the risk on 

parties who are unable to manage the risk. ESAI argues that allowing recovery of 100% 

of prudently incurred development costs runs the risk of producing a proliferation of 

white elephants. 

160. TANC argues that the Commission has upheld and enforced its existing cancelled 

plant policy and rejected the utility’s arguments that it be allowed full recovery of the 

cancelled plant because it could not get state regulatory approvals; and that the 

Commission should not adopt a separate policy now. 111 TANC argues the proposal 

 110 E.g., CREPC, the New Mexico AG, Steel Manufacturers and TANC. 

111 TANC cites PSNew Mexico. 
Docket No. RM06-4-000 - 92 - 

violates the intent of Opinion 295-A which is to encourage investors to make efficient 

production and consumption decisions. 

161. Commenters112 offer numerous instances where they believe it would be 

inappropriate to allow a utility to recover abandoned plant costs. For example, the 

Commission should not permit recovery: where the nature of the project was speculative; 

and where the project was abandoned for reasons within the control of the utility; or 

where there is an unexpected turn in the economy. TAPS questions whether project 

abandonment is really beyond a utility’s control if a state siting authority does not 

outright reject a proposal but instead conditions its acceptance in a way that the utility 

finds objectionable. 

162. Snohomish asserts applicants must make showings of why the project failed and 

recoverable costs should be limited to the original budget. New Mexico AG, TDU 

Systems and TAPS assert that if utilities are guaranteed their investment in abandoned 

facilities they need a lower ROE to represent the reduced risk of recovery. 

c. Commission Determination

163. We find that an applicant may request 100 percent of prudently-incurred costs 

associated with abandoned transmission projects can be included in transmission rates if 

such abandonment is outside the control of management. This incentive will be an 

 112 E.g., Industrial Consumers, Oklahoma Commission, PPC, MISO States, and 

TAPS. 
Docket No. RM06-4-000 - 93 - 

effective means to encourage transmission development by reducing the risk of nonrecovery of costs. 

164. Many commenters request that we evaluate proposals on a case-by-case basis and 

we affirm that we intend to do so. The case-by-case approach and the limitation to 

prudently-incurred costs should adequately discipline investment decisions. However, 

we will not prescribe specific rules to govern our evaluation but offer limited guidance 

below. 

165. We agree with many commenters that when local, state and federal (as applicable) 

siting authorities reject an application outright, we would view those circumstances, 

generally, as abandonment beyond the control of management. As TAPS points out, the 

situation is less clear when siting authorities do not reject the application outright but add 

conditions to the application that make it uneconomical or otherwise objectionable. In 

these instances we would expect the utility to file with the Commission and support the 

decision to abandon. The Commission will evaluate, in these instances, the change in 

circumstances from those originally planned on a case-by-case basis. 

166. We see no need to specify unique application procedures for this incentive. We 

will require a section 205 filing for recovery of abandoned plant costs in rates at the time 

the project is abandoned. We disagree with CREPC that this incentive shifts risk from 

those who can manage the risk to those who cannot because this incentive is limited by 

definition to abandonment that is beyond the control of the utility. We will not by rule 

limit the recovery of costs associated with abandoned plant to the costs included in the 
Docket No. RM06-4-000 - 94 - 

original budget estimate. The Commission will evaluate the public utility’s cost recovery 

to ensure no double recovery of costs. For example, if a utility already recovered survey 

costs by expensing these costs as a pre-commercial cost, it would be unjust and 

unreasonable for the utility to recover those costs again if the facility was subsequently 

abandoned.113

167. We will not mandate a reduction in ROE for utilities that receive approval for this 

rate treatment. As stated in the ROE incentive discussion, determinations of a just and 

reasonable ROE include risk evaluations made in individual rate proceedings and are 

based on the facts pertinent to the utility and its proxy group. We note, however, that a 

utility that receives approval to recover abandoned plant in rate base would likely face 

lower risk and thus may warrant a lower ROE than would otherwise be the case without 

this assurance.114 This does not mean that the Commission would reject an incentivebased ROE for a project that also receives assurance of abandoned plant costs that are 

beyond the utility's control. We would consider any such request on a case-by-case basis. 

The risk of a failed project is only one criteria that would be evaluated in determining 

whether an incentive-based ROE would be appropriate in a given case. 

 113 We also clarify that we maintain the timing of recovery as set forth in Opinion 

No. 295 which required recovery over the life of the asset as if it had gone into service. 

114 SCE, supra note 104. 
Docket No. RM06-4-000 - 95 - 

6. Deferred Cost Recovery

a. Background

168. In the NOPR, the Commission stated that public utilities with a retail rate 

moratorium may have less incentive to build transmission facilities that could reduce 

congestion or ensure reliability because of concerns about cost recovery for those 

facilities. Accordingly, the NOPR proposed to permit such utilities to use a deferred cost 

recovery mechanism which allows them to commence recovery of new facility costs in 

FERC-jurisdictional rates at the end of a retail rate moratorium. By providing a 

mechanism to facilitate cost recovery by public utilities that build transmission facilities 

during a retail rate moratorium, the Commission believed that it would meet the goals of 

section 219 by providing certainty to investors that costs can be recovered as quickly as 

possible.115 

b. Comments

169. Many commenters support the deferred recovery proposal.116 International 

Transmission states that deferred cost recovery should be used to facilitate the divestiture 

of transmission assets to Transcos. Of those that support the proposal, several urge 

 115 The Commission has approved a deferred cost recovery provision that allowed 

for the recovery of the cost of new facilities upon the end of a retail rate moratorium. See

Trans Elect, Inc., 98 FERC ¶ 61,142, reh’g denied, 98 FERC ¶ 61,368 (2002). 

116 In addition to commenters mentioned below, AEP, Ameren, KCPL, National 

Grid, Nevada Companies, NSTAR, NYSEG and RGE, and Upper Great Plains also 

support the proposal. 
Docket No. RM06-4-000 - 96 - 

cooperation between federal and state regulatory authorities. 117 In particular, NSTAR 

and AEP urge the FERC to collaborate with states and regional state committees to 

develop solutions for full and timely cost recovery and/or be prepared to intervene in 

state and court proceedings to the extent state regulators attempt to trap wholesale costs 

and prevent recovery of those costs in retail rates. EEI urges the Commission to ensure 

that the necessary regulatory mechanisms are in place to allow cost recovery and should 

cooperate with the states to develop these recovery mechanisms including transmission 

cost recovery tracker mechanisms.118 In EEI’s supplemental comments, EEI states that 

any utility that constructs new transmission facilities should automatically be entitled to 

deferred cost recovery. 

170. Trans-Elect argues that the Commission should allow recovery of all costs 

approved for deferred recovery for Michigan Electric Transmission Company (METC)119

and International Transmission.120 

171. TAPS agrees that deferred cost recovery is reasonable in the case cited in the 

NOPR in which all connected retail customers pay the same rates and see the same 

deferral. However, TAPS asserts that allowing utilities with stated rates based on old test 

 117 E.g., PJM TOs, NSTAR, EEI, and AEP. 

118 NU and PEPCO support EEI’s comments. 

119 See Michigan Electric Transmission Company, 107 FERC ¶ 61,206 at P12 

(2004). 

120 See ITC Holdings, 102 FERC ¶ 61,182 at P 74. 
Docket No. RM06-4-000 - 97 - 

years to defer the collection of additional revenues associated with costs related to new 

facilities would constitute an unreasonable double-dip and would be inconsistent with 

section 219(d). Moreover, because the rates of bundled retail customers are set elsewhere 

based on different test years, this double-dip would be paid only by wholesale customers 

and unbundled retail customers and would be unreasonable and unduly discriminatory. 

172. Several commenters opposing deferred cost recovery cite to concerns about the 

effect on state regulation.121 Some argue that the proposal may undermine or impinge on 

areas exclusively under state jurisdiction (Pennsylvania Commission cites 16 U.S.C. 824 

(a)(b)). Others allege that the unrestricted ability of a public utility to defer cost recovery 

until the end of the rate moratorium may not be consistent with the spirit of settlements 

struck as part of rate freezes.122 Pennsylvania Commission adds that all the rate caps in 

its state are time-limited and any incremental benefit from a federal incentive would be 

more than offset by the legal uncertainty that would be attached to such incentives and 

the eventual federal/state conflict that would ensue. 

173. MISO States argues that the Commission would do better to work with state 

authorities on retail rate recovery issues (e.g., ensure rate recovery at wholesale and 

 121 E.g., Kentucky Commission, MISO States, Pennsylvania Commission, and 

Wyoming Advocate. 

122 Similarly, New Mexico AG, California Commission, PPC and Steel 

Manufacturers oppose the deferred cost recovery proposal because of the potential effect 

on state regulation. 
Docket No. RM06-4-000 - 98 - 

retail) than to adopt a policy unilaterally.123 MISO States comments that Commission 

statements and accusations that state-statutory retail rate reviews undermine incentive 

ratemaking at the federal level are unwarranted. If the Commission proceeds with its 

proposed incentive of allowing deferred cost recovery, the Commission should consider 

granting deference to objections from state-level officials, according to MISO States. 

174. Other commenters124 seek assurance that the Commission will ensure the company 

does not over-recover its actual costs; offer that the Commission should adopt a case-bycase approach to allowing deferred cost recovery until the end of a moratorium and 

requiring agreement by wholesale and retail customers as to the nature, amount and 

duration over which the costs are to be deferred and synchronization of wholesale and 

retail ratemaking practices to avoid regulatory price squeeze;125 and, argue that the 

Commission should place limits on the amount that can be deferred, and initial deferral 

period and subsequent recovery period. 

 123 Steel Manufacturers contends that the Commission should instead work 

cooperatively with states on transmission planning matters, particularly in regional 

forums, in order to reduce possible areas for dispute, cost recovery gaps, or duplicative 

cost recovery. 

124 E.g., Municipal Commenters, and APPA. 

125 APPA notes that new transmission facility costs that would be eligible for 

inclusion as CWIP in rate base should similarly be eligible for deferred cost recovery to 

address mismatches in cost recovery created by retail rate freezes. 
Docket No. RM06-4-000 - 99 - 

c. Commission Determination

175. We find that permitting public utilities under retail rate freezes to defer recovery 

of new transmission investment costs undertaken consistent with section 219 will help 

facilitate investment. Increased certainty of cost recovery of new transmission 

investment will encourage development of more transmission infrastructure thereby 

fulfilling the goals of section 219 of the FPA. 

176. To date, the Commission has approved deferred cost recovery mechanisms during 

the formation of Transcos which permitted the new Transcos to defer recovery of other 

costs such as the ADIT adjustment associated with the acquisition of the transmission 

system and to defer recovery of the rate differential between the frozen rates and the rate 

it would have received. As discussed more fully below, we believe that Transcos offer 

significant benefits and the deferred cost recovery mechanisms that we approved for 

METC and International Transmission were helpful to establish those Transcos. We also 

believe that deferred cost recovery mechanisms should be available to all public utilities, 

not just Transcos and recognize the importance of ensuring that federal and state 

ratemaking policies align so that we not only reduce regulatory lag but facilitate 

transmission development. 

177. Most of the comments opposing this proposal cite potential conflicts with state 

regulation to be a critical issue. We believe that deferred cost recovery mechanisms 

generally will not hinder retail ratemaking. However, if a situation arises where a state 

regulator believes that a federal deferred cost mechanism conflicts with a state goal or 
Docket No. RM06-4-000 - 100 - 

undermines a state settlement with the applicant, we will consider objections by state 

regulators on a case-by-case basis, and seek to avoid inconsistencies between state and 

federal regulation. In this regard, we note that the approval by the Commission of 

regional state committees provides one vehicle for discussing Federal and state 

ratemaking issues on a cooperative and regional basis. With respect to TAPS’ concern 

that the cost of the incentive would be recovered from only wholesale customers and 

unbundled retail customers, the Commission may approve a rate design such that 

wholesale customers and unbundled retail customers pick up only a proportionate share 

of the costs of the incentive. 

178. With respect to commenters’ specific proposals for trackers, limits, and deferral 

periods, we decline to adopt such proposals here. The justness and reasonableness of any 

deferred cost recovery proposal will be considered as part of the section 205 filing and 

there is no basis to arbitrarily place limits on recovery through this rule. The intent of the 

deferred recovery mechanism is to increase the certainty of cost recovery to encourage 

more transmission investment. It may also facilitate the creation of Transcos in states 

where retail rate freezes are in place. The deferred recovery mechanism is an option 

available for any public utility to propose; a public utility may also propose the use of a 

regulatory asset, as suggested by APPA.126 We believe that a public utility must propose 

 126 Regardless of whether it proposes to use a regulatory asset, the public utility 

should explain its proposed accounting for the deferred recovery mechanism. 
Docket No. RM06-4-000 - 101 - 

a set of incentives that is tailored to the facts of its particular case and the Commission 

must review those proposals to ensure they are just and reasonable. 

7. Other Incentives - Single-Issue Ratemaking 

a. Background

179. In the NOPR (at 54), the Commission recognized that transmission pricing issues 

are some of the most difficult issues facing the industry and that the Commission’s policy 

of not allowing selective adjustments to a cost-of-service may serve as a disincentive to 

transmission investment.127 Certain applicants may consider the time requirements and 

the uncertainties associated with rate proceedings that encompass their entire 

transmission systems to be disincentives to making incentive filings, as specified in the 

NOPR. To ensure that the approval process for incentive treatment is as streamlined as 

possible, thereby ensuring timely infrastructure investments, the Commission stated it 

was willing to consider incentive filings, applicable to both Transcos and traditional 

public utilities, that propose rates applicable only to the new transmission project.128 

 127 See, e.g., City of Westerville, Ohio v. Columbus Southern Power Co., 

111 FERC ¶ 61,307 at P 18 & n.11 (2005). 

128 The NOPR cited Removing Obstacles as an example of one type of approach 

utilizing a limited section 205 filing. 
Docket No. RM06-4-000 - 102 - 

b. Comments

180. Numerous commenters129 support single issue ratemaking for the reasons set forth 

in the NOPR. Additionally, Ameren states that single-issue ratemaking can be useful in 

obtaining advance approvals of specific rate treatments that may be required by investors 

as a condition to financing new construction.130 Moreover, Kentucky Commission states 

that as long as single issue rate cases relate only to new transmission and comply with the 

filing requirements set forth elsewhere in the NOPR, it does not object to this proposal. 

181. FirstEnergy states this proceeding is analogous to the Removing Obstacles orders 

where, in order to facilitate development of transmission investment the Commission 

permitted limited section 205 rate applications. FirstEnergy states that in this proceeding, 

Congress has realized there is a pressing need for transmission investment and the 

Commission should permit limited section 205 rate applications to facilitate the needed 

development. FirstEnergy asserts single issue ratemaking is particularly important for 

companies using formula rates. 

182. AEP states that the Commission should be flexible with ratemaking conventions 

and that single-issue ratemaking could be a powerful incentive to encourage more 

transmission investment. AEP also states that single-issue ratemaking along with 

 129 E.g., Ameren, EEI, PJM, Trans-Elect, FirstEnergy, NorthWestern, 

MidAmerican, Nevada Companies, AEP, KCP&L, Semantic and Xcel. 

130 See, e.g., Western, supra note 2 (issuing advance approvals of certain rate 

treatments for proposed California transmission Path 15 upgrades). 
Docket No. RM06-4-000 - 103 - 

transmission cost trackers at the state level would be productive measures especially with 

integrated utilities. 

183. TDU Systems notes that where the Commission has accepted single issue 

ratemaking, the Commission required the implementation of a mechanism that would 

harmonize the rate increase from that surcharge with adjustments to rates for existing 

facilities to reflect the offsetting decreases in depreciation costs associated with those 

existing facilities. EEI agrees that it is important to establish a crediting mechanism in 

some cases to harmonize the rate treatment for new and existing transmission facilities.131 

PJM, Progress, TAPS and TDU Systems state that Schedule 12 of the PJM tariff provides 

an example of how concerns with single issue ratemaking can be addressed to implement 

a $/KW/month adder to network or point-to-point transmission rates.132 

184. TAPS proposes an alternative approach in which the Commission could 

harmonize the existing rates and new facility rates, when the inputs to the existing rate 

are known (i.e., not hidden in a “black box” settlement), by updating the load divisor and 

depreciation reserve, and all other rate components would remain the same (other than 

the new facility charge). Where the existing rate was black box, a load divisor and 

 131 EEI cites Allegheny Power, 111 FERC ¶ 61,308 at P 54; see also Request for 

Rehearing of the PJM Transmission Owners, Docket No. ER05-513-001, filed on June 

30, 2005. 

132 PJM and TAPS also cite Allegheny Power (accepting cost recovery provisions 

of Schedule 12). 
Docket No. RM06-4-000 - 104 - 

depreciation reserve would have to be imputed for these purposes by assuming that the 

difference between the filed-for and settled rate represented an adjustment to the rate 

divisor and depreciation reserve. 

185. Additionally, if the Commission proceeds with single issue ratemaking, APPA, 

TAPS and SCE suggest having the public utility file a full rate case at some point in the 

future which would roll-in the existing rate and the separate surcharge for the new 

transmission investment. APPA and TAPS recommend a full rate case after three years 

while SCE does not state a specific deadline for a full rate case. 

186. APPA, NASUCA and TDU Systems oppose single issue ratemaking for 

transmission service claiming that public utilities are likely earning returns on their 

existing transmission facilities in excess of previously allowed rates of return (due to load 

growth, continuing depreciation of existing transmission facilities, and stale rates). They 

argue that single issue ratemaking fails to determine if the entire transmission rate is just 

and reasonable. APPA states that to allow a rate increase for a new facility to be added to 

the transmission rates charged for existing facilities improperly mixes costs from 

different periods for the same functional class of facilities. In addition, NASUCA and 

TDU Systems state that single issue ratemaking violates section 205 because one rate 

determinant may often be accompanied by an associated decrease in other portions of the 

rate and failure to consider all rate components together can lead to overstatements that 
Docket No. RM06-4-000 - 105 - 

produce unjust and unreasonable rates.133 Further, NASUCA states that waivers of the 

general rule for a full blown rate case are found only in limited circumstances, for 

example where the utility is merely an accounting conduit for rate changes made by 

another utility from which the first utility purchases services.134

187. Municipal Commenters oppose single issue ratemaking because it represents a 

departure from cost-of-service ratemaking in that it fails to demonstrate any nexus 

between the awarding of proposed incentives and the owner’s overall cost of service, 

need, financing cost, capital structure or performance.

188. TAPS suggests an alternative approach of having companies file their incentive 

rate proposals, individually tailored to that utility where appropriate, but generally 

applicable to that utility’s qualifying transmission investments. Subsequent facilityspecific filings, as necessary, would merely apply the existing approved plan. With this 

approach, single issue ratemaking is unnecessary according to TAPS. 

189. In the event that the Commission decides to proceed with allowing single issue 

ratemaking for new transmission investment projects, commenters have suggested 

 133 NASUCA cites Arkansas Power & Light Co. v. Missouri Public Service 

Commission, 829 F.2d 1444, 1451-52 (8th Cir. 1987) (A state may determine whether the 

company has experienced savings in other areas which might offset the increased price 

resulting from the pass-through of the increased wholesale rate). 

134 NASUCA cites Panhandle Eastern Pipe Line. v. FERC, 613 F. 2d 1120, 1127 

(D.C. Cir. 1979). 
Docket No. RM06-4-000 - 106 - 

methodologies for implementing single issue ratemaking and ways to mitigate any 

potential problems with it. 

190. EEI explains that public utilities should be permitted to file with the Commission 

to establish a revenue requirement to recover the costs of constructing a specific new 

transmission facility pursuant to section 205. Under this approach, the transmission 

owner determines whether to establish a new ROE or use its current Commissionapproved ROE. 

c. Commission Determination

191. We believe that single-issue ratemaking can provide a significant incentive for 

achieving the infrastructure investment goals of section 219 because it can provide 

assurance that the decision to construct new infrastructure is evaluated on the basis of the 

risks and returns of that decision, rather than the additional uncertainty associated with 

re-opening the applicant's entire base rates to review and litigation. We agree with 

FirstEnergy that there is a pressing need for transmission investment and therefore the 

Commission should allow for limited section 205 filings as a way to facilitate needed 

development, as was approved for the Path 15 project. The Commission’s approval of 

limited section 205 procedures in Removing Obstacles showed how useful and 

appropriate single-issue ratemaking can be for needed investment in existing facilities, as 

Trans-Elect attests in their comments. 

