UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 35 

(Docket No. RM06-4-001; Order No. 679-A) 

Promoting Transmission Investment through Pricing Reform 

(Issued December 22, 2006) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Final Rule; Order on Rehearing. 

SUMMARY: In this order on rehearing, the Federal Energy Regulatory Commission 

(Commission) reaffirms its determinations in part and grants rehearing in part of 

Promoting Transmission Investment through Pricing Reform, Order No. 679, 71 Fed. 

Reg. 43,294 (July 31, 2006). Order No. 679 amended Commission 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. 

EFFECTIVE DATE: This order on rehearing will be effective on [Insert date 30 days 

after the publication in Federal Register]. 

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 

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 

SUPPLEMENTARY INFORMATION:
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Joseph T. Kelliher, Chairman; 

 Suedeen G. Kelly, Marc Spitzer, 

 Philip D. Moeller, and Jon Wellinghoff. 

Promoting Transmission Investment through 

Pricing Reform 

Docket No. RM06-4-001 

ORDER NO. 679-A 

ORDER ON REHEARING 

(Issued December 22, 2006) 

TABLE OF CONTENTS

 Paragraph Numbers

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

II. Background................................................................................................................... 9.

III. Discussion.................................................................................................................. 11.

A. Procedural Matters ................................................................................................. 11.

B. Statutory Arguments .............................................................................................. 13.

1. Rehearing Requests ............................................................................................ 13.

2. Commission Determination................................................................................ 14.

C. Nexus Requirement ................................................................................................ 16.

1. Rehearing Requests ............................................................................................ 17.

2. Commission Determination................................................................................ 20.

D. Cost-Benefit Analysis ............................................................................................ 28.

1. Rehearing Requests ............................................................................................ 29.

2. Commission Determination................................................................................ 35.

E. Rebuttable Presumptions ........................................................................................ 41.

1. Rehearing Requests ............................................................................................ 42.

2. Commission Determination................................................................................ 46.

F. ROE Sufficient to Attract Investment..................................................................... 48.

1. Rehearing Requests ............................................................................................ 49.

2. Commission Determination................................................................................ 56.
G. Incentives Available to Transcos ........................................................................... 68.

1. Rehearing Requests ............................................................................................ 69.

2. Commission Determination................................................................................ 73.

H. Transmission Organization Incentive .................................................................... 76.

1. Rehearing Requests ............................................................................................ 77.

2. Commission Determination................................................................................ 83.

I. Hypothetical Capital Structure ................................................................................ 88.

1. Rehearing Requests ............................................................................................ 89.

2. Commission Determination................................................................................ 90.

J. Single-Issue Ratemaking ........................................................................................ 91.

1. Rehearing Request.............................................................................................. 92.

2. Commission Determination................................................................................ 94.

K. Public Power .......................................................................................................... 97.

1. Rehearing Request.............................................................................................. 98.

2. Commission Determination................................................................................ 99.

L. Other Issues .......................................................................................................... 100.

1. Recovery of Costs of Abandoned Facilities ..................................................... 101.

2. Prudently Incurred Costs .................................................................................. 105.

3. Regional Planning............................................................................................. 107.

4. CWIP ................................................................................................................ 109.

5. Reporting Requirement: FERC-730 ................................................................. 112.

6. Miscellaneous ................................................................................................... 115.

IV. Information Collection Statement ........................................................................... 130.

V. Document Availability ............................................................................................. 131.

VI. Effective Date.......................................................................................................... 134.

APPENDIX 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Joseph T. Kelliher, Chairman; 

 Suedeen G. Kelly, Marc Spitzer, 

 Philip D. Moeller, and Jon Wellinghoff. 

Promoting Transmission Investment through Pricing 

Pricing Reform 

Docket No. RM06-4-001 

ORDER NO. 679-A 

ORDER ON REHEARING 

(Issued December 22, 2006) 

I. Introduction

1. On July 20, 2006, the Commission issued a Final Rule in this proceeding.1

 In the 

Final Rule, the Commission amended its regulations to establish incentive-based 

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

interstate commerce by public utilities. These incentives are intended to benefit 

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

transmission congestion. We took this action pursuant to section 1241 of the Energy 

 1

 Promoting Transmission Investment through Pricing Reform, Order No. 679, 

71 FR 43294 (July 31, 2006), FERC Stats. & Regs. ¶ 31,222 (2006) (Order No. 679 or 

Final Rule). 
Docket No. RM06-4-001 -2- 

Policy Act of 2005 (EPAct 2005),2

 which added a new section 219 to the Federal Power 

Act (FPA). The Final Rule identified ratemaking treatments available under section 219. 

The Final Rule did not grant incentives to any particular entity, but rather required each 

applicant to demonstrate that it could meet the requirements of section 219 and the Final 

Rule. 

2. Many entities sought rehearing of the Final Rule.3

 The petitioners representing 

consumer interests argue that the Final Rule was too permissive in offering rate 

incentives. We have carefully reviewed these petitions and grant them in part in this 

order. 

3. In doing so, we do not, however, depart from a fundamental commitment to 

provide incentives to support the development of transmission infrastructure. Section 

219 was enacted because of a long decline in transmission investment that is threatening 

reliability and causing billions of dollars in congestion costs. To reverse this historical 

trend, section 219 directed the Commission to "establish, by rule, incentive-based 

(including performance-based) rate treatments" that: “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 

 2

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

(2005). 