192. We will not require harmonization of rates, roll-in of new and existing rates or 

reopening of existing rates in this rule, as recommended by some commenters. Nor will 
Docket No. RM06-4-000 - 107 - 

we specify in this rule the rate calculations associated with developing a transmission rate 

for a particular new facility. Our concern in this rule is to ensure new investments are not 

impeded because of existing-system rate issues. Accordingly, applicants filing for singleissue ratemaking for a particular project are only required to address cost and rate issues 

associated with the new investment in the section 205 proceeding to approve rates. 

However, the applicant will be required to fully develop and support any transmission 

rate designed to recover the costs of a particular transmission system facility or upgrade – 

including cost allocation and rate design. The Commission will consider the potential 

need to combine or reconcile the new rate with any existing transmission rate when an 

applicant submits a request for incentives. In some instances, the Commission may find 

that single-issue ratemaking is appropriate without any determination as to when that rate 

will be harmonized with existing rates; in other cases, the Commission may, if 

appropriate, adopt certain of the mechanisms suggested by the commenters, such as a 

requirement to file a full rate case at a date certain in the future. In each instance, the 

Commission will balance the need for new infrastructure, and the importance of 

permitting single issue ratemaking in support of that infrastructure, with the concerns 

over whether a specific mechanism is required to re-open existing rates or whether the 

traditional complaint processes are sufficient for that purpose. 

193. We find the claims of some commenters that public utilities are currently earning 

excessive returns on their existing rates to be speculative. We have no basis to conclude 

earned returns are excessive since these commenters have not submitted section 206 
Docket No. RM06-4-000 - 108 - 

filings alleging such excessive returns nor do they provide evidence in their pleadings 

identifying the companies that are realizing excessive returns. 

C. Incentives Available to Transcos

1. Definition of Transco

a. Background

194. The NOPR (at P 37) proposed to define a Transco as a stand-alone transmission 

company, approved by the Commission, which sells transmission service at wholesale 

and/or on an unbundled retail basis, regardless of whether it is affiliated with another 

public utility. The Commission invited comments on this proposed definition of 

Transcos. 

b. Comments

195. AEP and PEPCO support the proposed definition because it allows a Transco to be 

affiliated with another public utility. AEP states that eligible entities should include 

integrated utility companies or their affiliates, and PEPCO that the definition of a Transco 

should allow for ownership by a single affiliate. 

196. Other commenters support a definition that includes affiliated Transcos, but only 

those with passive ownership. Commenters differed on the level and nature of 

independence requirements, if any, that should apply to affiliated Transcos. PJM TOs, 

for example, argued only for the same governance requirements otherwise applicable to 

Transcos. TAPS, on the other hand, advocates more specific definitions of affiliated 

Transcos that would need to meet all of the standards of the Policy Statement Regarding 
Docket No. RM06-4-000 - 109 - 

Evaluation of Independent Ownership and Operation of Transmission (Policy Statement 

Regarding Evaluation of Independent Ownership).135 Several commenters, including 

APPA and ITC, argue for the benefits of independence. Vectren opposes the proposed 

definition of Transco in the NOPR because by permitting inclusion of transmission 

owners with affiliates that own generation and/or distribution, it allows a Transco to be 

substantially identical to a vertically-integrated utility. Vectren questions whether the 

Commission’s policy initiatives would have more impact on an FPA jurisdictional 

Transco with generation and distribution affiliates than on a traditional integrated 

transmission owner due to the Transco’s parent company’s common equity ownership of 

transmission and distribution as well as its role in making critical Transco business 

decisions. Vectren also argues that holding companies with Transcos will utilize shared 

service companies to fulfill common managerial and administrative functions for 

Transcos and affiliates. 

197. Commenters differed on whether the level of affiliate ownership should bear on 

the definition of a Transco. For example, Ameren states that utilities exhibiting 

comparable levels of independence (and benefits) should be entitled to similar rate 

treatments, regardless of organizational structure. Ameren focuses on the level of 

functional separation and operational independence of the Transco – and not the 

 135 111 FERC ¶ 61,473 (2005). 
Docket No. RM06-4-000 - 110 - 

percentage of passive equity ownership. Semantic requests that the Commission define 

the maximum permitted traditional utility ownership allowed in a Transco. 

198. Some commenters, including TransCanada and American Transmission, advocate 

flexibility regarding ownership in the proposed definition. NSTAR, National Grid, and 

OMS contend that the Commission’s proposed definition of Transco is overly restrictive 

in applying only to companies that are solely transmission providers. They argue that 

transmission and distribution companies that have taken significant steps toward 

independence by divesting of generation and marketing activities be similarly rewarded. 

199. Due to concerns about competition for capital within Transcos, TDU Systems 

states only Transcos with strict limits on investments in other industries should receive 

incentive rates. APPA states that Transcos must have access to sources of equity capital 

other than their affiliates, such as through issuance of new equity or through capital 

contributions from a diverse base of Load Serving Entity owners. 

200. Semantic states that the definition of Transco should be broadened to include 

entities that deliver services using advanced transmission technologies recognized in 

section 1223(a) of EPAct 2005, such that a Transco need not directly participate in the 

flow of energy. A Transco could be an “Advanced Technology Transco” that delivers 

enhanced grid state data processed by analytical software. 

c. Commission Determination

201. We will adopt in the Final Rule the definition from the NOPR that a Transco is a 

stand-alone transmission company that has been approved by the Commission and that 
Docket No. RM06-4-000 - 111 - 

sells transmission services at wholesale and/or on an unbundled retail basis, regardless of 

whether it is affiliated with another public utility. This definition includes the flexibility 

advocated by some commenters and allows the Commission to consider various business 

models and arrangements. 

202. The definition we adopt here does not exclude affiliated Transcos with active 

ownership by market participants, or stand-alone transmission companies that own 

transmission and distribution facilities. However, we expect applicants to demonstrate 

the value of their particular affiliated Transco proposal. We will consider the eligibility 

of such arrangements based on a showing of how the specific characteristics of a 

proposed Transco affect its ability and propensity to increase transmission investment 

and lead to increased transmission investment similar to the Transcos we have already 

approved. We note that the three Transcos established thus far – which have all 

demonstrated their willingness and ability to invest in new transmission – are either not 

affiliated with any market participant (e.g., International Transmission and METC) or 

have joint ownership and board membership by a number of market participants and 

independent members (e.g., American Transmission). Concerns regarding affiliated 

Transcos, such as those voiced by Vectren, or support for companies that own 

transmission and distribution or other business structures, will be considered in the 

context of specific applications for incentive treatment. 

203. In addition, because we do not wish to preclude entities that may help foster 

investment in needed transmission infrastructure simply because they have not yet been 
Docket No. RM06-4-000 - 112 - 

proposed or evaluated, we will not establish specific limits on Transcos regarding, for 

example, business investments in other industries, sources of equity, or levels of active 

and passive ownership. 

204. We also clarify that an entity’s status as a Transco will not be conditioned on 

membership in an ISO or RTO. As the Commission explained in the NOPR, just as the 

need for investment is a national need, we believe that the expansion and investment 

objectives of new FPA section 219 are best met by a definition of Transcos that does not 

restrict the formation of Transcos to only certain organized markets. Similarly, we 

clarify that an applicant that receives an incentive related to its status as a Transco may 

also request and be eligible for other generally applicable incentives discussed in the 

Final Rule, such as those for joining an RTO or ISO. The Commission will consider the 

suitability of multiple incentives at the time of an application. 

205. We will not create a new Transco category that includes entities that do not own 

transmission facilities, as requested by Semantic. Consistent with section 219 the Final 

Rule applies to rate treatments for transmission of electric energy in interstate commerce 

by public utilities. To the extent Semantic meets this requirement, it may file an 

application for incentive treatment and the Commission will then make its determination 

of whether the Semantic proposal meets the requirements of section 219. 
Docket No. RM06-4-000 - 113 - 

2. Transco ROE Incentive

a. ROE Incentive

i. Background

206. As part of the encouragement of Transco formation, the Commission stated that it 

will permit suitably structured Transcos to receive an ROE that both encourages Transco 

formation and is sufficient to attract investment. For example, the Commission approved 

equity returns for METC and International Transmission that reflect the significant 

benefits that their status as Transcos provide, and these returns are higher than those 

approved for integrated entities. Continuing to allow a higher ROE (that falls within a 

zone of reasonableness) in recognition of the benefits Transcos provide is an appropriate 

way to ensure the achievement of section 219’s objectives. Therefore, the Commission 

stated that it will consider the positive impact Transcos have on transmission investment 

and in turn on the reliable or economically efficient transmission and generation of 

electricity when it evaluates ROEs proposed by properly structured Transcos. (NOPR at 

P 40, footnote omitted) 

ii. Comments

207. Several commenters,136 oppose the Commission’s proposal to grant an ROE 

 136 E.g., APPA, Community Power Alliance, Municipal Commenters, NASUCA, 

NECPUC, New Mexico AG, NRECA, NU, Pennsylvania Commission, Snohomish, and 

TANC. 
Docket No. RM06-4-000 - 114 - 

incentive to Transcos outright. Other commenters137 oppose giving Transcos an incentive 

that is not available to other business models. 

208. Those opposing the outright grant of ROE incentives to Transcos138 contend, 

among other things, that: there should be no equity incentive adders without direct 

demonstration of customer benefits; such incentives would unfairly divert capital to 

Transcos; and that enhanced Transco ROEs do nothing to solve the problem of building 

needed transmission. 

209. Commenters opposing139 treatment based on corporate form or business model 

suggest that the Commission focus on the purpose and effect of the proposed 

investments, not the type of entity that proposes them. They argue that there is a lack of 

evidence of how Transcos encourage transmission infrastructure expansion and the track 

record for Transcos is incomplete. 

210. Other commenters raise concerns about the signals the Commission is sending 

regarding RTOs and independence of operations, planning and expansion that can be 

ensured through other types of regional transmission groups or through traditional 

 137 E.g., AEP, BG&E, EEI, First Energy, KCPL, MidAmerican and PacifiCorp, 

Midwest ISO, NECPUC, Northwestern, PEPCO, PJM, PJM TOs, PPC, Progress Energy, 

SCE, Southern Companies, and Vectren. 

138 E.g., Municipal Commenters, NECPUC, Progress Energy, Snohomish, PPC. 

139 E.g., APPA, Community Power Alliance, FirstEnergy, Pennsylvania 

Commission and NASUCA. 
Docket No. RM06-4-000 - 115 - 

utilities, particularly those in a RTO with a regional planning process.140 EEI, for 

example, opposes the Commission managing business models and argues the 

Commission should not (even unintentionally) give the impression through incentives 

that it seeks to restructure the transmission sector. 

211. Other commenters offer suggestions as to how to distinguish incentives. For 

example, NU and PJM suggest targeting incentives at companies that are investing in 

transmission and/or involved in regional planning, regardless of corporate structure. PJM 

suggests the Commission proceed on a case-by-case basis. 

212. Finally, commenters argue that higher ROEs for only some transmission owners 

are discriminatory and not just and reasonable, and have no basis in section 219. 

Alternatively, some suggest that Transcos have lower risk than integrated companies and 

should receive lower ROEs. Others argue that incentives should cover only new 

investments and behavior,141 not existing infrastructure. For example, California 

Commission opposes providing higher ROEs to Transcos, arguing that Transco and 

traditional integrated utility shareholders bear the same (and only significant) risk as 

transmission project owners - during the initial stage of project permitting and 

developing. SCE offers that Transco-specific ROEs might actually provide a disincentive 

 140 E.g., American Wind, Mid American, PacifiCorp, and EEI. 

141 E.g., New Mexico AG, NRECA, Pennsylvania Commission, PG&E, Vectren, 

Southern Companies, California Commission, SCE, and TANC. 
Docket No. RM06-4-000 - 116 - 

for future Commission-jurisdictional transmission investments by traditional utilities if 

they can earn higher ROEs on state-jurisdictional facilities. TANC offers that a for-profit 

Transco has no incentive to make, and, in fact, is discouraged from making, economically 

efficient and/or energy efficient investments. Dairyland points out that American 

Transmission’s plans for substantial investment were made in the context of a settlement 

agreement in which American Transmission agreed to a lower ROE than that approved 

for Midwest ISO transmission owners and that the settlement improved American 

Transmission’s cash flow and reduced its risk, providing a sufficient financial package to 

enable its investments even with the lower ROE. Dairyland states that American 

Transmission shows that substantial investment by Transcos is likely to occur even if 

ROEs are reduced. 

213. Some commenters take issue with the representations in the NOPR regarding state 

and federal jurisdiction.142 For example, Community Power Alliance opposes rewarding 

changes in ownership structure resulting in transfer of jurisdiction from state to federal 

regulators. PEPCO believes the NOPR suggests that traditional utilities may be treated 

less well by federal regulators merely because they are subject to state as well as federal 

jurisdiction. New Mexico AG states Transco incentives are nothing more than an attempt 

by the Commission to override state regulatory jurisdiction. Nevada Companies state 

 142 E.g., Community Power Alliance, PEPCO, NSTAR, and PJM TOs. 
Docket No. RM06-4-000 - 117 - 

that the Commission must work with state regulatory authorities to foster Transco 

formation. 

214. TDU Systems opposes incentive rates for new investment by Transcos after those 

Transcos form. If any such award is granted, TDU Systems argues it be done only upon 

demonstration of need, and apply only to system expansions, not existing facilities. 

215. Other commenters,143 generally support incentive-based ROEs to encourage 

Transco formation. For example, International Transmission supports incentives for 

Transco formation and investment not merely to reward a particular transmission 

ownership structure but to encourage a type of transmission ownership that has produced 

the results that Congress sought when it enacted section 219. International Transmission 

states that both its own specific experience and the track record of Transcos generally 

illustrate the benefits of Transco ownership of transmission.144 International Transmission 

 143 E.g., International Transmission, KKR, Nevada Companies, TDU Systems, 

Trans-Elect and Upper Great Plains. 

144 International Transmission states that in the last decade of Detroit Edison’s 

ownership of the facilities now owned by International Transmission, Detroit Edison 

invested about $10 million a year in those transmission facilities that International 

Transmission states it invested $41 million on in 2003; $82 million on in 2004; and over 

$118 million on in 2005. At the end of 2005, the net asset value of International 

Transmission’s facilities has nearly doubled while its CWIP balance remained roughly 

flat. International Transmission states that this substantially increased investment is 

producing benefits for consumers in enhanced reliability and increased access to 

competitively priced generation. International Transmission states that in the latest 

Midwest ISO Transmission System Expansion Plan, the three transcos in the Midwest 

ISO account for 54 percent of the approximately $2.9 billion in projected investment 

through 2009. Comparing the level of projected investment across transcos and non-

(continued) 
Docket No. RM06-4-000 - 118 - 

states that if other forms of transmission ownership invest in transmission in a manner 

comparable to Transcos, those other entities should be eligible for equal incentives, but 

that until they do, Transco-specific incentives are fully appropriate. 

216. KKR offers the following potential investment advantages of Transcos: 

elimination of competition for capital between generation and transmission functions; a 

singular focus on transmission investment which allows more rapid and precise response 

to market signals indicating when and where transmission investment is needed; a lack of 

incentive to maintain congestion in order to protect generation market share; and an 

enhanced ability to manage assets and access to capital markets. As stand-alone entities 

lacking incentive to favor a particular market participant’s generation, Transcos are likely 

to attract a variety of new generators, including solar and wind renewable generation. 

217. KKR states that enhanced ROE can both drive capital investment and support 

Transco formation. An enhanced ROE in excess of that sufficient to support new 

investment will be factored into the purchase price of the Transco assets or company and 

be delivered in whole or in part to the seller. 

218. Additional comments in support of higher ROEs for Transcos,145 note that Transco 

formation and investment will occur when actual Transco returns are equal to or greater 

 

transcos, the average transco in the Midwest ISO is investing at over seven times the rate 

of the average non-transco in the Midwest ISO. 

145 E.g., Nevada Companies and Trans-Elect. 
Docket No. RM06-4-000 - 119 - 

than returns for investments with comparable risk and that these returns must be earned 

on a consistent basis. 

219. Trans-Elect offers suggestions on the manner in which the incentive could be tied 

specifically (and exclusively) to the acquired facilities. In addition, Trans-Elect states 

that whatever methodology is used to develop a range of equity cost estimates, use of the 

mid-point (or average) of that range would be contrary to the notion of stimulating new 

transmission investment. Particularly in the context of the inherently higher-risk Transco 

business model, Trans-Elect supports ROEs toward (or at) the high end of the range. 

220. Upper Great Plains supports Transco incentives but argues they be limited to what 

is necessary to put Transcos on an equal footing with other transmission developers. 

According to Upper Great Plains, leveling the playing field will encourage Transcos to 

more fully develop the advantages made possible by their business structure. 

iii. Commission Determination

221. After considering all the comments, we adopt in this Final Rule the proposal from 

the NOPR to provide to Transcos a ROE that both encourages Transco formation and is 

sufficient to attract investment after the Transco is formed. The incentive ROE does not 

preclude a Transco from applying for any other incentive adopted in this rule, including 

hypothetical capital structures, ADIT, acquisition premiums, formula rates or deferred 

cost recovery. We note that such additional incentives could aid the formation of 

Transcos as well as bolster their ability to add transmission infrastructure. We note, in 

addition, that application of the ROE incentive or applicable other incentives will likely 
Docket No. RM06-4-000 - 120 - 

be more efficiently translated into rates for those applicants that operate under or 

concurrently propose formula rates. 

222. This decision is based on the proven and encouraging track record of Transco 

investment in transmission infrastructure. For example, International Transmission states 

that its investment was more than ten times higher in 2005 than the annual investment by 

DTE during the last decade of DTE’s ownership of the same transmission system.146 

Trans-Elect states that it expended $112 million in capital on its system from May 2002 

through 2005.147 Since January 1, 2001, American Transmission states that it has 

invested approximately $1 billion in strengthening its system, essentially tripling its 

investment in transmission infrastructure in five years. 

223. The expansion plans of existing Transcos are also encouraging. International 

Transmission notes that in the latest Midwest ISO Transmission System Expansion Plan, 

the three Transcos in the Midwest ISO account for 54 percent of the Plan’s approximately 

$2.9 billion in projected investment through 2009. It also states that comparing the level 

of projected investment across Transcos and non-Transcos, the average Transco in the 

Midwest ISO is investing at a rate that is over seven times that of the average nonTransco in the Midwest ISO.148

 146 International Transmission comments at 21. 

147 METC comments at 3. 

148 International Transmission Reply Comments at 6. 
Docket No. RM06-4-000 - 121 - 

224. As stated in the NOPR, the Commission believes that this positive record of 

Transco investment in transmission facilities is related to the stand-alone nature of these 

entities. 149 In particular, we agree with the comments submitted by KKR explaining the 

benefits of the Transco model. By eliminating competition for capital between 

generation and transmission functions and thereby maintaining a singular focus on 

transmission investment, the Transco model responds more rapidly and precisely to 

market signals indicating when and where transmission investment is needed. We agree 

that Transcos have no incentive to maintain congestion in order to protect their owned 

generation. Moreover, Transcos’ for-profit nature, combined with a transmission-only 

business model, enhances asset management and access to capital markets and provides 

greater incentives to develop innovative services. By virtue of their stand-alone nature, 

Transcos also provide non-discriminatory access to all grid users. 

225. Numerous commenters state that the Commission should not favor one corporate 

structure (i.e., Transcos) over another. We agree in part. In the context of the goal to 

increase investment in needed transmission infrastructure, it is inappropriate to favor one 

corporate structure over another to the extent both business structures have similar 

transmission investment records. To date, however, no other business structure has a 

transmission investment record similar to that of a Transco and therefore our incentives 

that focus on Transcos are justified. While this rule provides incentives for all public 

 149 NOPR at P 39. 
Docket No. RM06-4-000 - 122 - 

utilities, the additional incentives for Transcos, in light of their superior record of adding 

infrastructure, are neither unduly discriminatory nor contrary to the goals of section 219. 

226. We believe an incentive ROE for Transcos is justified because Transcos are 

spending their additional return on capital spending, as demonstrated by the negative cash 

flow profiles of the current Transcos and their future capital spending plans, as discussed 

in the comments of the Transcos and KKR. Though Transcos have demonstrated that 

they will build transmission, and plan to build more in the future, we agree with 

commenters that state that our focus should be on actual results—i.e., getting 

transmission built. Currently, Transcos are spending capital aggressively, reinvesting any 

earned returns and spending a significant amount more than they are earning. However, 

continuing to allow a Transco, over the long-term, to receive an incentive ROE for all its 

facilities that recognizes its increased transmission investment only makes sense if the 

Transco continues to provide the benefits which we are trying to incentive. Therefore, as 

discussed earlier, we encourage Transco applicants to submit proposals to measure 

performance and thereby justify continuation of ROEs (as well as other rate treatments) 

that were provided for the purpose of attracting and sustaining transmission investments. 

227. We disagree with AWEA’s statement that single-system Transcos do nothing for 

regional goals. Even a single-system Transco can build infrastructure that significantly 

aids a broad region. Moreover, to the extent Transcos belong to transmission 

organizations, their expansion plans must be approved by transmission organizations and 

therefore they support regional planning goals. 
Docket No. RM06-4-000 - 123 - 

228. We disagree with Municipal Commenters’ contention that the Transco incentive is 

misguided as transmission prices have increased dramatically in regions where the 

transmission systems were spun off from investor owned utilities. We have no evidence 

that Transcos have increased prices, nor did Municipal Commenters provide supporting 

evidence. Nor do we agree Transco formation would simply increase earnings without 

any direct demonstration of customer benefits from such formation. The amount of 

infrastructure likely to be added by Transcos will directly benefit customers in the region. 

Responding to the Pennsylvania Commission, we have no basis to conclude Transcos 

may introduce undesirable biases in grid investment and operations. Furthermore, like 

any public utility, their rates remain subject to review to ensure justness and 

reasonableness. We therefore have no basis to change our conclusion that Transcos are 

appropriate structures for investment in infrastructure and accomplishment of the 

objectives of section 219. 

229. In response to concerns of commenters such as NRECA and the California 

Commission that the incentive return for Transcos is not based on a risk evaluation of 

Transcos, we believe those concerns are premature. Such an evaluation is more 

appropriately part of the section 205 process in individual rate applications of assessing 

representative proxy companies and the impact of other factors, including risk. 

230. We expect that providing for deferred cost recovery for Transcos, such as has been 

approved for Trans-Elect and International Transmission, will address Nevada 
Docket No. RM06-4-000 - 124 - 

Companies’ concern that state-level rate freezes could preclude recovery of costs 

associated with divesting transmission assets to Transcos. 

231. We believe PEPCO and the New Mexico AG have misinterpreted our statements 

in the NOPR regarding benefits of federal jurisdiction for Transcos. The NOPR does not 

state that a state’s jurisdiction over some of the activities and assets of traditional utilities 

hinders investment, as PEPCO maintains. Rather, the NOPR indicated that Transcos 

would benefit from having incentive approvals determined in a single jurisdiction, by 

eliminating delay and uncertainty. The purpose of our policy of incentives for Transcos 

is to build much needed transmission infrastructure. States continue to have jurisdiction 

over the siting of new transmission infrastructure and many of the high voltage interstate 

projects will require extraordinary cooperation and collaboration between state and 

Federal regulators. 

b. Transco Level of Independence 

i. Background

232. The Commission proposed to clarify and broaden the definition of Transcos to be 

stand-alone transmission companies approved by the Commission, without a condition of 

membership in a RTO or ISO, and requested comment on how to factor the level of 

independence into any request for ROE-based incentives for Transcos. The Commission 

sought comment on whether it should specify additional incentive levels within the zone 

of reasonableness to correspond to certain levels of independence and if so, what those 

amounts should be. The Commission also sought comments concerning whether 
Docket No. RM06-4-000 - 125 - 

membership in an RTO or ISO should be considered in setting incentive-based ROEs 

approved by the Commission for a Transco.150 

ii. Comments

233. Numerous commenters151 generally support tying the level of incentives to the 

level of independence of the Transco. For example, Ameren proposes a tiered approach 

to ROE incentives, with Transcos that are members of an RTO or ISO entitled to the 

highest ROE incentive. International Transmission states that it is appropriate to award 

the highest ROE-based incentives to Transcos that are truly independent. KKR states that 

Transcos that have achieved total structural independence should receive the most 

generous set of incentives. MISO States state that the level of Transco independence is 

an important consideration and, accordingly, the Commission could apply a graduated 

ROE incentive depending upon the degree of independence between the Transco and 

market participants, affiliates or generation. 

234. National Grid states that the Commission should establish the level of ROE-based 

incentives based on a sliding scale keyed to various levels of independence for all forms 

of Transmission Organizations, with one end of the sliding scale being “total structural 

independence,” which would be entitled to full incentives. 

 150 NOPR at P 42. 

151 E.g., Ameren, AWEA, Connecticut DPUC, International Transmission, KKR, 

MISO States, and National Grid. 
Docket No. RM06-4-000 - 126 - 

235. Trans-Elect states that only entities that establish independence as to operation, 

planning, construction and investment decisions should qualify for ROE-based incentives 

for Transcos. Rather than recognizing a “range” or “levels” of independence that would 

justify “additional incentive levels,” the Commission should confirm that entities that 

meet the definition of Transco would qualify for the full ROE-based incentive, while 

those that do not would not be eligible for the incentive. According to Trans-Elect, it is 

critical that Transco ownership arrangements that reflect truly passive ownership qualify 

for the full ROE-based incentive and that the independence standard should be deemed 

satisfied when passive ownership is structured to ensure that the Transco will “operate 

free of market participant control or influence.” 

236. TDU Systems supports a policy to prevent a Transco with passive ownership 

interests from earning Transco incentives. TDU Systems assert that should the 

Commission authorize passive ownership interests by market participants in Transcos, 

those relationships should be rigorously scrutinized. Passive ownership interests by 

market participants in Transcos should only be authorized upon a showing that the option 

of investment in the Transco is open to all LSEs in the region up to their load ratio shares, 

according to TDU Systems, with governance based on equal and/or equally-weighted 

votes, if any, for all passive owners. TDU Systems recommend that the Commission 

commit to monitor these relationships in order to deter the potential for abuse. 

237. Some commenters also address whether membership in an RTO or ISO should be 

considered in setting incentive-based ROEs approved by the Commission for a Transco. 
Docket No. RM06-4-000 - 127 - 

For example, PEPCO states that the Commission should not provide additional incentive 

levels for certain levels of Transco “independence” unless it also provides the same 

incentive levels for participants in other models, such as RTOs. MISO States and PJM 

believe that the Commission should reverse its proposed policy of not taking into account 

if the Transco is a member of an RTO and instead recognize the positive benefits of 

Transco membership in RTOs. AWEA states that incentives for regionalizing the grid 

through RTO participation should be an additional incentive. 

238. Others, such as APPA, NRECA, and PG&E support the Commission’s proposal 

that membership in an RTO or ISO should not be a factor in setting incentive-based 

ROEs for Transcos. WPS states that the proposed incentive for Transcos may be 

appropriate, but also could be duplicative if the Transco is an RTO member and also 

receives an incentive for that membership. 

iii. Commission Determination

239. We will not establish a specific methodology to factor the level of independence 

into any request for ROE-based incentives for Transcos. We will also not specify 

additional incentive levels that remain within the zone of reasonableness, to correspond 

to certain levels of independence. While not quantifying a precise formula or method, we 

will consider the level of independence of a Transco as part of our analysis when we 

determine the proper ROE for the Transco, and evaluate the specific attributes of a 

particular proposal, including the level of independence, to determine appropriate 

incentives. 
Docket No. RM06-4-000 - 128 - 

240. Though we are not establishing a range of incentives based on independence, we 

note that the three existing Transcos, which have significantly increased their 

transmission investment post-formation, are either totally independent of market 

participants or can meet the independence standards in the Policy Statement Regarding 

Evaluation of Independent Ownership. Independence is an important component of the 

positive contribution of Transcos on investment in needed transmission infrastructure. A 

Transco with active ownership by a market participant or other new business 

arrangements is also eligible for Transco incentives to the extent it can show, for 

example, why active ownership by an affiliate does not affect the integrity of its 

investment planning, capital formation, and investment processes or how its business 

structure provides support for transmission investments in a way similar to the structure 

of non-affiliated Transcos or Transcos with only passive ownership by market 

participants. 

241. In addition, while a Transco need not be a member of an RTO, ISO, or other 

Transmission Organization, we will also consider such membership as part of our 

evaluation process on the level of Transco incentives that might be appropriate. We also 

note that a Transco is eligible for incentives if it is a member in an RTO, ISO, or other 

Transmission Organization. 

3. Accumulated Deferred Income Taxes (ADIT) 

a. Background

242. To remove any disincentives that might prevent the sale or purchase of 
Docket No. RM06-4-000 - 129 - 

transmission assets to form Transcos, such as capital gains taxes on sales of assets,152 the 

Commission (NOPR at P 43) proposed to include in the rates of Transcos an adjustment 

to recover ADIT. This incentive would provide the assurance of recovery in rate base of 

adjustments for taxes associated with asset sales, thereby reducing uncertainty. 

b. Comments

243. Several Commenters153 submitted comments that generally support the 

Commission continuing to consider proposals to include adjustments for ADIT in rates 

when a Transco is purchasing transmission facilities. For example, Trans-Elect states 

that continuing to allow adjustments for ADIT will eliminate this tax-related disincentive 

and, in the process, demonstrate to potential sellers, purchasers and the investment 

community the Commission’s commitment to promoting independent stand-alone 

transmission businesses. National Grid states that allowing recovery of ADIT is designed 

to ensure that there is no financial or tax penalty associated with undertaking the 

transactions necessary to form Transcos and therefore the Commission should allow such 

recovery to eliminate an obstacle to Transco formation. OMS states that allowing the 

ADIT cost recovery adjustment appears more reasonable than simply authorizing filings 

 152 See, e.g., International Transmission Co., 92 FERC ¶ 61,276 at 61,915-16 

(2000) (explaining potential disincentives to sellers and buyers of transmission assets if 

the ADIT adjustment is not granted). 

153 E.g., International Transmission, KKR, National Grid, NorthWestern, OMS, 

PJM TOs, TAPS, and Trans-Elect. 
Docket No. RM06-4-000 - 130 - 

to recover acquisition premiums because the ADIT adjustment premium would be 

specifically quantifiable and tied to a specified purpose. International Transmission and 

Trans-Elect also specifically support the Commission’s clarification that a stand-alone 

transmission company that requests an incentive ROE would not be precluded from also 

requesting the ADIT adjustment. 

244. Some commenters raise specific concerns regarding how an ADIT adjustment will 

be calculated. TAPS states that after the seller is held harmless for its book-based gainon-sale tax consequences (if any) any remaining tax balance should flow back to 

ratepayers. TDU Systems state that the ADIT adjustment should be reduced by the 

seller’s ADIT and investment tax credits associated with the transferred property. APPA 

is concerned about the difficulty a buyer of facilities will have in correctly calculating the 

ADIT, which is based on the seller’s capital gains tax liability. NRECA states that the 

Commission needs to create sufficient safeguards to prevent double recovery. TAPS and 

APPA also cite the American Jobs Creation Act of 2004 as substantially mitigating, and 

potentially eliminating the ADIT concern. 

245. APPA, PPC and Snohomish state that, in order to get the ADIT adjustment, buyers 

of transmission facilities should need to demonstrate concomitant customer benefits to 

offset increased transmission rates resulting from measures to recover capital gains taxrelated acquisition premiums. 

246. PPC and Snohomish state that allowing recovery of ADIT goes beyond the stated 

goal of promoting investment in new transmission capacity, and. instead would promote 
Docket No. RM06-4-000 - 131 - 

the sale of existing transmission assets. They contend that allowing purchasers to 

amortize ADIT in rates will increase ratepayer costs and allow Transcos to benefit from 

the time-value of money without offsetting any actual expenditure. The value of ADIT 

should be passed through to customers only if the Transco is actually making tax 

payments, and then only in an amount equal to those payments. 

c. Commission Determination

247. We find that it is appropriate for the Commission to continue to consider proposals 

to make an adjustment to the book value of transmission assets being sold to a Transco to 

remove the disincentive associated with the impact of accelerated depreciation on federal 

capital gains tax liabilities. This adjustment is simply intended to remove a disincentive 

to Transco formation. As explained in the NOPR, transmission owners are unlikely to 

sell transmission assets at book value if they are not held harmless from capital gains 

taxes on such sales by including an adjustment for taxes associated with those sales. 

Buyers of transmission assets may be unwilling to pay such an adjustment without some 

assurance of recovery of the adjustment in their rate base, as the Commission has 

addressed in previous Transco-related orders. In addition, we find appropriate the 

clarification proposed in the NOPR that a Transco requesting an incentive ROE not be 

precluded from also requesting the ADIT adjustment. 

248. While the Commission will continue to consider proposals to include adjustments 

for ADIT in rates when a Transco is purchasing transmission facilities, we emphasize that 

we will review such proposals on a case-by-case basis to ensure that the ADIT 
Docket No. RM06-4-000 - 132 - 

adjustment is just and reasonable and not unduly discriminatory or preferential under the 

particular circumstances of the proposal.154 Specific concerns about how the ADIT 

adjustment is calculated, such as those raised by TAPS, TDU Systems, APPA and 

NRECA, can be raised when a proposal is filed with the Commission. In addition, 

TAPS’ and APPA’s concern that the American Jobs Creation Act of 2004 may eliminate 

the need for an ADIT adjustment can be raised as an issue concerning an applicant’s 

proposed ADIT adjustment in a specific proceeding. We note that, as there is no sunset 

date for the incentives, applications could be made after the potential tax benefits of the 

American Jobs Creation Act have lapsed, as the tax law only affects transactions that 

close by January 1, 2007. 

249. We will not require, as requested by APPA, PPC and Snohomish, that our 

approval of any ADIT adjustment be conditioned on an analysis of costs and benefits 

related to such an adjustment, as discussed elsewhere in this Rule. We disagree with the 

implication of PPC that the Transco purchaser is receiving the benefit for ADIT costs that 

it is not really paying. ADIT is part of the purchase price of the transmission assets sold 

to the Transco, and hence represents actual costs to the purchaser. 

250. However, as described more fully in the Performance Test section, we clarify that 

continuation of the ADIT adjustment, like continuation of other incentives, is conditional 

 154 As discussed elsewhere in the Final Rule, an applicant may propose a number 

of incentives. Thus, a stand-alone transmission company is not precluded from 

requesting ROE and ADIT. 
Docket No. RM06-4-000 - 133 - 

on the applicant achieving benchmarks for its own proposed Commission-approved 

metrics. 

4. Acquisition Premiums for Transco Formation

a. Background

251. The NOPR (at P 55) requested comments on whether the Commission should 

make a generic determination that general benefits would accrue to ratepayers as a result 

of Transco formation. It also sought comment on whether any change in the acquisition 

premium/ratepayer benefits review at the federal level would risk increased resistance to 

such acquisitions at the state level. The NOPR sought comment on whether there are 

other mechanisms that the Commission could institute to provide regulatory certainty of 

the recovery of the acquisition premium both through retail as well as wholesale rates. It 

also sought comment on what measure the Commission might use in evaluating the 

appropriateness of such premiums as measured against, for example, the size of the 

premium, the location of the assets, the level of independence of the Transco, and other 

relevant factors. 

b. Comments

252. Several Commenters155 support a generic Commission determination that Transco 

formation benefits consumers and that fair value paid for transmission assets by a 

Transco will be recoverable, even if that fair value exceeds the book value of those assets 

 155 E.g., International Transmission, KKR, and Trans-Elect. 
Docket No. RM06-4-000 - 134 - 

by a significant amount. Trans-Elect argues for a case-by-case consideration, i.e., that a 

Transco should be entitled to make a showing that the benefits of a particular transaction 

justify allowing a specific acquisition adjustment and that the level of proposed 

adjustment is appropriate. KKR supports allowing a Transco Applicant to recover an 

acquisition premium in rates for all or a portion of any premium paid above net book 

value for purchases of transmission facilities. PNM encourages the Commission to 

eliminate its historical prohibition against recovery of acquisition adjustments for 

transmission assets. 

253. Several commenters156 oppose a generic determination regarding the allowance of 

acquisition premiums for Transcos, and generally support the continuation of current 

Commission policy which, according to commenters, is case-by-case. They also oppose 

the Commission making a general determination that Transco formation results in general 

benefits to customers for purposes of determining whether to allow recovery of an 

acquisition premium in rates. 

254. In response to our request for comment on what measure to use to evaluate the 

appropriateness of such premiums, Pennsylvania Commission states that if the 

Commission determines that approval of acquisition adjustments is necessary to 

encourage acquisition and mergers of transmission systems in a business-neutral way, the 

 156 E.g., Ameren, APPA, MISO States, Northwestern, NRECA, Pennsylvania 

Commission, PEPCO, PJM TOs, Snohomish, TDU Systems, and WPS. 
Docket No. RM06-4-000 - 135 - 

Commission should require applicant(s) to demonstrate that such costs were both 

reasonable and negotiated at arms’ length. According to the Pennsylvania Commission, 

the applicant should be required to offer proof that the purchase price of assets had a 

reasonable relationship to the market valuation of the assets transferred, that the buyer 

and seller were financially separate and unrelated, and that directors and officers of, and 

advisors to, the buyer and seller had a financial and legal “arm’s-length” relationship 

before and after consummation of the acquisition. International Transmission suggests 

that recovery of the difference between book value and fair value, as represented in a 

proposed purchase price, be limited to no more than 50 percent of any amount paid above 

the book value of the assets, in order to provide market discipline with respect to the 

purchase price of the assets. Snohomish states that there must be a means to 

independently verify the purchase price, such as requiring submission of two or more 

independent appraisals. 

255. Dairyland supports limiting acquisition adjustments to situations where the seller 

of the facilities to a Transco does not have (or does not simultaneously obtain) an 

ownership in the Transco. AEP, PJM TOs and SCE state that if the Commission allows 

recovery of acquisition premiums, it should allow all business models to recover them, 

including traditional investor-owned utilities. 

256. TAPS and TDU systems argue that entities allowed to recover acquisition 

premium for the formation of Transcos should not also be authorized to receive an 

enhanced ROE. 
Docket No. RM06-4-000 - 136 - 

257. Nevada Companies state that the Commission must work with state regulatory 

authorities to foster Transco formation since transmission owners’ incentives are reduced 

if they must give a large portion of an acquisition premium back to customers. 

c. Commission Determination

258. We will not in this Final Rule change the Commission’s policy of allowing 

acquisition adjustments in rates only upon a specific showing of ratepayer benefit.157 

However, given the positive contributions of Transcos on transmission investment 

discussed above, we find that a Transco may propose an acquisition premium as an 

incentive under the Final Rule, as provided under § 35.35 (d)(1)(viii). We will continue 

to evaluate proposals made by Transcos to recover acquisition premiums associated with 

the purchase of transmission facilities on a case-by-case basis. We appreciate the 

comments on how the Commission should evaluate the level of acquisition premiums, 

such as those from Pennsylvania Commission, International Transmission, and 

Snohomish, and we will take such factors into account in evaluating whether to allow 

recovery of particular acquisition premiums. While this discussion is limited to 

providing an incentive for Transco formation, entities other than Transcos can apply for 

 157 While the proposed ADIT incentive discussed above would adjust book value 

and therefore may be considered a premium on net book value, we note that unlike the 

acquisition premium discussed here, the proposed ADIT incentive addresses tax-related 

issues outside of the applicant’s control. 
Docket No. RM06-4-000 - 137 - 

the incentive and the Commission will evaluate those applications on a case-by-case 

basis. 

5. Merchant Transmission

a. Comments

259. LIPA states that because of the NOPR’s focus on cost-of-service ratemaking, it 

has less impact on merchant transmission developers, whose rates are defined by contract 

(and thus market benefit), and not by Commission cost-of-service ratemaking standards. 

Merchant transmission developers are generally required to rely on market rates for 

transmission service negotiated directly with purchasers of their capacity, and to assume 

(along with the purchasers of their capacity) all of the market risk for their facilities. 

Merchant transmission developers will base their decisions on other factors, particularly 

their ability to efficiently attain the market benefits that their investments create. 

260. TransCanada believes that a two-tier subscription process would provide merchant 

developers with some initial regulatory and business certainty by addressing the initial 

up-front siting and permitting risk (because of the ability to secure meaningful 

commitments from the first tier subscribers). It would also allow for a full open season 

for the remainder of the capacity (the second tier) consistent with current Commission 

policy. 

261. National Grid states that the key issues raised in this rulemaking (ensuring 

adequate returns on equity for investment and independence, facilitating timely and 
Docket No. RM06-4-000 - 138 - 

complete cost recovery, etc.) are regulated rate issues, which should be of no concern to 

merchant transmission developers. 

b. Commission Determination

262. With respect to comments on merchant transmission, we agree with comments that 

this issue is beyond the scope of this Final Rule. Merchant projects are market driven 

while this final rule deals fundamentally with regulated transmission rates. True 

merchant transmission projects may play an important role in the future of transmission 

infrastructure development, but incentives related to, for example, ROE and cost 

recovery, do not apply to merchant transmission. 

D. Performance-Based Ratemaking

1. General Comments

a. Background

263. In the NOPR, the Commission sought comments on ways performance-based 

ratemaking (PBR) might apply to for-profit Transcos and traditional public utilities, and 

not-for-profit Transcos and public utility ISOs and RTOs. In the case of for-profit 

entities, the Commission sought comment on whether there should be mechanisms for 

sharing gains with ratepayers and, if so, what those mechanisms should be. In the case of 

not-for-profit public utility ISOs and RTOs, the Commission sought comment on whether 

and how PBR developed for for-profit entities might be applied to not-for-profit entities. 

Finally, the Commission sought comment on whether performance-based benchmarks for 
Docket No. RM06-4-000 - 139 - 

transmission costs would provide incentives for the deployment of advanced 

technologies.158

b. Comments 

264. Commenters generally support the concept of PBR, especially as it was defined in 

the Commission’s 1992 Policy Statement on Incentive Regulation and in Order No. 2000, 

which emphasize that PBR should be voluntary, have both an upside and downside, that 

gains should be shared with ratepayers, that benefits should be quantifiable, and that costs 

to consumers under PBR should not exceed what they would have been under traditional 

regulation. They urge the Commission to retain these principles.159 

265. However, citing to current market structure, most commenters expressed a general 

lack of enthusiasm for PBR, and none held out any expectation that PBR would have a 

significant role to play in providing consumer benefits. Chief among the obstacles cited 

to implementing PBR is a difficulty in determining appropriate performance measures or 

benchmarks. For example, KCP&L emphasized that experts, such as EPRI, are 

researching appropriate performance measures but have not yet determined how to 

account for various factors such as system age and configuration, geography and 

customer density, a point of view shared by many.160 Moreover, APPA cautions that 

 158 NOPR at P 58. 

159 E.g., NASUCA, TDU Systems, Missouri Commission, and SMUD. 

160 E.g., Comments of KCPL, SCE, and EEI. 
Docket No. RM06-4-000 - 140 - 

poorly designed performance measures could lead to unintended and undesirable 

consequences, and it recommends that the Commission conduct a series of technical 

conferences and workshops on PBR before considering any implementation. The 

Kentucky Commission states that performance-based benchmarks for transmission costs 

are not necessary because any technology that is beneficial will have an economic 

reward, thereby providing its own incentive. The transmission tariff should reflect 

prudent operation and maintenance so that, if there is improvement, a greater profit will 

be realized. For proven technologies, a sharing of both benefits and the risks would be 

appropriate for deployment of new technologies. Thus, many conclude that the value of 

PBR seems remote, although voluntary programs could be worth considering. 

266. Some commenters oppose PBR because they believe it could deter investment in 

transmission facilities, contrary to the main objective of the proposed rulemaking. For 

example, International Transmission concludes that PBR might play a limited role in 

some circumstances, but warns that some PBR approaches, such as price cap regulation, 

could actually discourage investment. Others, such as FirstEnergy and Nevada 

Companies are concerned that PBR could increase risk and, thus, reduce investment. 

Some commenters believe that PBR might have a limited role in inducing utilities to 

adopt certain innovative practices and advanced technologies,161 while other commenters 

 161 E.g., Comments of AEP and UTC Power. 
Docket No. RM06-4-000 - 141 - 

were more concerned that PBR would discourage reliability and provide unwarranted 

benefits to utilities.162 

267. Few commenters see any realistic role for PBR as a means of inducing cost saving 

behavior on the part of non-profit entities, although some, such as Ameren, believe that 

the Commission’s oversight is inadequate. Industrial Consumers, in particular, express 

the view that PBR has no role to play in the non-profit area and, furthermore, that PBR 

should not be applied to the profit area unless a proven model would make pricing under 

PBR as transparent as pricing under conventional ratemaking. Some commenters163

stress that safeguards already exist to insure that ISOs/RTOs are efficient and 

accountable, and they argue that there is no urgency to adopt PBR for RTOs/ISOs. 

Although they could consider PBR on a limited, case-by-case basis, PJM TOs also 

emphasize that RTOs with regional planning processes and requirements outside the 

transmission owners’ control are poor candidates for PBR. 

268. Among those commenting most favorably on implementing some form of PBR 

were Progress Energy, Southern Company, and National Grid. Although they see limited 

immediate applicability of PBR, both Progress Energy and Southern Company 

recommend specific types of PBR – Progress Energy favors loop flow pricing, and 

Southern Company favors revenue or rate caps that would reward utilities for increasing 

 162 E.g., Comments of NSTAR and the New Mexico AG. 

163 E.g., NYISO, CAISO, PJM TOs and NECOE. 
Docket No. RM06-4-000 - 142 - 

throughput. In contrast, National Grid emphasizes that it has had success with PBR 

mechanisms different from those mentioned in the NOPR outside the U.S. However, 

until the U.S. industry is more independent and there is greater consolidation of 

ownership and operation, it does not believe that PBR is an immediate attractive option. 

269. Connecticut DPUC, along with testimony submitted by two of its witnesses, 

Thomas P. Lyon and Pete Landrieu, support the view that PBR is either inappropriate or 

unlikely to provide important benefits. Lyon’s affidavit emphasizes that critical 

principles for PBR include not only incentives to enhance efficiency and performance, 

but also should promote an efficient mix of infrastructure investment. He cautions 

against the use of price caps because they may induce firms to degrade quality, and he 

would favor some type of profit-sharing plan, perhaps a PBR that links a firm’s financial 

performance to network congestion.164 Landrieu’s affidavit emphasizes that PBR is 

unnecessary, because system standards and performance are better managed directly by 

various regional reliability organizations. He also is pessimistic that PBR focused only 

on transmission will be able to account for important and complex tradeoffs between 

generation and transmission. He agrees with other comments that note that establishing 

appropriate benchmarks is an extremely complicated task and for that reason regards 

benchmark type PBR as unworkable.165

 164 Comments of Connecticut DPUC, Affidavit of Thomas P. Lyon at 16-19. 

165 Comments of Connecticut DPUC, Affidavit of Pete Landrieu at 27-28. 
Docket No. RM06-4-000 - 143 - 

c. Commission Determination

270. We interpret “incentive-based (including performance-based) rate treatments” in 

section 219 to require the Commission to consider PBR as an option among incentive 

ratemaking treatments. To that end, the NOPR invited comments on how performancebased regulation might be used to motivate transmission entities to maintain and operate 

their systems reliably and efficiently. Consistent with Congress’ directive to encourage 

PBR, we signaled our intention to reevaluate previous Commission policies on PBR. We 

did not intend that the NOPR be viewed as a rejection of our previous statements or as a 

comprehensive overview of all possible approaches to PBR. Our objective was to 

consider whether PBR can play a useful role in transmission pricing reforms in light of 

the many changes in electric markets that have occurred since our earlier statements. 

271. The overwhelming view on PBR from all segments of the industry is “not at this 

time” and “not given the current industry structure.” Although there is general support 

for our earlier principles, we acknowledge, as commenters stress, that our voluntary 

program has not resulted in any PBR proposals being filed with the Commission. The 

consensus appears to be that the current state of the industry structure – a multitude of 

transmission-owning entities, many that do not directly control their transmission assets 

and operate in diverse geographical regions with very different customer densities, 

system ages and configurations – makes the determination of generally applicable 

performance benchmarks unworkable. Some suggest further study of PBR, express 
Docket No. RM06-4-000 - 144 - 

general support for the concept, and urge the Commission to remain open to considering 

voluntary proposals on a case-by-case basis. 

272. We share the view of most commenters that it would be premature to adopt 

generic PBR measures at this time. However, the development of PBR measures may 

represent a long-term goal for the industry and the Commission to pursue. Among the 

goals of section 219 is to promote capital investment “in the enlargement, improvement, 

maintenance, and operation” of transmission facilities. Accordingly, we intend to 

continue to work with the industry to encourage development of PBR proposals. 

2. Comments Proposing Performance Tests and Competitive Bidding

a. Comments

273. The New Mexico AG asserts that another way to implement an incentive-based 

mechanism is to penalize companies or RTOs that do not perform adequately and do not 

make the investments necessary to ensure the reliability of the transmission grid. The 

Delaware Commission contends that providing incentives without assessing penalties for 

failure to meet obligations violates the just and reasonable standard because it rewards 

monopoly power. Furthermore, the Delaware Commission claims that the plain meaning 

of incentive requires both rewards and penalties. NASUCA states that it is one-sided and 

inherently unfair to provide incentives that only increase utility profits with no 

performance accountability. 

274. The Delaware Commission recommends that the Commission implement 

performance penalties by first defining the utility obligation, then determining whether 
Docket No. RM06-4-000 - 145 - 

there are transmission incentive projects which the transmission owner has failed to carry 

out, and in such situations impose a penalty in the form of a prospective reduction in 

return on equity or prudence disallowance that can be lifted when the project is complete. 

275. TAPS argues that transmission providers should have their returns reduced to the 

low end of the zone of reasonableness if they fail to achieve and maintain a robust 

transmission infrastructure. TAPS recommends the Commission consider a number of 

factors in its determination of system reliability, including congestion, proration of 

financial transmission rights (FTRs), lack of available transfer capacity (American 

Transmission), failure to meet customer needs and denial of reasonable access. TAPS 

also asserts that the capital requirements of major projects should be put out to bid if a 

vertically-integrated transmission owner is unwilling to permit transmission dependent 

utility (TDU) participation but refuses to build without receiving above-cost rate 

treatments. 

276. The Missouri Commission proposes that the Commission implement a process that 

determines performance-based ROEs. The process, according to the Missouri 

Commission, would require transmission owners to bid out projects, thereby providing an 

incentive for keeping implementation costs as low as possible and minimizing the 

regulatory concern with cost overruns. Projects based on actual costs would receive an 

ROE below the median of ROEs from the proxy group while projects proposing fixed 

costs would receive higher ROEs, explains the Missouri Commission. The Missouri 

Commission also recommends that the bids include an assessment and quantification of 
Docket No. RM06-4-000 - 146 - 

specific risks associated with the project. E.ON US would support a competitive bidding 

process for transmission additions required to enhance reliability or to meet native load 

requirements. 

b. Commission Determination

277. As discussed in the preceding section, the Commission will continue to support 

industry in the development of PBR but will not in the Final Rule impose it. 

Accordingly, we will not pursue performance treatments and competitive bidding. 

Moreover to the extent these proposals consist of penalties (which would not provide 

incentives to expand transmission infrastructure and would likely limit the investment in 

infrastructure by reducing the return – and therefore funds for capital expansions), they 

do not implement the requirements of section 219. 

278. We note that the Commission has other regulations to address concerns over 

access and discrimination raised by commenters, including rules promulgated under 

Order No. 888, the anti-manipulation provisions of Order No. 672166 and market behavior 

rules. We believe those regulations provide adequate protections. Further, all rates that 

include incentives will remain in the zone of reasonableness, and, therefore, we disagree 

with the Delaware Commission that rates without penalties are not just and reasonable. 

 166 Rules Concerning Certification of the Electric Reliability Organization; and 

Procedures for the Establishment, Approval, and Enforcement of Electric Reliability 

Standards, Order No. 672, 71 FR 8662 (Feb. 17, 2006), FERC Stats. & Regs., ¶ 31,204 

(2006), order on reh’g, Order No. 672-A, 71 FR 19,814 (Apr. 18, 2006), FERC Stats. & 

Regs. ¶ 31,212 (2006). 
Docket No. RM06-4-000 - 147 - 

279. While the requirements of section 219 and the Final Rule do not encompass 

bidding processes, as recommended by the Missouri Commission and TAPS, we are 

sympathetic to the objective of the Missouri Commission to reduce the costs of 

expansions to consumers. We expect that regional planning processes that evaluate and 

compare the costs and benefits of expansion proposals, as well as state commission 

reviews and requirement that costs be prudently incurred will serve to provide the 

screening function desired by the Missouri Commission, and therefore additional 

processes are not necessary. We agree with NASUCA that there is merit in holding 

utilities receiving incentives accountable for investing the capital and building the 

capacity for which the incentives are provided, as we discuss further in section IV.A 

(Standard for Approval) and section III.D (Effective Date and Duration Of Effectiveness 

For Incentives). As we discuss further below in section IV.H (Public Power), we will not 

make TDU participation in the project a precondition for receiving incentives. 

E. Advanced Technologies

1. General

a. Background

280. Pursuant to section 219(b)(3) of the FPA, the NOPR proposed to encourage the 

use of advanced technology in new transmission projects. Advanced transmission 

technologies are defined in section 1223 of EPAct 2005 to be technologies that increase 
Docket No. RM06-4-000 - 148 - 

the capacity, efficiency, or reliability of an existing or new transmission facility.167 The 

Commission stated that it expected that the NOPR’s proposed incentives, including the 

ROE-based incentives, will stimulate investment in new transmission facilities, which 

will, in turn, provide opportunities for the deployment of innovative technologies for 

those new transmission facilities. 

281. The NOPR also asked for comments on: (1) whether the Commission should 

require that applications for incentive-based treatment include a technology statement; 

(2) whether other incentives could fulfill the goals of section 219(b)(3); and (3) whether 

performance-based benchmarks for transmission costs (i.e., a risk-sharing approach) 

would provide incentives for the deployment of advanced technologies.168

b. Comments 

282. NRECA and others support the incentives proposed in the NOPR and do not 

support additional separate incentives for advanced technology. They believe that 

technologies will be developed when they are cost effective. 

283. NEMA believes the technology list from section 1223 of EPAct2005 should be 

incorporated into the Final Rule to ensure that the Commission’s regulations express the 

intent of Congress. But, EEI argues that a predetermined list of advanced technologies 

 167 Section 1223 identifies 18 such technologies and further provides that advanced 

transmission technologies include any other technologies that the Commission considers 

appropriate. 

168 NOPR at P 64-66. 
Docket No. RM06-4-000 - 149 - 

would soon become outdated, which may discourage the use of other worthwhile 

technologies. Bonneville states that the list in the NOPR is incomplete and includes 

items that range from measures in common use today to very speculative items. AEP 

believes that any list of advanced technology should be illustrative and non-exclusive. 

284. AEP and others want the Commission to encourage additional measures related to 

reliability and infrastructure development, including control center upgrades, national 

security-related infrastructure facilities vital to the electric system and operation, the 

refurbishment of aging transmission assets, advanced grid control technologies for realtime measurement, communications and control, “non-wires” alternatives to control or 

dispatch loads and resources for optimum use of the transmission and distribution 

infrastructure, inventories of transformers and other critical equipment, and substation 

upgrades. 

285. Some commenters seek incentives for technologies that could indirectly mitigate 

congestion and enhance grid reliability. UTC Power believes the Commission should 

provide incentives for distributed generation, such as fuel cells. Sabey believes that 

advanced technology usage on the distribution system may provide transmission 

congestion relief. FirstEnergy suggests incentives for pumped storage hydro and 

compressed air energy storage. 

286. NSTAR and Vectren urge the Commission to recognize the higher risk caused by 

accelerated obsolescence of transmission facilities. Obsolescence may be the result of 

the changing transmission technology. Accelerated depreciation could be relevant to a 
Docket No. RM06-4-000 - 150 - 

specific facility that may have a useful life less than its physical life due to obsolescence. 

287. Some commenters, such as International Transmission, state that it is imperative 

that new technology installed on the grid be reliable and durable for decades. They 

express concern that new technologies may carry significant risks and may ultimately not 

be low cost and reliable. 

c. Commission Determination

288. We agree with comments that new technologies will be adopted when they are 

cost effective. Incentives will be considered for advanced technologies through the same 

evaluation process as other technologies, as discussed in this Final Rule. 

289. We will not provide a unique incentive designed for a specific technology. To the 

extent that applicants seek additional incentives for advanced technologies, the 

Commission will consider the propriety of such incentives on a case-by-case basis. 

290. Section 1223 of EPAct 2005 lists 18 advanced transmission technologies. We 

interpret this list as being illustrative of the kinds of technologies that Congress sought to 

encourage and not exclusive of advanced technologies that may be employed and 

considered for incentive ratemaking treatment. We expect new technologies to 

continually evolve. Moreover, as noted above, section 1223 of EPAct 2005 also provides 

that advanced transmission technologies include any other advanced transmission 

technologies that the Commission considers appropriate. Thus, we decline to adopt in 

the regulatory text a specific list of technologies eligible for incentive ratemaking, and 
Docket No. RM06-4-000 - 151 - 

will entertain proposals for incentives rate treatments for advance technologies on a caseby-case basis. 

291. This includes technologies that may indirectly mitigate congestion and enhance 

grid reliability, if such technologies can be shown to increase the capacity, efficiency, or 

reliability of an existing or new transmission facility. 

292. The Commission does not have sufficient information to make generic judgments 

about what barriers exist, if any, to the introduction of particular technologies based on 

the record. To the extent applicants believe additional incentives for advanced 

transmission technologies are needed, they must support such requests in individual 

cases. 

293. In addition, we note that those applicants that do not want to use accelerated 

depreciation for all their facilities may elect to utilize this incentive for advanced 

technologies since the useful life of such technologies may not be sufficiently known. 

The Commission will also consider requests to recover the costs of obsolescent plant, 

thereby facilitating the addition of new, more technically advanced transmission 

infrastructure. 

2. Case-by-Case Review

a. Comments

294. Ameren and others suggest the Commission should determine whether technology 

applications are just and reasonable on a case-by case basis, which would allow 
Docket No. RM06-4-000 - 152 - 

applicants flexibility to determine which technologies are best suited for a particular 

project. 

295. National Grid believes the Commission should encourage the development of the 

best technology for particular needs identified in transmission owners’ planning 

processes. This avoids putting the Commission in a position of picking winners and 

losers, but would allow transmission owners to make appropriate decisions relative to 

costs, benefits and risks associated with advanced technologies. 

296. International Transmission suggests the Commission should determine what 

incentives are necessary to overcome barriers to deployment of the technologies defined 

in section 1223 of EPAct 2005, and then authorize those incentives on a case-by-case 

basis. 

297. As an alternative to the case-by-case consideration of incentives, AEP 

recommends establishment of criteria for transmission investment to receive full 

incentive treatment. Such criteria might include: reducing congestion, advancing growth 

and security of the interstate grid, and providing an opportunity to site fuel diverse, newer 

technology, and environmentally friendly generation. 

b. Commission Determination 

298. The Commission will consider incentives for advanced technologies on a case-bycase basis. As discussed above, we are not making generic determinations regarding the 

applicability of incentives to particular technologies. Consistent with this case-by-case 

approach, we will not adopt AEP’s suggestion to establish generic criteria for evaluating 
Docket No. RM06-4-000 - 153 - 

which transmission investments will receive full incentives. As discussed by Ameren 

and others, case-by-case review also provides flexibility to transmission providers in 

identifying the technologies that are most appropriate for their project applications and 

business models. It also avoids putting the Commission in a position of picking winners 

and losers, but allows transmission owners to make appropriate business decisions, as 

discussed by National Grid. The Commission in its reviews will provide incentives to 

technologies that increase the capacity, efficiency, or reliability of an existing or new 

transmission facility. 

299. With regard to International Transmission’s concerns, the Commission is not in a 

position to make generic judgments about what barriers exist, if any, to the introduction 

of particular technologies. To the extent applicants believe additional incentives for their 

advanced technology applications are needed, they can make a case for advanced 

technology incentives in their individual proceedings and the Commission will make a 

case-by-case determination. 

3. Whether To Require A Technology Statement 

a. Comments

300. TAPS and others believe the Commission should not require that a particular 

technology or the most advanced technology be used in order to qualify for incentives. 

They believe that a technology statement would add an unnecessary burden to 

applications and would likely result in Commission approval of imprudent and routine 

transmission investment. They also argue that statements made by an applicant would 
Docket No. RM06-4-000 - 154 - 

tend to be self-serving, and not detailed enough for proper Commission evaluation. 

Instead, the Pennsylvania Commission suggests that the Commission develop in-house 

technology expertise, or alternatively establish a peer review board of nationally 

recognized independent experts. 

301. UTC Power believes the technology statement should also include a list of the 

advanced technologies capable of meeting the project goals for reducing congestion and 

increasing reliability, and reasons they were not employed. Duquesne supports a 

technology statement but does not believe that it should have to be specific as to describe 

all technologies that were considered and not used. 

b. Commission Determination 

302. In as much as EPAct 2005 requires the Commission to encourage the deployment 

of transmission technologies, we will require applicants for incentive rate-treatment to 

provide a technology statement that describes what advanced technologies have been 

considered and, if those technologies are not to be employed or have not been employed, 

an explanation of why they were not deployed. 

4. Risk Sharing

a. Comments

303. CCAS suggests that the Commission offer a framework of cost sharing among 

entrepreneurs, ratepayers, utility shareholders and taxpayers, peer review and competitive 

solicitation to share and recover qualified research development and demonstration 

project costs through transmission rates. NEMA supports performance-based ratemaking 
Docket No. RM06-4-000 - 155 - 

as a means of enabling advanced technology implementation for the sharing of benefits 

and risks between utilities and customers. 

304. CAISO suggests that the Department of Energy and the Commission cooperate 

with the industry and reliability organizations on programs to identify, test, and 

disseminate information on new technology. APPA also suggests a process for the 

Commission to work with each region to develop a technology plan and a research and 

development budget, with costs to be recovered through regional transmission rates. 

Sabey encourages the Commission to provide incentives for technology demonstrations 

on small-to-medium scale projects. 

305. NU and others suggests the Commission consider incentive ratemaking treatment 

of research and development dollars spent by utilities, which benefit the advancement of 

new technology. The Kentucky Commission believes in federal funding for research and 

that the Department of Energy is an appropriate sponsor for research in new transmission 

technology. 

306. EPRI supports efforts to enhance grid infrastructure, and offers a list of advanced 

transmission technologies that are near term or commercially available, those that may be 

available for demonstration within four months with commercial availability in three to 

five years, and longer-term technologies still in the research and development stage with 

possible demonstration in three to five years. 
Docket No. RM06-4-000 - 156 - 

b. Commission Determination

307. The Department of Energy is a more appropriate federal agency to promote 

research and development. Accordingly, research and development are beyond the scope 

of this proceeding, and we will not include incentive ratemaking for research and 

development costs in the Final Rule. 

5. Other Technology-Related Issues

a. Comments

308. Semantic states that the Final Rule needs to define “prudently-incurred” costs that 

are to be recoverable and proposes that “prudently-incurred” be defined to include a 

substitution test such that expenditures are not made in excess of that which is required. 

By way of example, Semantic offer that an open RFP process for congestion relief should 

provide for separate pricing for the avoided cost value of each separable reliability 

benefit for which the reliability standards require action. This separate pricing of 

strategies for achieving the reliability and congestion goals must be compared to the 

summed cost of the advanced technology that can achieve the goals when determining 

prudence and just and reasonable rates. Semantic believes that such an approach results 

in greater efficiency in the use of the existing grid and the Final Rule should provide 

incentives other than ROE adders to foster such efficiency through the use of Advanced 

Transmission Technologies for time of day congested segments of the grid. 

309. American Superconductor states that the Commission should revisit and clarify its 

Seven Factor Test for distinguishing between transmission and distribution facilities, to 
Docket No. RM06-4-000 - 157 - 

reflect technology advances made since the Commission adopted the Seven Factor Test. 

For example, American Superconductor states that it has developed dynamic VAR 

technologies that can effectively support transmission grids while connected to 

distribution facilities. Classification of such advanced technologies as transmission 

facilities would make them eligible for recovery under Commission-jurisdictional tariffs. 

b. Commission Determination

310. We deny Semantic’s request to define “prudently-incurred” as requiring an open 

RFP process to consider alternative technologies and to provide additional incentives to 

address time of day congestion. As previously stated, we expect that new development 

programs will include, or at least consider, advanced technologies, but we will not 

mandate it. We agree that improvements in the operation of the grid, perhaps through 

advanced technologies addressing time of day congestion, could result in efficiency 

benefits and encourage such proposals on a case-by-case basis. 

311. We also deny American Superconductor’s request to revisit our Seven Factor Test 

because it is beyond the scope of this proceeding.169 

 169 We note that if these technologies truly perform a transmission function, a 

more productive approach than modifying the Seven Factor Test may be to propose 

modification of the Uniform System of Accounts to reflect such plant in a new 

transmission-related plant account. But that is beyond the scope of this proceeding. 
Docket No. RM06-4-000 - 158 - 

F. Transmission Organization Incentive

1. Background

312. The NOPR (at P 45) proposed that the Commission will continue to consider 

requests for ROE-based incentives for utilities that join an RTO, in recognition of the 

benefits such organizations bring to customers, as outlined in detail in Order No. 2000. 

In addition, it proposed that the Commission will consider similar requests by utilities 

that join an ISO for an incentive ROE that, while still in the zone of reasonableness, is 

higher than the ROE the Commission might otherwise allow if the utility did not join. 

313. The NOPR (at P 46) also sought comment on whether the Commission should 

consider incentive-based ROE requests for public utilities that are not in an RTO but that 

join a Commission-approved regional planning organization. 

2. Comments

314. Comments span a wide range of views on proposed incentive for utilities that join 

an RTO. Several commenters170 support the proposal to continue to consider requests for 

ROE-based incentives for utilities that join a Transmission Organization. Most of these 

commenters also request that the incentive apply equally to both new members and 

existing members. They contend that denying an incentive to existing Transmission 

Organization members while awarding it to new members who join these organizations 

 170 E.g., Ameren, EEI, Electric Power Supply, FirstEnergy, KCPL, MidAmerican, 

National Grid, NYSEG, NorthWestern, New England TOs, NSTAR, PEPCO, PacifiCorp, 

PG&E, PJM, PJM TOs, TransCanada, Trans-Elect, Vectren, and WPS. 
Docket No. RM06-4-000 - 159 - 

unfairly discriminates against those entities that should be rewarded for taking the initial 

step of establishing and joining an independent Transmission Organization and would 

therefore be contrary to good public policy, unjust, unreasonable, and unduly 

discriminatory. In addition, this discrimination could create an incentive for a 

transmission owner to depart from an existing RTO and to join a new RTO, simply to 

obtain the NOPR incentives “for public utilities that join a Transmission Organization.” 

PEPCO states that an adder should apply generally to all facilities for utilities in the RTO, 

not just to new investment after a new company joins an RTO. 

315. Other commenters171 contend that, if the Commission does allow an incentive for 

joining a Transmission Organization, the incentive should only apply going forward for 

new members, not for those who already joined. They argue that incentives should incite 

or spur a desired future action, and thus it makes no sense to provide incentives to 

transmission owners for past behavior or for actions that are likely to occur under other 

normal business circumstances. Incentives for existing members would represent an 

unjustified windfall for utilities, at the expense of the transmission customers. In 

addition, the FPA does not permit the Commission to reward a utility “in recognition” of 

benefits for actions already taken by the utilities. 

 171 E.g., Connecticut DPUC, Dairyland, Delaware Commission, NRECA, NECOE, 

NECPUC, New York Commission, SMUD, TANC, MISO States and TDU Systems. 
Docket No. RM06-4-000 - 160 - 

316. Some of these commenters also assert that the incentive should not apply where a 

transmission owner is ordered to join a RTO/ISO by statute or has agreed to join an 

RTO/ISO as a condition of receiving approval for a merger, market-based rates, or 

because of other regulatory actions. Also, possible incentives for joining an RTO, and 

the procedures for requesting such incentives, are already addressed in Order No. 2000. 

317. Certain commenters172 contend that the Commission should consider giving ROE 

incentives only to companies joining a newly forming Transmission Organization, rather 

than existing ones, and then only for a limited period of time; and if a public utility 

withdraws from an RTO or ISO for which it obtained an ROE adder for joining, the 

Commission should issue an order immediately eliminating such ROE adders. 

318. Others request that the Commission make a generic finding that entities that join 

an ISO or RTO automatically qualify for the incentive. For example, Trans-Elect 

submits that the Commission can and should use the record developed in this proceeding 

to find, on a generic basis, that RTO/ISO membership produces sufficient customer 

benefits to qualify for the 50 basis-point ROE adder. 

319. Some commenters173 state that this incentive should not be limited to public 

utilities. It should apply to all transmitting utilities and electric utilities, including 

municipal utilities. Another view, that of Northwestern’s, would have the Commission 

 172 E.g., MISO States, NRECA, and TDU Systems. 

173 E.g., CAISO, APPA, and NRECA. 
Docket No. RM06-4-000 - 161 - 

consider granting such incentives to transmission owners that are actively engaged in the 

development of an RTO or ISO, and permit transmission owners to recover prudently 

incurred costs of developing an RTO or ISO as they are incurred, in regions that do not 

currently have such an independent entity. American Wind strongly supports the 

objective to regionalize the grid, but believes that it would not serve the Commission’s or 

Congress’ goal to allow incentives to any type of Transmission Organization that is 

approved by the Commission for the operation of facilities. For example, American 

Wind states that single-system Transcos do nothing for regional goals. 

320. Some commenters raise issues concerning the definition of a Transmission 

Organization. For example, Bonneville and PNM believe that incentives should be 

available to utilities that enter agreements or form transmission associations outside the 

specific models of RTOs or ISOs. MISO States contend that the Commission should not 

grant ROE incentives to utilities joining Transmission Organizations until these entities 

are more clearly defined. MISO States assert that the Commission currently has 

inadequately specified standards and requirements for “independent transmission 

providers” and no established standards or requirements for “other transmission 

organizations.” 

321. Some commenters seek some type of conditions/criteria for receiving the 

Transmission Organization incentive, including: ongoing participation in an ISO that 

provides open access on the basis of competitive bids and that allocates the costs of grid 

access to users based on LMP ; participation in the relevant ISO or RTO planning process 
Docket No. RM06-4-000 - 162 - 

such that the ISO or RTO will make a determination of need; or tying the incentives to 

whether the Transmission Organization has an effective regional planning process that 

results in the construction, not merely the identification, of transmission. Others suggest 

tying the level of the incentive to meeting certain criteria, including: a single sliding scale 

ROE adder mechanism which is tied to levels of independence; or a graduated incentive 

tied to important features of the Transmission Organization like degree of independence, 

range of functions, transparency of operations, openness of stakeholder forums, and 

geographic scope of the transmission planning area.174

322. Some commenters state that there should be penalties associated with a lack of 

participation in Transmission Organizations.175 For example, they contend that: the ROE 

should be reflecting that service not provided by an ISO or RTO is less optimal; there 

should be a negative 50 basis point penalty on those public utilities that seek to withdraw 

from RTOs within the first 5 to 10 years of participation to recognize the costs paid by 

consumers to fund the public utility’s participation; and there should be penalties for 

incumbent transmission owners that continue to frustrate RTO formation. 

 174 E.g., SDG&E, CAISO, International Transmission, National Grid, and MISO 

States. 

175 E.g., California Oversight Board, TDU Systems, and TransCanada. 
Docket No. RM06-4-000 - 163 - 

323. Some commenters oppose ROE-based incentives for joining an RTO or ISO.176 

Among other reasons, they state that: it has not been determined whether the benefits of 

participation in RTOs outweigh the costs, and, therefore, there is no justification for an 

incentive to encourage participation in RTOs; that the incentive is unwarranted because 

RTOs and similar organizations have a poor track record for getting new transmission 

built; that return incentives for RTO participation raise the already heavy RTO cost 

burden and add fuel to the concerns of state commissions and customers about RTO 

costs, thus undermining RTOs; that the risk of joining an RTO/ISO will already be 

reflected in the utility’s return allowance; that joining an RTO/ISO is already lucrative, a 

fact that can be illustrated by the sound business conditions of the existing transmission 

owners’ businesses in an RTO/ISO area in which transmission businesses will have 

guaranteed returns as a monopoly business; and that the incentive is not tied to actual 

new investments, and allowing an increased ROE on all transmission investment 

(including existing facilities) would merely drive up transmission rates. 

324. According to PPC, EPAct 2005 is conspicuously silent regarding whether 

Transmission Organizations are desirable, and section 219(c) cannot fairly be read to 

authorize the Commission to provide incentives to the utilities that join such 

organizations that are greater than those incentives that are available to other, nonmember utilities. 

 176 E.g., APPA, NRECA, and TDU Systems. 
Docket No. RM06-4-000 - 164 - 

325. Several commenters support incentives for participation in a regional planning 

process that is not necessarily an RTO.177 For example, PJM supports incentives for 

transmission owners’ participation in robust regional transmission planning processes as 

an effective, collaborative and transparent means to ensure the development of 

economically efficient transmission projects that truly benefit customers. MidAmerican 

states that a strict requirement for public utility participation in an RTO or ISO could 

discourage certain transmission owners, particularly non-jurisdictional transmission 

owners, from regional participation under any structure. Bonneville states that modest 

financial incentives linked to construction of new facilities advocated by an independent 

regional planning process may be sensible, but incentives must be tied to implementation 

of the regional plan, not just for mere participation in the organization. 

3. Commission Determination

326. To the extent within our jurisdiction, we will approve, when justified, requests for 

ROE-based incentives for public utilities that join and/or continue to be a member of an 

ISO, RTO, or other Commission-approved Transmission Organization. However, we are 

not persuaded that we should create a generic adder for such membership, but instead 

will consider the appropriate ROE incentive when public utilities request this incentive. 

The decision in this rule to consider specific incentives on a case-by-case basis fulfills the 

 177 E.g., Ameren, Southern Companies, SCE, PJM, and MidAmerican. 
Docket No. RM06-4-000 - 165 - 

Congressional mandate to the Commission.178 Thus, issues concerning risk such as those 

raised by SMUD are more appropriately addressed in the proceedings that evaluate proxy 

companies and set a zone of reasonableness. 

327. We will not make a generic finding on the duration of incentives that will be 

permitted for public utilities that join Transmission Organizations. An entity will be 

presumed to be eligible for the incentive if it can demonstrate that it has joined an RTO, 

ISO, or other Commission-approved Transmission Organization, and that its membership 

is on-going. Any public utility receiving an incentive ROE for joining a Transmission 

Organization but that withdraws from such organization is no longer eligible for the ROE 

incentive. 

328. We will not broaden or restrict the definition of Transmission Organization. For 

purposes of this Final Rule, and as defined in section 3(29) of the FPA, a Transmission 

Organization means a Regional Transmission Organization, Independent System 

Operator, independent transmission provider, or other transmission organization finally 

approved by the Commission for the operation of transmission facilities. We note that all 

RTOs and ISOs are already covered by this definition, and we will consider, on a caseby-case basis, applications for other types of entities to be classified as Transmission 

 178 We believe that the Commission’s accounting and reporting procedures for 

RTOs, as required by Order No. 668, address commenters’ concerns about the 

management of RTO costs. See Accounting and Financial Reporting for Public Utilities 

Including RTOs, Order No. 668, FERC Stats. & Regs. ¶ 31,199 (2005). 
Docket No. RM06-4-000 - 166 - 

Organizations for purposes of whether membership warrants incentives under these 

provisions. 

329. With respect to NorthWestern’s argument that the Commission should consider 

incentives for the development of a Transmission Organization and permit recovery of 

prudently incurred costs of such development as they are incurred, the Commission will 

review applications for incentives in the context of filings for the creation of 

Transmission Organizations and determine the appropriate methods for recovery of costs 

on a case-by-case basis. With respect to comments suggesting specific criteria to qualify 

for the incentive (e.g., participation in a planning process) or that the level of the 

incentive be tied to meeting certain criteria, we will not specify such criteria in this Final 

Rule. 

330. Several comments urge that eligibility for these incentives not be limited to public 

utilities. However, the fact is that section 219(a) directs that this rulemaking provide 

incentives for “public utilities” and public utilities are the only entities whose rates are 

jurisdictional under sections 205 and 206 of the FPA. Further, although section 219(c) 

refers to incentives for “transmitting utilities” and “electric utilities” that join 

Transmission Organizations, it also contains the provision “to the extent within its 

jurisdiction.” Accordingly, the rule will apply to jurisdictional public utilities.179 We 

 179 We note that new section 211A gives the Commission authority to order 

transmission services by otherwise non-jurisdictional transmitting utilities. The 

Commission has never exercised authority under the new provision and the new 

(continued) 
Docket No. RM06-4-000 - 167 - 

clarify that this does not mean that public utilities are precluded from proposing incentive 

plans under section 205 whereby incentives would be given to public utilities as well as 

non-public utilities. Indeed, we encourage such plans. However, we would generally not 

have authority under sections 205 and 206 to enforce such incentives for the non-public 

utilities. 

331. We also clarify that, as explained earlier, entities that have already joined, and that 

remain members of, an RTO, ISO, or other Commission-approved Transmission 

Organization, are eligible to receive this incentive. The basis for the incentive is a 

recognition of the benefits that flow from membership in such organizations and the fact 

continuing membership is generally voluntary.180 Our interpretation of the statute is that 

eligibility for this incentive flows to an entity that “joins” a Transmission Organization 

and is not tied to when the entity joined. As some commenters note, to do otherwise 

could create perverse incentives for an entity to actually leave Transmission 

Organizations and then join another one. It would also be unduly discriminatory for the 

Commission to consider the benefits of membership in determining the appropriate ROE 

for new members but not for similarly situated entities that are already members. 

 

provision provides limited rate authority. However, we leave open the possibility that 

incentives for otherwise non-jurisdictional transmitting utilities could be permitted in an 

order under section 211A. 

180 Our clarification also applies to utilities that joined RTOs or ISOs because of 

merger conditions or market-based rate requirements. 
Docket No. RM06-4-000 - 168 - 

332. We will not at this time establish a specific incentive for joining a Commissionapproved regional planning organization. A regional planning process is very important 

to meeting regional transmission needs, and, we believe it will produce benefits for 

customers. For this reason, we have initiated a proposed rulemaking to require 

transmission providers to coordinate with interconnected systems when planning 

transmission system additions.181 This increased coordination in regional planning 

proposed in the OATT Reform NOPR would be mandatory, not optional, and therefore 

we will not offer at this time an incentive for such coordination. However, if a region 

develops a planning processes that is superior to that required by the OATT reform 

rulemaking (such as by using an independent entity to perform system planning), nothing 

in this final rule would preclude entities in the region from requesting appropriate 

incentives under FPA section 219. 

333. As stated earlier in this Final Rule, we will not adopt performance-based ROEs 

that reduce ROEs for transmitting utilities that do not join Transmission Organizations, as 

recommended by several commenters. The purpose of this rule is to provide incentives, 

per the requirements of section 219. 

 181 See OATT Reform NOPR at 214. 
Docket No. RM06-4-000 - 169 - 

G. Recovery of Prudently Incurred Costs to Comply with Reliability Standards 

and Recovery of Prudently Incurred Costs Associated with Transmission 

Infrastructure Development

1. Background

a. Prudently Incurred Costs to Meet Mandatory Reliability Standards

334. Under FPA section 215 (Electric Reliability), an Electric Reliability Organization 

may propose, and the Commission may approve by rule or order, reliability standards.182 

Pursuant to section 219(b)(4)(A) of the FPA, the NOPR (at P 47) proposed to allow 

recovery of all prudently incurred costs necessary to comply with these mandatory 

reliability standards. Proposed new § 35.35(f) would allow for such recovery. 

b. Prudently Incurred Costs Associated with Transmission Infrastructure 

Development

335. Under FPA section 216 (siting of interstate electric transmission facilities), the 

Commission has certain backstop siting authority for transmission facilities when the 

Secretary of Energy designates a geographic area experiencing electric transmission 

capacity constraints or congestion that adversely affects consumers as a National Interest 

Electric Transmission Corridor. Pursuant to section 219(b)(4)(B) of the FPA, the NOPR 

(at P 48) proposed to allow recovery of all prudently incurred costs related to 

infrastructure development pursuant to section 216. Proposed new § 35.35(g) would 

allow for recovery of such prudently incurred costs. 

 182 An Electric Reliability Organization is the organization certified by the 

Commission to establish and enforce reliability standards for the bulk power system, 

subject to Commission review. See Order Nos. 672 and 672-A. 
Docket No. RM06-4-000 - 170 - 

2. Comments

336. Several commenters raise issues applicable to both the mandatory reliability 

standard-related incentive and the infrastructure development-related incentive. For 

example, PJM TOs argue that the Commission should require that recovery of such 

prudently incurred costs be through stand-alone section 205 filings. 

337. FirstEnergy and National Grid seek clarification that the NOPR is not revising 

existing policy on the recovery of prudently incurred costs and that there continues to be 

a presumption that investment is prudently made, with the burden of the challenging 

party to prove otherwise. 

338. NRECA requests guidance from the Commission on what it considers to be 

prudently incurred costs. NRECA suggests the addition of a test to determine if the costs 

to comply with mandatory reliability standards and infrastructure development are just, 

reasonable and not unduly discriminatory, and that the Commission require participation 

in a regional planning process, with LSE participation. 

339. Some commenters proffer specific examples they believe should be considered as 

prudently incurred reliability or infrastructure development costs. For example, AEP 

recommends the cost of control centers and national security infrastructure, and Semantic 

recommends substation tests as reliability costs. 

340. East Texas and others caution the Commission to approve only the costs that are 

necessary to comply with mandatory reliability standards and for transmission 
Docket No. RM06-4-000 - 171 - 

infrastructure development. They express concern about the potential for rising costs to 

customers that may result from additional transmission investment. 

341. APPA and others raise issues specific to recovery of prudently incurred costs to 

comply with mandatory reliability standards. APPA and other commenters agree that it 

is appropriate for the Commission to allow recovery of all prudently incurred costs to 

comply with mandatory reliability standards, and recommend the Commission clarify 

standards for determining that such costs are prudently incurred. TDU Systems suggest 

the Commission approve only prudently incurred costs to comply with mandatory 

reliability standards that are approved by a regional entity and in the context of a full FPA 

section 205 rate hearing or under a formula rate. 

342. East Texas raises an issue specific to recovery of prudently incurred costs 

associated with infrastructure development. It requests that the Commission make 

explicit provisions in its transmission incentives rules for any actions that it may 

undertake under the new siting authority provided to it under section 216. 

3. Commission Determination

343. The Commission will allow recovery of all prudently incurred costs necessary to 

comply with the mandatory reliability standards under section 215 and all prudently 

incurred costs associated with infrastructure development under section 216. In response 

to commenters, we further clarify that the Commission will review applications for the 

recovery of such prudently incurred costs under its section 205 procedures. 

344. Some confusion may have been caused because the NOPR is more broadly 
Docket No. RM06-4-000 - 172 - 

related to transmission pricing reform and expresses the Commission’s willingness to 

consider a variety of transmission pricing “incentives” to encourage the construction of 

new transmission. In many instances new investment in transmission may both improve 

reliability and reduce congestion. However, the NOPR specifically referred to recovery 

of “prudently incurred costs” in the context of the section 215 and 216-related expenses 

and investment. We take this opportunity to clarify that we are simply codifying our long 

standing regulatory policy that allows utilities the opportunity to recover all prudently 

incurred costs associated with the provision of transmission service in interstate 

commerce. 

345. We deny NRECA’s request that the Commission require participation in a 

regional planning process as part of the prudence review. As we have stated earlier in 

this rule, we will not make regional planning a precondition of receiving incentive 

ratemaking treatment. However, we expect and encourage participation in regional 

planning processes for all major transmission additions, including those within a 

designated national interest corridor. 

346. In regard to commenters’ specific examples of what they believe should be 

considered as prudently-incurred reliability or infrastructure development costs, we find 

it premature to develop such a list of pre-approved costs without proper consideration of 

the equipment involved and its application to the transmission system. This type of casespecific justification would be required from the applicant in its section 205 filing. 

347. Similarly, we deny APPA’s request to establish standards for determining that 
Docket No. RM06-4-000 - 173 - 

reliability standards compliance costs are prudently incurred. The Commission is making 

no change in the long-standing regulatory presumption in a section 205 proceeding that 

costs are prudently incurred, but parties are free to provide evidence to the contrary; and, 

ultimately, the burden is on the applicant to demonstrate that its proposal is just and 

reasonable. 

348. We deny the request of East Texas that the Final Rule include explicit provisions 

for any actions the Commission may take with respect to the Commission’s backstop 

siting authority under FPA section 216. This is beyond the scope of this rulemaking, 

which addresses only the recovery of prudently-incurred costs related to transmission 

infrastructure development pursuant to FPA section 216, not the Commission’s backstop 

siting authority under that section. This issue is best addressed in the National Interest 

Electric Transmission Corridors proceeding in Docket No. RM06-12-000. 

H. Public Power

1. Background

349. Given the importance of public power participation and the requirements of 

section 219, the NOPR (at P 63) requested comments on what actions the Commission 

should take in this rulemaking to encourage public power participation in new 

transmission projects. The NOPR asked, for example, whether the consortium approach 

would help to promote expansion of the transmission grid, and, if so, what types of 

incentives the Commission could provide to encourage such consortia. 
Docket No. RM06-4-000 - 174 - 

2. Comments

350. Commenters express diverse views. Several commenters183 express support for 

the consortium approach. For example, Connecticut DPUC states that the approach has 

appeal especially for very large transmission projects involving multiple states and that 

where there is agreement on the project, a sharing of the benefit incentives might be 

applicable. Similarly, Ameren and PJM state that public power involvement can be 

valuable and that the Consortium should receive the same incentives available to public 

utilities developing such projects. PJM supports a case-by-case approach for incentive 

rate treatment for these types of projects. EEI and MidAmerican offer that regardless of 

whether public power is involved, any member of the consortium should receive the same 

incentives that public utilities receive for building new projects. Upper Great Plains 

states that incentives should be available to all forms of joint projects, not just those 

arising from an RTO-led consortium. 

351. Certain commenters184 state that public power participation should not be 

mandated. New England TOs warn that requiring that utilities offer participation in 

transmission projects to certain pre-specified parties will be counter-productive. New 

England TOs state that there are other entities (e.g., private equity, merchant 

 183 E.g., Connecticut DPUC, PJM, Municipal Commenters, Semantic, Progress 

Energy, and Ameren Services. 

184 E.g., KCPL, National Grid, International Transmission, New England TOs, 

NU, NYSEG, and SMUD. 
Docket No. RM06-4-000 - 175 - 

transmission) who might have an interest in investing in a particular project and that the 

Commission has no basis for discriminating in favor of public power by giving it special 

investment rights and that doing so will create controversy. 

352. Some of these same commenters that support the consortia185 also support the 

Commission offering to public power entities the same incentives it is offering to 

jurisdictional public utilities, including Transcos. For example, AMP-Ohio states that the 

Commission should encourage arrangements that allow public power entities to obtain 

direct ownership. Wyoming Infrastructure Authority states that public power 

participation has demonstrably aided grid expansion projects to increase reliability and 

efficiency of the transmission grid. 

353. Others propose limitations, including limiting incentives to those applicants 

offering third-party participation in projects.186 Citizens Energy, for example, states that 

the Commission should require Transmission Organizations to adopt rules which ensure 

non-discrimination against merchant transmission. TransCanada proposes a specific 

process for merchant transmission. FirstEnergy states that public power participation 

should be permitted only when such entities have an OATT on file with the Commission. 

 185 E.g., AMP-Ohio, Ameren, CAISO, Municipal Commenters, Nevada 

Companies, Upper Great Plains, Powder River, Wyoming Infrastructure Authority and 

Snohomish. 

186 E.g., TAPS, TANC, NECOE, Citizens Energy, TDU Systems, and Municipal 

Commenters.. 
Docket No. RM06-4-000 - 176 - 

Still other commenters187 state public power already enjoys various benefits over 

investor-owned utilities (e.g., access to low-cost borrowing funds, ability to set own rates, 

tax advantages) and that the Commission should not further the rate advantages. 

3. Commission Determination

354. We agree with comments that public power participation can play an important 

role in the expansion of the transmission system. We want to encourage public power 

participation in new transmission projects, but the ratemaking incentives we discuss in 

the Final Rule are generally not directly available to non-jurisdictional entities such as 

most public power entities, because they do not file their rates with the Commission. 

However, to the extent our jurisdiction allows, the Commission will entertain appropriate 

requests for incentive ratemaking for investment in new transmission projects when 

public power participates with jurisdictional entities as part of a proposal for incentives 

for a particular joint project.188 Encouraging public power participation in such projects 

is consistent with the goals of section 219 by encouraging a deep pool of participants. 

355. We will not specify which incentives might be most appropriate for encouraging 

participation by public power entities but instead will allow the applicants to make 

 187 E.g., KCPL and EEI. 

188 This is not to say that the Commission would not consider incentive ratemaking 

treatment for a consortium project that did not include public power participation. 

Nothing in this rule prevents jurisdictional entities from combining their resources on a 

project. 
Docket No. RM06-4-000 - 177 - 

proposals that best suit their circumstances. We also clarify that the Commission’s 

approval of an incentive plan proposed by a public utility that also pertains to an entity 

that is not otherwise jurisdictional under sections 205 and 206 (e.g., public power), does 

not affect the non-jurisdictional status of the entity. 

356. We will not, however, require public power or other joint participation in a 

transmission project in order for investment in a project to be eligible for incentives. 

While participation by a diverse group of investors might be the best structure for an 

individual project, it is inappropriate to mandate a particular joint-structure be used in all 

cases. However, we clarify that, to the extent allowed under our jurisdiction, a public 

power entity should have the same opportunity afforded to jurisdictional entities to 

recover costs related to new transmission investment. 

357. We believe a consortium approach that includes public power and other entities 

for new investment has value and we encourage participation by public power in meeting 

the transmission infrastructure provisions of section 219. However, we will not require a 

consortium approach. We believe it is more appropriate for applicants to fashion 

proposals for new transmission infrastructure projects that are tailored to the specific 

circumstances and needs of a particular project. In addition, we believe a consortium-led 

proposal that is the result of an open, collaborative, regional process and that includes a 

diverse group of participants may face less resistance from parties when a filing is made 

here, because competing interests will have already been addressed before the proposal is 

filed with the Commission. 
Docket No. RM06-4-000 - 178 - 

V. Reporting Requirement

A. Background

358. Section 35.35(h) of the proposed rule would require jurisdictional public utilities 

to report annually to the Commission no later than April 18, 2007, and, in succeeding 

years, on the date on which FERC Form No. 1 information is due the following data and 

projections: (subsection i) in dollar terms, actual investment for the most recent calendar 

year, and planned investments for the next five years; and (subsection ii) for all current 

and planned investments over the next five years, a project by project listing that 

specifies for each project the expected completion date, percentage completion as of the 

date of filing and reasons for delay. A draft Form X was provided in the Appendix. 

359. In the NOPR (at P 49), the Commission stated that the purpose of the reporting 

requirement is to determine the effectiveness of the proposed rules and to provide the 

Commission with an accurate assessment of the state of the industry with respect to 

transmission investment. 

B. Comments

360. A number of commenters189 support the proposed Form X reporting requirement. 

For example, International Transmission states that such reports are important to 

determine if the investment incentives adopted by the Commission are actually working 

to elicit investment in transmission that benefits consumers. Some of these commenters 

 189 E.g., International Transmission, NRECA, APPA, National Grid, AEP and 

TAPS, Siemans, and NEMA. 
Docket No. RM06-4-000 - 179 - 

make a number of recommendations, including the following: define transmission 

investment for reporting; include separate categories for new generation interconnection 

versus other types of system upgrades; classify investments by voltage level to 

distinguish facilities that have little or nothing to do with the interstate transmission grid; 

exclude small, miscellaneous upgrades; provide instructions that Transmission Facilities 

in the table “Capital Spending On Electric Transmission Facilities” are defined as 

transmission assets under the Uniform System of Accounts in accounts 350 through 359; 

like the report with FERC Form No. 1; provide a list of categories for the “Reasons for 

Delay” column, such as siting, delayed completion of a new generator; report the 

consumer benefits of the project (e.g., congestion relief, enhanced reliability); require the 

posting of the information on RTO, ISO, Transco or public utility websites or OASIS; 

require that all the reports be aggregated in one report that is made public, thereby 

providing manufacturers with a better basis to plan for industry needs. 

361. Commenters also contend that the report does not go far enough.190 Some191 state 

that such reports should extend to all transmission providers, including those subject to 

new section 211A of the FPA and government-owned entities. Semantic asserts that the 

reporting requirements proposal is incomplete and does not adequately secure the 

 190 E.g., International Transmission, Northwestern, Siemans, NEMA, and 

Semantic. 

191 E.g., International Transmission, EEI, Northwestern, and KCP&L. 
Docket No. RM06-4-000 - 180 - 

comprehensive state of the grid information required by the regulators and market 

participants. Semantics would require that power systems state data must be made 

available in real-time to identify parallel flows and to avoid under-investment, overinvestment or bad investments; that the report should provide for the filing of data that 

enables the Commission to fulfill its oversight responsibility for RTOs under 

§ 35.34(k)(4) and to promote compliance with § 35.34(k)(1). Semantics further 

recommends that time of day rate schedules should be reported into a web-accessible 

national repository. Semantic explains that capital investment in advanced technologies 

will relieve congestion if this information is made known to technology vendors and 

entrepreneurial entities. 

362. Certain commenters192 that support the reporting also express concerns. For 

example, National Grid states the Commission should clarify that the forward-looking 

projections in Form X, rendered in good faith and upon a reasonable basis, would not 

subject the reporting transmission owners to claims of fraud, detrimental reliance or other 

liabilities arising from the fact that actual capital spending may vary from reported 

projections.193 Ameren requests that the Commission clarify that the reported 

information is to be provided for informational purposes only and should not be allowed 

 192 E.g., National Grid, Ameren, PG&E, and Nevada Companies. 

193 See Section 27A of the Securities Act of 1933, as amended; Section 21E of the 

Securities Exchange Act of 1934, as amended; 15 U.S.C. §§ 77z-2 and 78u-5; 17 CFR 

§ 240.3b-6. 
Docket No. RM06-4-000 - 181 - 

to form the basis of a review by the Commission or other entities regarding the 

reasonableness or prudence of the amounts reported. PG&E and the Nevada Companies 

assert that a disclaimer should be added to footnote 1 explaining that much of the 

information reported here may change over time and may be subject to correction. 

Trans-Elect asserts that the reporting requirement, alone, should not be allowed to form a 

basis for a section 206 investigation. 

363. Some commenters raise confidentiality concerns.194 EEI and KCP&L urge that 

the Commission afford Critical Energy Infrastructure Information (CEII)195 status to this 

information since it clearly relates to the production, generation, transmission or 

distribution of energy, could be useful to a person planning an attack and gives strategic 

information beyond the location of critical infrastructure. EEI encourages the 

Commission to perform an evaluation as to the need for confidentiality of selected 

company information due to the commercially sensitive nature of the information. 

Similarly, Ameren and TransElect request that the Commission clarify that the required 

information may be submitted pursuant to the Commission’s confidential filing 

procedures.196 

 194 E.g., TransElect, EEI, KCP&L, and Ameren. 

195 They cite Critical Infrastructure Information, Order No. 630, 68 FR 9857 

(March 3, 2003), FERC Stats. & Regs. ¶ 31,140 (2003), order on reh’g, Order No. 630-A, 

68 FR 46,456 (Aug. 6, 2003), FERC Stats. & Regs. ¶ 31,147 (2003).. 

196 See 18 CFR 388.112. 
Docket No. RM06-4-000 - 182 - 

364. A number of commenters oppose the reporting requirement for a variety of 

reasons. Several197 claim that the Commission has not provided adequate justification for 

the Form X data collection, as required by the Paperwork Reduction Act, given that the 

Commission already collects information on utility transmission investment and planning 

in existing FERC Form Nos. 1, 714 and 715 and that the Commission has not 

demonstrated the need to make the information collection mandatory. Ameren, AEP and 

PJM TOs state that the requested information duplicates information already being 

compiled by RTOs in their planning process; and MISO States suggest that the 

Commission obtain an aggregate report from the RTO. PJM TOs recommend that Form 

No. 1 requirements be modified prospectively, instead of requiring a new form. EEI is 

concerned that the Commission, state commissions and the public may inappropriately 

rely on the information, expecting the plans to be implemented without regard to the 

regulatory approvals and applicant and market decisions involved. EEI further states that 

reporting information on planned future facilities can lead to unnecessary opposition that 

might not occur with a proper public siting process, lead to speculation in land use fees 

that can harm the applicant’s customers. 

365. EEI, arguing that the only accurate measure of the effectiveness of the incentives 

is the number of applications filed for incentives, encourages the Commission to simply 

 197 E.g., EEI, Southern, SCE, KCP&L, Nevada Companies, Progress Energy, 

Mid-American and PG&E. 
Docket No. RM06-4-000 - 183 - 

monitor the number of applications for new transmission facilities, the magnitude of the 

facilities involved and the incentives sought and thereby obtain the most accurate 

measure of the effectiveness of the proposed incentives. EEI also encourages the 

Commission to rely on annual aggregate transmission investment information that EEI 

has provided to the Commission and can continue collecting for the Commission’s 

benefit. Nevada Companies assert this information should not be required since it is 

inaccurate and incomplete. 

366. Southern, SCE and Ameren propose limitations on the information to be provided 

as follows: only aggregate information should be required, and project-specific 

information should not be required since it is extremely burdensome, entails security and 

confidentiality issues, and is subject to change; if project-level information is required, 

that it be limited to major transmission projects, i.e., 345 kv and above; and limit projectspecific reporting requirements to only projects costing $20 million or more and that are 

subject to a Transmission Organization’s or a regional planning organization’s planning 

and approval process. 

C. Commission Determination

367. To ensure that these rules are successfully meeting the objectives of section 219, 

the Commission needs industry data, projections and related information that detail the 

level of investment. The rule’s purpose is to both provide new investment as well as 

ensure that customers benefit. Thus, information regarding projected investments as well 

as information about completed projects will help the Commission to monitor the success 
Docket No. RM06-4-000 - 184 - 

of the ratemaking reforms announced in this rule. Thus, the Commission will adopt the 

proposed reporting requirement Form X and designate it as the FERC-730. Further, the 

Commission will make certain modifications to clarify when reports must be filed and 

what data must be submitted in FERC-730 reports.198 The information required in 

FERC-730 is not available from Form Nos. 1, 714 or 715, nor is it available from other 

federal agencies. For instance, FERC Form No. 1 requires the reporting of historical 

financial data but does not contain forward looking projections of expected transmission 

investments.199 Thus, the information sought is not already readily available and will be 

required only from public utilities that have been granted incentive rate treatment for 

specific transmission projects under the provisions of § 35.35. 

368. We agree with commenters that, for some utilities, the information requested is 

similar to information submitted to RTOs. However, the Commission does not receive 

that information, and the information provided to RTOs may not be identical to the 

information requested here. Therefore, to ease the administrative burden, those utilities 

providing information to RTOs can submit the same information to the Commission. We 

 198 FERC-730 filers are reminded that each FERC-730 filing must be accompanied 

by a Subscription consistent with the requirements of 18 CFR 385.2005(a). 

199 See e.g., FERC Form No. 1 schedule pp. 204-7, “Electric Plant in Service 

(Accounts 101, 102, 103 and 106)” which requires the reporting of the original cost of 

electric plant in service and p. 216, “Construction Work in Progress—Electric (Account 

107)” which requires the reporting of expenditures for certain construction projects at 

December 31 of the reporting year. 
Docket No. RM06-4-000 - 185 - 

strongly encourage utilities that submit FERC-730 reports to do so in an electronic format 

via eFiling.200 To rely on information collected by EEI, as recommended, would not 

provide the Commission with the accurate information we need to assess the 

effectiveness of our regulations under section 219. The Commission would not have 

available to it the survey instruments or the analysis behind the reported information. 

Thus, reliance on second-hand gathered survey information for the purposes of rate 

setting would not provide the independent, factual basis to allow the Commission to 

make a determination that continuing incentives is appropriate. Likewise, the summary 

investment information available in existing reports does not provide information on 

projected investment or reasons for delays in projects, thereby limiting its value for 

determining the effectiveness of the rules. 

369. We do not believe a CEII designation is required for this information since it is 

expected to only include information on capital spending and a general designation of the 

project name, without requiring data on facility location. With respect to confidential 

treatment of FERC-730, as a general matter we do not believe that this type of general 

planning information involves commercially sensitive information. However, while we 

will require applicants to provide capital spending projections and other information in 

their applications, we also recognize that applicants may have legitimate reasons to 

 200 The Commission will issue a separate notice on how to submit this data 

electronically via eFiling. 
Docket No. RM06-4-000 - 186 - 

maintain confidentiality of certain information. For this reason, applicants can request 

protection of information under § 388.112. 

370. With respect to project-level information, this information is needed to determine 

the status of critical projects and reasons for delay, and will play a role in the 

Commission’s evaluation of continuing incentives. To facilitate this review, we will 

require that filers specify which projects are currently receiving incentives in the project 

detail table and that they group together those facilities receiving the same incentive. We 

will not limit the information to projects above a certain voltage, since lower-voltage 

projects can have significant impacts on reliability and congestion relief, nor will we limit 

the information to projects subject to a Transmission Organization’s or a regional 

planning organization’s planning and approval process since we are addressing a national 

problem and complete coverage is therefore necessary. As discussed earlier in this rule, 

projects eligible for incentives – and hence required to submit data – are not restricted to 

projects or investments that result from regional planning processes. We agree with SCE 

that a minimum dollar threshold of $20 million is a reasonable level for reporting of 

significant projects. 

371. We agree with many of the recommendations for modifications to the tables as 

shown in the revised FERC-730 in the Appendix. We will not require the reporting of 

consumer benefits of projects. In order for these projects to have received an incentive, 

the project must have met the requirements of this rule, which includes that it benefit 

consumers by ensuring reliability and reducing the cost of delivered power by reducing 
Docket No. RM06-4-000 - 187 - 

transmission congestion. We will not require the addition of operating data to the table 

since the sole purposes of the information collection is to determine the level of capital 

spending, the status of significant and critical projects and reasons for delay. We will not 

require a Proposed Operating Date, as recommended by Ameren, since our sole concern 

with this information is that the planned projects are completed on time; operational startup issues such as synchronization with the grid and testing introduce additional issues not 

directly relevant to tracking the progress of investments in new infrastructure. 

372. Further, we will not require year-by-year capital spending estimates for the project 

detail table as recommended by TAPS since the goal of the rule is not to ensure the 

achievement of annual capital spending targets but rather to ensure the overall project is 

completed, and if not, the reasons for the delay. We will not require the inclusion of cost 

allocation or pricing information as recommended by TAPS since that information is 

beyond the scope of our requirements. We do not see the need for a disclaimer that 

information is subject to change, since the required information is clearly labeled 

“projected” and “expected” and therefore assumed to be subject to change. Since this 

rulemaking applies to public utilities and incentives are being permitted pursuant to 

sections 219 and 205, which pertain to public utilities, we will not require information 

from entities that are not jurisdictional under section 205, although such entities are 

encouraged to voluntarily provide this information. We clarify that the meaning of “On 

Schedule” in the Project Detail table is the most up-to-date, expected project completion 

date. 
Docket No. RM06-4-000 - 188 - 

373. We clarify that the reported information is to be provided for informational 

purposes only, and its purpose is not to establish the prudence of the amounts spent. As 

we specified earlier in the rule, we expect applicants will propose metrics and provide a 

nexus between the incentive and the investment, and therefore the information in this 

report will not be the sole basis for a section 206 investigation. We further clarify that 

the projections in FERC-730, rendered in good faith and upon a reasonable basis, would 

not subject the reporting transmission owners to claims of fraud, detrimental reliance or 

other liabilities arising from the fact that actual capital spending may vary from reported 

projections. 

374. Rather than requiring all public utilities to submit FERC-730, we clarify that only 

those public utilities that have been granted incentive-based rate treatment for specific 

transmission projects under the provisions of § 35.35 must file FERC-730 in the manner 

prescribed in Appendix A. A public utility is subject to the FERC-730 reporting 

requirement beginning with the year the Commission issues an order in response to a 

filing made pursuant to section 205 of the Federal Power Act, or in a petition for a 

declaratory order that precedes a filing pursuant to section 205. The initial FERC-730 

filing is due by April 18 of the following calendar year and subsequent filings are due 

each April 18 thereafter. 

375. In addition, we will add a new provision to § 35.35(h) and delegate to the Chief 

Accountant or the Chief Accountant’s designee authority to act on requests for extension 
Docket No. RM06-4-000 - 189 - 

of time to file FERC-730 or to waive the requirements applicable to any FERC-730 

filing. 

376. Finally, we find the data issues raised by Semantic to be beyond the scope of this 

rulemaking. While the data requested by Semantic could provide a useful purpose for the 

operations and management of electric facilities and may have applicability to the 

Commission’s regulations for RTOs, this rulemaking is limited to an evaluation of 

incentives for investment in electric transmission facilities. Therefore, the reporting 

requirements of the rulemaking are appropriately limited to data on industry investment. 

VI. Other Issues

A. Rate Related Issues

1. Rate Related Issues

377. Commenters also raised other rate issues such as formula rates, rate design, the 

five-month suspension policy and recovery of other costs. The Commission addresses 

these issues below. 

a. Comments on Formula Rates

378. As an alternative to single-issue ratemaking, certain commenters urge the 

Commission to require recovery of incentives through various forms of formula rates.201 

Certain MISO TOs state that the Commission should facilitate recovery from wholesale 

and retail customers including bundled and unbundled retail load through a formula rate 

 201 E.g., APPA, AWEA, KKR, MDU, PG&E, Certain MISO TOs, and TAPS. 
Docket No. RM06-4-000 - 190 - 

for new investments. Certain MISO TOs cite section 219 of the FPA to argue that 

Congress required the Commission to ensure the recovery of all prudently incurred costs 

necessary to comply with mandatory reliability requirements and related to transmission 

infrastructure development.202 

379. EEI argues that the section 205 filing for a public utility with a formula rate should 

be limited to including appropriate language in the formula rate allowing the utility to get 

the incentives and not be the basis to challenge any other aspect of the formula rate. 

b. Comments on Rate Design

380. Several commenters urge the Commission to require applicants to seek rolled-in 

treatment, rather than participant funding, to recover any costs incurred under the rule.203 

Those commenters assert that participant funding is inequitable because it imposes too 

much of a system burden on limited customers and that participant funding may actually 

discourage investment. 

381. Other commenters support participant funding for projects.204 They argue that 

socialization unfairly requires others to pay for facilities that they do not need and may 

deter new investment. Xcel requests that the Commission provide clear guidance on the 

 202 Certain MISO TOs state that all costs of new investment should include the 

costs of facilities built by the company as well as the costs of facilities allocated to the 

company through a RTO transmission cost allocation process. 

203 E.g., East Texas, TDU Systems, and TAPS. 

204 E.g., NorthWestern, Progress, Southern Companies, PSEG, and E.ON US. 
Docket No. RM06-4-000 - 191 - 

issue of “rolled in” versus “incremental” pricing. Xcel states that the Commission should 

allow phased roll-in of transmission facilities as it does for natural gas pipelines because 

rolled-in pricing would encourage proper siting of generation. 

382. EEI states that the Commission should be open to proposals that deviate from the 

“higher of” policy where justified. 

383. Other commenters express support for regional or zonal rates.205 They argue that 

regional rates would foster new projects because the rates would match cost recovery to 

the broad regional benefits obtained and reduce opposition from local consumers and 

state regulators and litigation. 

c. Comments on Five-Month Suspension

384. EEI, SCE and Xcel argue that the Commission’s current suspension policy hinders 

transmission investment because delaying the effective date of rates forces a utility to 

absorb the costs associated with the new facilities during the suspension period, thereby 

effectively reducing that utility’s return on equity. Additionally, EEI argues that, because 

any rate increase authorized by the Commission could be made subject to refund, with 

interest, customers could be made whole even without a five-month suspension. SCE 

suggests that the Commission should either change the threshold for determining when 

rates are excessive or use a sliding scale that would impose a longer suspension the larger 

the excessive revenues. 

 205 E.g., TAPS and Upper Great Plains. 
Docket No. RM06-4-000 - 192 - 

d. Other Comments on Rate Design

385. Commenters raised a variety of rate design issues. Energy Capital states that the 

Commission must modify traditional ratemaking practices to recognize the risks and 

structures required to fund a single line transmission project. SCE states that an 

additional disincentive to transmission investment is the imputation of revenues from 

grandfathered agreements that are greater than the actual revenues under the agreements, 

thereby reducing the earned return for transmission tariff service. TAPS faults the 

Commission’s policy of excluding EPRI dues from transmission rates because wholesale 

customers may make their own direct contributions. Trans-Elect requests the 

Commission to confirm that all financing costs, including prepaid liquidity reserve and 

working capital costs required by the lender as a condition to financing, are recoverable 

in rates. 

e. Commission Determination

386. We agree with several commenters that formula rates can provide the certainty of 

recovery that is conducive to large transmission expansion programs.206 Moreover, 

formula rates alleviate the need for other relief sought by commenters. For example, 

public utilities with formula rates will generally be able to flow through increased 

transmission investment without concern as to the Commission’s five-month suspension 

 206 We will not rule on PG&E’s proposed rate base tracking mechanism here 

because we do not have an actual proposal with supporting documents before us. 
Docket No. RM06-4-000 - 193 - 

policy with the exception of the suspension period for approval of initial rates. While we 

continue to encourage public utilities to explore the benefits of filing transmission-related 

formula rates,207 we will not require public utilities to use formula rates to recover 

incentives. 

387. We disagree with the interpretation that section 219 requires the Commission to 

claim jurisdiction over the transmission component of bundled retail load. While MISO 

TOs are correct that section 219 requires the Commission to ensure the recovery of all 

costs prudently incurred for section 215 reliability compliance and section 216 national 

interest corridor investments, we do not believe it is necessary to assert jurisdiction over 

bundled retail transmission to fulfill this statutory requirement.208 

388. The rate design issues raised in the comments are beyond the scope of this 

proceeding.209 While rate designs can impact infrastructure investment, this rule is 

 207 Allegheny Power System Operating Companies, 111 FERC ¶ 61,308 at P 51 

(2005). See also Allegheny Power System Operating Companies, 106 FERC ¶ 61,003 at 

P 32 (2004) (“The parties may explore whether adopting formula rates for recovery of the 

costs of both the TOs’ existing transmission facilities and new transmission facilities 

would be best. Specifically, we note that other TOs that we have approved incentive 

rates for also have formula rates.”). 

208 We will not add the term “all” to the regulatory text in 18 CFR 35.35(f) and (g) 

as recommended by Certain MISO TOs. The text in those sections reflects the language 

in section 219 of the FPA and therefore meets the Commission’s compliance 

requirements. 

209 We will not retain 18 CFR 35.34(e) in the new regulations as requested by 

MISO States. However, the new regulations allow RTOs to propose alternative 

incentives in 18 CFR 35.35(d)(1)(iii) and under these new regulations, RTOs may 

(continued) 
Docket No. RM06-4-000 - 194 - 

limited to addressing incentive treatments that foster infrastructure investment. Interested 

parties may raise issues associated with rate design policies in the associated section 205 

filings in which applicants are seeking rate recovery of transmission incentives. 

389. We will not revise our five-month suspension policy in this proceeding. To the 

extent that public utilities are concerned that the Commission’s suspension policy 

unnecessarily delays recovery of prudent costs, there are alternative means to ensure such 

recovery. As mentioned previously, formula rates enhance cost recovery certainty. 

Further, public utilities that are concerned that a particular rate increase may be deemed 

"excessive" under our suspension policy may use our pre-filing process for discussing 

those concerns. 

390. We will not make the determination on Energy Capital’s proposal that the 

Commission modify its traditional ratemaking practices to recognize unique aspects of 

non-traditional transmission owners because the issues raised are novel and we would be 

better informed with an actual proposal before us. Regarding SCE’s concern about 

imputing the transmission revenues under grandfathered agreements using the OATT 

rate, this issue is beyond the scope of this proceeding. 

391. We shall deny TAPS proposal to reconsider our policy on recovery of EPRI 

research and development costs when the unbundled retail load takes service under the 

 

propose the incremental pricing provisions previously included in 18 CFR 35.34(e). 
Docket No. RM06-4-000 - 195 - 

same transmission rate as wholesale customers.210 That is beyond the scope of this 

proceeding. 

392. The Commission will remain flexible with respect to rate treatments proposals that 

applicants or interested parties can demonstrate to be just and reasonable. 

393. We will deny the request to confirm in this proceeding that prepaid liquidity 

reserve and working capital costs required by project lenders as a condition to financing 

are recoverable. Those issues were the subject of an Administrative Law Judge’s Initial 

Decision in Docket No. ER05-17-002 and are pending Commission review. Those issues 

are better addressed in that proceeding because that proceeding has a complete litigated 

record. 

394. We also find that EEI’s request that the Commission use this rule to revisit “and” 

pricing to be beyond the scope of this rule. 

B. Section 35.34

1. The Proposal to Eliminate Section 35.34(e) 

a. Background

395. The NOPR proposed that applicants for incentive ratemaking treatment under 

section 35.35 would not be required to support their applications with cost-benefit 

 210 The Commission has explained that, when the basis for calculating the amount 

of the voluntary contribution to EPRI for research and development is based on the 

amount of retail sales, recovery from wholesale customers is unreasonable. See Public 

Service Company of New Mexico, Opinion 133, 17 FERC ¶ 61,123 at 61,249 (1981), 

order on reh’g, Opinion No. 133-A, 18 FERC ¶ 61,036 (1982). 
Docket No. RM06-4-000 - 196 - 

analyses. The NOPR also proposed to eliminate § 35.34(e), which requires cost-benefit 

analyses by RTO applicants in order to avoid potential conflict between or overlap of the 

pre-existing regulations and the new § 35.35. 

b. Comments

396. Several comments specifically addressed the NOPR’s proposal to eliminate 

§ 35.34(e). TDU Systems do not oppose elimination of § 35.34(e), so long as the 

consumer protections embodied in that section are incorporated into a new rule adopted 

to replace it. TDU Systems argues that adoption of the conditions and criteria it 

recommends (i.e., public power participation in planning, financing and construction, and 

rolled-in rate treatment for expansions of network facilities) would ensure that these 

protections remain in place. TAPS, APPA and Industrial Consumers support retention of 

the cost-benefit provision for reasons given in their comments on the cost-benefit issue. 

397. NRECA supports the Commission’s proposal. Public utilities have had the 

opportunity for five years now to form RTOs and obtain transmission rate incentives for 

RTO membership. In light of the fact that it is yet to be demonstrated that the benefits of 

RTOs outweigh their cost, elimination of this provision is appropriate. 

398. MISO supports the elimination of § 35.34(e), because it will be superfluous and 

unnecessary if the NOPR is adopted. Moreover, MISO points out that the authorization 

for RTOs to include innovative rate treatments in their rates found in § 35.34(e) expired 

after January 1, 2005, with respect to transmission rate moratoriums and rates of return 

that do not vary with capital structure. 
Docket No. RM06-4-000 - 197 - 

399. Ameren Services does not oppose the Commission’s proposal to remove existing 

section 18 C.F.R. § 35.34(e) from its regulation. This is consistent with the mandate of 

new FPA section 219 to provide incentives for qualifying entities. Ameren Services 

contends that removal of § 35.34(e) will avoid confusion that could arise from potential 

conflicts between innovative rate treatments available under existing § 35.34(e) and the 

additional incentives proposed to be adopted in new § 35.35. 

400. MISO States generally support the elimination of § 35.34(e). However, MISO 

States point out that § 35.34(e) appears to contain a provision that permits RTOs to apply 

for incremental pricing for new transmission facilities in association with an embeddedcost access fee for existing transmission facilities. Such a provision does not appear to be 

encompassed in the language of the Commission’s proposed new § 35.35 rule. MISO 

States believe that such a provision could prove useful in certain circumstances and urges 

the Commission not to drop this provision in the transition process of deleting the 

elements in § 35.34(e) and replacing them with the new elements in § 35.35. 

401. NorthWestern opposes preferential treatment based on corporate structure. It 

argues that if the Commission does remove § 35.34(e) as proposed, it should make 

certain that its resulting policies provide the appropriate non-preferential treatment. 

c. Commission Determination

402. Comments opposing the elimination of the cost-benefit analysis requirement are 

addressed above in our determination to affirm the NOPR on the cost-benefit issue. 

403. MISO States expresses concern that the proposed new § 35.35 does not appear to 
Docket No. RM06-4-000 - 198 - 

encompass the provision in pre-existing § 35.34(e)(v) allowing RTOs to apply for 

incremental pricing for new transmission facilities in association with an embedded-cost 

access fee for existing transmission facilities. The deletion of § 35.34(e) is intended to 

eliminate potentially conflicting or overlapping regulations concerning requests for 

incentive rate treatment. Thus, for example, the deletion of § 35.34(e) eliminates 

potential confusion over whether a proposal would be an “innovative” rate treatment (and 

require a cost-benefit analysis) under the pre-existing rules or be an incentive rate 

treatment requirement (with no cost-benefit analysis) under the new rules. 

404. In Section IV.D. of this preamble in our determination segment, we find that we 

do not have a sufficient basis to adopt rules for PBR in this rule. Notwithstanding that 

determination not to enumerate PBR in the list of incentive rate treatments, we also state 

that we remain open to consider PBR proposals as an incentive rate treatment pursuant to 

section 219. Given that determination, and to avoid potential conflict or overlap with the 

rules adopted herein, we believe that removal of the pre-existing PBR provisions – 

§§ 35.34(e)(2)(v) and 35.34(e)(3) – is appropriate. 

405. We address NorthWestern’s comment that the Commission should not favor any 

particular corporate structure in the discussion of the Transco incentives, supra Section 

IV. 

VII. Information Collection Statement

406. The Office of Management and Budget (OMB) regulations require approval of 
Docket No. RM06-4-000 - 199 - 

certain information collection requirements imposed by agency rules.211 The 

Commission is submitting these reporting requirements to OMB for its review and 

approval under section 3507(d) of the Paperwork Reduction Act.212 Upon approval of a 

collection(s) of information, OMB will assign an OMB control number and an expiration 

date. Respondents subject to the filing requirements of this 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. Interested persons may obtain information on the 

reporting requirements by contacting: Federal Energy Regulatory Commission, 888 First 

Street, N.E., Washington, D.C. 20426 [Attention: Michael Miller, Office of the 

Executive Director, Phone: (202) 502-8415, fax: (202) 273-0873, e-mail: 

michael.miller@ferc.gov]. 

407. Public Reporting Burden: The Commission did not receive specific comments 

concerning its burden estimates and uses the same estimate here. Comments on the 

proposed reporting requirement (proposed in the NOPR as Form X) are addressed above 

in Section V, Reporting Requirements, where we adopt the FERC-730 information 

collection requirement. The comments received and our adoption of FERC-730 do not 

lead us to revise the NOPR’s estimates of the public reporting burden. 

 211 5 CFR 1320.13 (2005). 

212 44 U.S.C. 3507(d) (2000). 
Docket No. RM06-4-000 - 200 - 

Data Collection No. of 

Respondents 

No. of 

Responses 

Hours Per 

Response 

Total Annual 

Hours 

FERC-516 

Transcos 30 1 296 8,880 

Traditional 

Public Utilities 

200 1 181 36,200 

FERC-730 200 1 30 6,000 

Totals 230 1 222 51,080 

Total Annual hours for Collection: (Reporting + recordkeeping, (if appropriate)= 51,080 

hours. 

Information Collection Costs: The Commission sought comments about the time and 

corresponding costs needed to comply with these requirements. No comments were 

received. Costs for FERC-516 and FERC-730 = $6,129,600 (51,080 hours at $120 an 

hour). (The hourly rate was determined by taking the median annual salary from Bureau 

of Labor Statistics, Department of Labor Occupational Outlook Handbook. The figures 

reported by BLS are for 2002 and added to them was an inflation factor of 4.73 percent 

for the period January 2003 through December 2004.) 
Docket No. RM06-4-000 - 201 - 

Title: FERC-516 “Electric Rate Schedule Filings”, FERC-730 “Report of Transmission 

Investment Activity” 

Action: Proposed Collections 

OMB Control No: 1902-0096; and to be determined 

Respondents: Business or other for profit 

Frequency of Responses: On occasion for applicants and annually for transmission 

investment report. 

Necessity of the Information: The Final Rule amends the Commission’s regulations to 

implement the statutory provisions of section 1241 of EPAct 2005. The Act directs the 

Commission to establish incentive-based (including performance-based) rate treatments 

for the transmission of electric energy in interstate commerce by public utilities in order 

to benefit consumers by ensuring reliability and reducing the cost of delivered power by 

relieving transmission congestion. This mandate addresses an identified need to 

encourage construction of transmission infrastructure and encourage investment. 

Sufficient supplies of energy and a reliable way to transport those supplies are necessary 

to assure reliable energy availability and to enable competitive markets. Without 

sufficient delivery infrastructure, some suppliers will not be able to enter the market, 

customer choices will be limited, and prices may be needlessly higher or volatile. The 

implementation of incentive and performance-based rate treatments supports the 

Commission’s mandate to support investments in transmission capacity to reduce the cost 

of delivered power by reducing congestion. 
Docket No. RM06-4-000 - 202 - 

408. Entities seeking incentives to build new transmission facilities must file under Part 

35 of the Commission’s regulations, an application describing how the entity will bring 

benefits to the grid. The information provided for under Part 35 is identified as FERC516. The information for actual and planned investments as proposed in an annual report 

is identified as FERC-730 and the information is provided for under § 35.35(h) of the 

Commission’s regulations. 

409. Comments on the final rule may also be sent to the Office of Management and 

Budget. For information on the requirements, submitting comments on the collection of 

information and the associated burden estimates including suggestions for reducing this 

burden, please send your comments to the Federal Energy Regulatory Commission, 888 

First Street, N.E., Washington, D.C. 20426 (Attention: Michael Miller, Office of the 

Executive Director, (202-502-8415) or send comment to the Office of Management and 

Budget (Attention: Desk Officer for the Federal Energy Regulatory Commission, fax: 

202-395-7285, e-mail: oria_submission@omb.eop.gov., and please reference this 

rulemaking docket no. in your submission. 

VIII. Environmental Statement

410. 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.213 The Commission has categorically excluded certain 

 213 Regulations Implementing the National Environmental Policy Act, Order No. 

(continued) 
Docket No. RM06-4-000 - 203 - 

actions from this requirement as not having a significant effect on the human 

environment. Included in the exclusion are rules that are clarifying, corrective, or 

procedural or that do not substantially change the effect of the regulations being 

amended.214 Thus, we affirm the finding we made in the NOPR that this Final Rule is 

procedural in nature and therefore falls under this exception; consequently, no 

environmental consideration would be necessary. 

IX. Regulatory Flexibility Act Certification

411. The Regulatory Flexibility Act (RFA)215 requires that a rulemaking contain either 

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. However, the RFA does not define “significant” or 

“substantial” instead leaving it up to any agency to determine the impacts of its 

regulations on small entities. The Final Rule will not have a significant adverse impact 

on a substantial number of small entities. The Final Rule applies only to entities that 

own, control, or operate facilities for transmitting electric energy in interstate commerce 

and not to electric utilities per se. Small entities that believe this Final Rule will have a 

significant impact on them may apply to the Commission for waivers. 

 

486, 52 FR 47897 (1987), FERC Stats. & Regs. ¶ 30,783 (1987). 

214 18 CFR 380.4(a)(2)(ii). 

215 5 U.S.C. 601-612 (2000). 
Docket No. RM06-4-000 - 204 - 

X. Document Availability

412. 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 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, 

Washington, D.C. 20426. 

413. From the Commission’s Home Page on the Internet, this information is available 

in the eLibrary. The full text of this document is available on eLibrary both in PDF and 

Microsoft Word format for viewing, printing, and/or downloading. To access this 

document in eLibrary, type the docket number excluding the last three digits of this 

document in the docket number field. 

414. User assistance is available for eLibrary and the Commission’s website during 

normal business hours. For assistance, please contact Online Support at 1-866-208-3676 

(toll free) or 202-502-6652 (e-mail at FERCOnlineSupport@FERC.gov), or the Public 

Reference Room at 202-502-8371, TTY 202-502-8659 (e-mail at 

public.referenceroom@ferc.gov). 

XI. Effective Date and Congressional Notification

415. This Final Rule will take effect [insert date 60 days after date of publication in the 

Federal Register]. The Commission has determined, with the concurrence of the 

Administrator of the Office of Information and Regulatory Affairs of the Office of 
Docket No. RM06-4-000 - 205 - 

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 1996.216 The 

Commission will submit the Final Rule to both houses of Congress and the Government 

Accountability Office.217 

List of subjects in 18 CFR Part 35

Electric power rates 

Electric utilities 

Reporting and recordkeeping requirements 

By the Commission. 

Magalie R. Salas, 

Secretary. 

 216 5 U.S.C. 804(2) (2000). 

217 5 U.S.C. 801(a)(1)(A) (2000). 
Docket No. RM06-4-000 - 206 - 

 In consideration of the foregoing, the Commission amends part 35 of Chapter I, 

Title 18, Code of Federal Regulations, as follows: 

PART 35 – FILING OF RATE SCHEDULES AND TARIFFS 

1. The authority citation for part 35 continues to read as follows: 

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

7352. 

Subpart F – Procedures and Requirements Regarding Regional Transmission 

Organizations 

§ 35.34 [Amended] 

2. In § 35.34, remove and reserve paragraph (e). 

3. A new subpart G is added to read as follows: 

Subpart G – Transmission Infrastructure Investment Provisions 

§ 35.35 Transmission infrastructure investment. 

 (a) Purpose. This section establishes rules for incentive-based (including 

performance-based) rate treatments for transmission of electric energy in interstate 

commerce by public utilities for the purpose of benefiting consumers by ensuring 

reliability and reducing the cost of delivered power by reducing transmission congestion. 

 (b) Definitions.

 (1) Transco means a stand-alone transmission company that has been approved by 

the Commission and that sells transmission services at wholesale and/or on an unbundled 

retail basis, regardless of whether it is affiliated with another public utility. 
Docket No. RM06-4-000 - 207 - 

 (2) Transmission Organization means a Regional Transmission Organization, 

Independent System Operator, independent transmission provider, or other transmission 

organization finally approved by the Commission for the operation of transmission 

facilities. 

 (c) General rule. All rates approved under the rules of this section, including any 

revisions to the rules, are subject to the filing requirements of sections 205 and 206 of the 

Federal Power Act and to the substantive requirements of sections 205 and 206 of the 

Federal Power Act that all rates, charges, terms and conditions be just and reasonable and 

not unduly discriminatory or preferential. 

 (d) Incentive-based rate treatments for transmission infrastructure investment. The 

Commission will authorize any incentive-based rate treatment, as discussed in paragraph 

(d), for transmission infrastructure investment, provided that the proposed incentivebased rate treatment is just and reasonable and not unduly discriminatory or preferential. 

A public utility’s request for one or more incentive-based rate treatments, to be made in a 

filing pursuant to section 205 of the Federal Power Act, or in a petition for a declaratory 

order that precedes a filing pursuant to section 205, must include a detailed explanation 

of how the proposed rate treatment complies with the requirements of section 219 of the 

Federal Power Act and a demonstration that the proposed rate treatment is just, 

reasonable, and not unduly discriminatory or preferential. The applicant must 

demonstrate that the facilities for which it seeks incentives either ensure reliability or 

reduce the cost of delivered power by reducing transmission congestion consistent with 
Docket No. RM06-4-000 - 208 - 

the requirements of section 219, that there is a nexus between the incentive sought and 

the investment being made, and that resulting rates are just and reasonable. For purposes 

of paragraph (d), incentive-based rate treatment means any of the following: 

 (1) The Commission will authorize the following incentive-based rate treatments 

for investment by public utilities, including Transcos, in new transmission capacity that 

reduces the cost of delivered power by reducing transmission congestion or ensures 

reliability, and is otherwise just, reasonable and not unduly discriminatory or preferential, 

as demonstrated in an application to the Commission: 

 (i) A rate of return on equity sufficient to attract new investment in transmission 

facilities; 

 (ii) 100 percent of prudently incurred Construction Work in Progress (CWIP) in 

rate base; 

 (iii) Recovery of prudently incurred pre-commercial operations costs; 

(iv) Hypothetical capital structure; 

(v) Accelerated depreciation used for rate recovery; 

(vi) Recovery of 100 percent of prudently incurred costs of transmission facilities 

that are cancelled or abandoned due to factors beyond the control of the public 

utility; 

 (vii) Deferred cost recovery; and 
Docket No. RM06-4-000 - 209 - 

 (viii) Any other incentives approved by the Commission, pursuant to the 

requirements of this paragraph, that are determined to be just and reasonable and not 

unduly discriminatory or preferential. 

 (2) In addition to the incentives in § 35.35(d)(1), the Commission will authorize 

the following incentive-based rate treatments for Transcos, provided that the proposed 

incentive-based rate treatment is just and reasonable and not unduly discriminatory or 

preferential: 

 (i) A return on equity that both encourages Transco formation and is sufficient to 

attract investment; and 

 (ii) An adjustment to the book value of transmission assets being sold to a Transco 

to remove the disincentive associated with the impact of accelerated depreciation on 

federal capital gains tax liabilities. 

 (e) Incentives for joining a Transmission Organization. The Commission will 

authorize an incentive-based rate treatment, as discussed in paragraph (e), for public 

utilities that join a Transmission Organization, if the applicant demonstrates that the 

proposed incentive-based rate treatment is just and reasonable and not unduly 

discriminatory or preferential. Applicants for the incentive-based rate treatment must 

make a filing with the Commission under section 205 of the Federal Power Act. For 

purposes of paragraph (e), an incentive-based rate treatment means a return on equity that 

is higher than the return on equity the Commission might otherwise allow if the public 

utility did not join a Transmission Organization. The Commission will also permit 
Docket No. RM06-4-000 - 210 - 

transmitting utilities or electric utilities that join a Transmission Organization the ability 

to recover prudently incurred costs associated with joining the Transmission 

Organization, either through transmission rates charged by transmitting utilities or 

electric utilities or through transmission rates charged by the Transmission Organization 

that provides services to such utilities. 

 (f) Approval of prudently-incurred costs. The Commission will approve recovery 

of prudently-incurred costs necessary to comply with the mandatory reliability standards 

pursuant to section 215 of the Federal Power Act, provided that the proposed rates are 

just and reasonable and not unduly discriminatory or preferential. 

 (g) Approval of prudently incurred costs related to transmission infrastructure 

development. The Commission will approve recovery of prudently-incurred costs related 

to transmission infrastructure development pursuant to section 216 of the Federal Power 

Act, provided that the proposed rates are just and reasonable and not unduly 

discriminatory or preferential. 

 (h) FERC-730, Report of transmission investment activity. Public utilities that 

have been granted incentive rate treatment for specific transmission projects must file 

FERC-730 on an annual basis beginning with the calendar year incentive rate treatment is 

granted by the Commission. Such filings are due by April 18 of the following calendar 

year and are due April 18 each year thereafter. The following information must be filed: 

 (1) In dollar terms, actual transmission investment for the most recent calendar 

year, and projected, incremental investments for the next five calendar years; 
Docket No. RM06-4-000 - 211 - 

 (2) For all current and projected investments over the next five calendar years, a 

project by project listing that specifies for each project the most up-to-date, expected 

completion date, percentage completion as of the date of filing, and reasons for delays. 

Exclude from this listing projects with projected costs less than $20 million; and 

 (3) For good cause shown, the Commission may extend the time within which any 

FERC-730 filing is to be filed or waive the requirements applicable to any such filing. 

The authority to act on motions for extensions of time to file FERC-730 or to waive the 

requirements applicable to any FERC-730 filing, including granting or denying such 

motions, in whole or in part, is delegated to the Chief Accountant or the Chief 

Accountant’s designee. 

 (i) Rebuttable presumption. The Commission will apply a rebuttable presumption 

that an applicant has met the requirements of section 219 for: 

 (i) A transmission project that results from a fair and open regional planning 

process that considers and evaluates projects for reliability and/or congestion and is found 

to be acceptable to the Commission; 

 (ii) A project that has received construction approval from an appropriate state 

commission or state siting authority; or 

 (iii) A proposed project that is located in a National Interest Electric Transmission 

Corridor pursuant to section 216 of the Federal Power Act. 
Docket No. RM06-4-000 - 212 - 

Note: The following appendices will not be published in the Code of Federal 

Regulations.

APPENDIX A 

FERC-730, Report of Transmission Investment Activity 

Company Name: ________________________________________ 

Table 1: Actual and Projected Electric Transmission Capital Spending 

Actual at 

December 

31, 

Projected Investment (Incremental Investment by 

Year for Each of the Succeeding Five Calendar 

Years) 

20__ 20__ 20__ 20__ 20__ 20__ 

Capital Spending On 

Electric Transmission 

Facilities 1/ 

($ Thousands) 

1/ Transmission facilities are defined to be transmission assets as specified in the 

Uniform System of Accounts in account numbers 350 through 359 (see, 18 CFR Part 

101). 
Docket No. RM06-4-000 - 213 - 

Table 2: Project Detail 1/ 

Project 

Description 2/ 

Project 

Type 3/ 

Expected 

Project 

Completion 

Date 

(month/year)

Completion

Status 4/ 

Is Project 

On 

Schedule?

(Y/N) 

If Project Not On 

Schedule, Indicate 

Reasons For Delay 

5/ 

 

1/ Respondents must list all projects included in the actual and projected electric 

transmission capital spending table, excluding those projects with projected costs less 

than $20 million. 

2/ Project description should include voltage level. 

3/ Project types are New Build, Upgrade of Existing, Refurbishment/Replacement, 

or Generator Direct Connection. 

4/ Completion status designations are Complete, Under Construction, PreEngineering, Planned, Proposed, and Conceptual. 

5/ Reasons for delay designations are Siting, Permitting, Construction, Delayed 

Completion of New Generator, or Other (specify). 
Docket No. RM06-4-000 - 214 - 

APPENDIX B 

Commenters on the NOPR 

Public Utilities and Trade Associations

Ameren Service Company (Ameren) 

American Electric Power System Corporation (AEP) 

American Transmission Companies (American Transmission) 

WestConnect Public Utilities (WestConnect) 

Baltimore Gas and Electric Company (BG&E) 

California Independent System Operator Corporation (California ISO) 

Certain Midwest ISO Transmission Owners (Certain MISO TOs) 

Citizens Energy Corporation (Citizens Energy) 

Consumers Energy Company (Consumers Energy) 

DTE Energy Company (DTE Energy) 

Duquesne Light Company (Duquesne) 

E.ON U.S. LLC (E.ON US) 

Edison Electric Institute (EEI) 

Electric Power Supply Association (EPSA) 

FirstEnergy Service Company (FirstEnergy) 

Gridwise Alliance (Gridwise) 

International Transmission Company (International Transmission) 

ISO New England (ISO-NE) 

Kansas City Power & Light Company (KCPL) 

MidAmerican Energy Company (MidAmerican) 

Midwest Independent Transmission System Operator, Inc. (Midwest ISO) 

Montana-Dakota Utilities (Montana-Dakota) 

National Grid USA (National Grid) 

Nevada Power Company and Sierra Pacific Power Company (Nevada Companies) 
Docket No. RM06-4-000 - 215 - 

New England Transmission Owners (New England TOs) 

New York Independent System Operator, Inc. (New York ISO) 

New York Electric & Gas Corporation and Rochester Gas & Electric Corporation 

 (NYSEG and RGE) 

Northeast Utilities (NU) 

NorthWestern Corporation (NorthWestern) 

NSTAR Electric & Gas Corporation (NSTAR) 

Pacific Gas and Electric Company (PG&E) 

PacifiCorp 

Pepco Holdings, Inc., et al. (Pepco) 

PJM Interconnection, LLC (PJM) 

PJM Transmission Owners (PJM TOs) 

Progress Energy, Inc. (Progress Energy) 

PSEG Companies (PSEG) 

Public Service Company of New Mexico and Texas-New Mexico Power Company 

 (PNM and TNMP) 

San Diego Gas & Electric Company (SDG&E) 

Southern California Edison Company (SCE) 

Southern Company Services, Inc. (Southern Companies) 

Trans-Elect, Inc. (Trans-Elect) 

United Illuminating Company (United Illuminating) 

WPC Companies (WPS) 

Xcel Energy Services, Inc. (Xcel) 

Public Power Entities and Associations

American Municipal Power-Ohio, Inc. (AMP-Ohio) 

American Public Power Association (APPA) 

Bonneville Power Administration (Bonneville) 
Docket No. RM06-4-000 - 216 - 

California Department of Water Resources State Water Project (CADWR) 

CAPX Utilities (CAPX Utilities) 

Community Power Alliance 

Dairyland Power Cooperative (Dairyland) 

East Texas Cooperatives (East Texas) 

Hamilton, Ohio, et al. (Municipal Commenters) 

Imperial Irrigation District (Imperial) 

Los Angeles Department of Water and Power (LADWP) 

National Rural Electric Cooperative Association (NRECA) 

New England Consumer-Owned Entities (NECOE) 

New York Association of Public Power (NY Association) 

Public Power Council (PPC) 

Public Utility District No. 1 of Snohomish County, Washington (Snohomish) 

Sacramento Municipal Utility District (SMUD) 

Transmission Access Policy Study Group (TAPS) 

Transmission Agency of Northern California (TANC) 

Transmission Dependent Utility Systems (TDU Systems) 

Upper Great Plains Transmission Coalition (Upper Great Plains) 

Wyoming Infrastructure Authority 

State Commissions and Other State Entities

California Electricity Oversight Board (California Oversight Board) 

Public Utilities Commission of the State of California (California Commission) 

Committee on Regional Electric Power Cooperation (CREPC) 

Connecticut Attorney General (Connecticut AG) 

Connecticut Department of Public Utility Control (Connecticut DPUC) 

Delaware Public Service Commission (Delaware Commission) 

Kentucky Public Service Commission (Kentucky Commission) 
Docket No. RM06-4-000 - 217 - 

Long Island Power Authority and Long Island Lighting Company (LIPA) 

Maryland Public Service Commission (Maryland Commission) 

Missouri Public Service Commission (Missouri Commission) 

National Association of Regulatory Commissioners (NARUC) 

National Association of State Regulatory Consumer Advocates (NASUCA) 

New England Conference of Public Utility Commissioners (NECPUC) 

New Jersey Board of Public Utilities (New Jersey Board) 

New Mexico Attorney General (New Mexico AG) 

New York Public Service Commission (New York Commission) 

North Dakota Industrial Commission (North Dakota Commission) 

Oklahoma Corporation Commission (Oklahoma Commission) 

Organization of MISO States (MISO States or OMS) 

Pennsylvania Public Utility Commission (Pennsylvania Commission) 

Wyoming Office of Consumer Advocate (Wyoming Consumer Advocate) 

Others

American Superconductor Corporation (American Superconductor) 

American Wind Energy Association (AWEA) 

Babcock & Brown, L.P. (Babcock & Brown) 

Coalition for the Commercial Application of Superconductors (CCAS) 

Consumer Energy Policy of America (CECA) 

Electric Power Research Institute (EPRI) 

Energy Capital 

Energy Financing, Inc. (Energy Financing) 

Industrial Consumers [ELCON, et al.] (Industrial Consumers) 

JH2 Risk Advisors (JH2) 

Kohlberg Kravis Roberts & Co. (KKR) 

National Electrical Manufacturers Association (NEMA) 
Docket No. RM06-4-000 - 218 - 

Norton Energy Storage (Norton) 

Powder River Energy Corporation (Powder River) 

Sabey Corporation (Sabey) 

Semantic Applications, Inc. (Semantic) 

Siemens Power Transmission & Distribution (Siemens) 

Steel Manufacturers Association (Steel Manufacturers) 

TransCanada Pipelines Limited (TransCanada) 

UTC Power 

Vectren Corporation (Vectren) 

Reply and Supplemental Comments

EEI 

International Transmission 

KKR 

National Grid