3

 The parties who filed the requests for rehearing and/or clarification are listed in 

Appendix A. 
Docket No. RM06-4-001 -3- 

transmission of electric energy in interstate commerce, regardless of the ownership of the 

facilities; provide a return on equity that attracts new investment in transmission facilities 

(including related transmission technologies); 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 allow recovery of –

(A) all prudently incurred costs necessary to comply with mandatory reliability standards 

issued pursuant to section 215 and (B) all prudently incurred costs related to transmission 

infrastructure development pursuant to section 216."4

 The Final Rule fulfilled that 

command by providing a range of rate treatments that remove impediments to new 

investment or otherwise attract that investment. 

4. This order retains those rate treatments, but modifies the way in which they are 

applied in three principal respects to address the concerns of petitioners. 

5. First, NARUC argues that we erred in rebuttably presuming that certain review 

processes (e.g., state siting approvals and regional planning processes) satisfy section 

219's requirement that a transmission project ensure reliability or reduce congestion. 

NARUC contends that these review processes do not, in all cases, establish the need for a 

particular facility. We grant rehearing in part on this issue. The Commission created the 

rebuttable presumption because we do not wish to duplicate the work of state siting 

authorities, regional planning processes, or the U.S. Department of Energy (DOE) under 

 4

 16 U.S.C.A. 824s(a), (b)(1) (West Supp. 2006). 
Docket No. RM06-4-001 -4- 

EPAct section 1221. However, we agree with NARUC to the extent that, if review 

processes do not include a determination of whether a project ensures reliability or 

reduces congestion, no rebuttable presumption should exist for that project. We will 

therefore require that each applicant explain whether any process being relied upon for a 

rebuttable presumption includes a determination that the project is necessary to ensure 

reliability or reduce congestion. Furthermore, we clarify that this rebuttable presumption 

applies only to whether the project reduces congestion or encourages reliability, not the 

additional requirements of the Final Rule. As discussed more fully elsewhere in this 

order, we also grant rehearing with respect to the Final Rule’s rebuttable presumption 

concerning a National Interest Electric Transmission Corridor (NIETC) designation. 

6. Second, the Final Rule required that each applicant demonstrate a nexus between 

the incentive being sought and the investment being made. Several petitioners argue that 

the nexus test is not sufficiently rigorous to protect consumers. We grant rehearing in 

part on this issue. The Final Rule stated that the nexus test is to be applied separately to 

each incentive, rather than to the package of incentives as a whole. We agree that this 

approach fails to protect consumers where an applicant both seeks incentives that reduce 

the risk of the project and seeks an enhanced rate of return on equity (ROE) for increased 

risk. We will therefore grant in part rehearing and require applicants to demonstrate that 

the total package of incentives is tailored to address the demonstrable risks or challenges 
Docket No. RM06-4-001 -5- 

faced by the applicant in undertaking the project.5

 If some of the incentives in the 

package reduce the risks of the project, that fact will be taken into account in any request 

for an enhanced ROE. 

7. Third, several petitioners argue that the Final Rule erred in its treatment of 

incentive returns on equity. Specifically, they fear the Commission will routinely grant 

ROEs at the top end of the zone of reasonableness. Although the Commission has broad 

discretion to establish returns on equity anywhere within the zone of reasonableness, we 

must be careful in the manner we exercise this discretion. The Commission clarifies 

below that we do not intend to grant incentive returns "routinely" or that, when granted, 

they will always be at the "top" of the zone of reasonableness. Rather, each applicant 

will, first, be required to justify a higher ROE under the required nexus test and, second, 

to justify where in the zone of reasonableness that return should lie. Furthermore, we 

recognize that some investors may desire up-front certainty regarding ROE before they 

invest in a particular project. Because our traditional ratemaking practice typically 

determines ROE in a hearing only after an investment is made and a facility is 

constructed, it does not provide such up-front certainty. We therefore clarify that we will 

entertain requests for a specific ROE determination in a petition for declaratory order. 

 5

 The Commission will apply a rule of reason with respect to what is sufficient to 

meet the requirement of “demonstrable” risk or challenge. An applicant may provide 

specific evidence of a risk or challenge or a supported explanation of why it faces a 

particular risk or challenge. 
Docket No. RM06-4-001 -6- 

8. In this order, the Commission denies in part and grants in part the requests for 

rehearing and/or clarification. 

II. Background

9. Section 1241 of EPAct 2005 directed the Commission to establish, no later than 

one year after enactment of section 219, by rule, incentive-based (including performancebased) 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.6

 To that end, 

the Commission issued a Notice of Proposed Rulemaking (NOPR)7

 on November 18, 

2005 seeking comment on the Commission’s proposal to comply with section 219. In the 

NOPR, the Commission stated that the purpose of this rulemaking is to promote greater 

capital investment in new transmission capacity, recognizing that the need for capital 

investment in energy infrastructure is a national problem that requires a national solution. 

Inadequate transmission infrastructure results in transmission congestion that impedes 

competitive wholesale markets and impairs the reliability of the electric grid.8

 

 6

 16 U.S.C.A. 824s(a) (West Supp. 2006). 

7

 Promoting Transmission Investment Through Pricing Reform, Notice of 

Proposed Rulemaking, 70 Fed. Reg. 71409 (Nov. 29, 2005), FERC Stats. & Regs., 

Proposed Regs. ¶ 32,593 (2005). 

8

 Id. P 2. 
Docket No. RM06-4-001 -7- 

10. After considering the comments on the NOPR, the Commission issued its Final 

Rule on transmission investment incentives to address the need for transmission capacity. 

In the Final Rule, the Commission provided 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 Final Rule identified 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.9

 The Commission stated that the 

Final 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, 

incentives will be permitted only if the incentive package as a whole results in a just and 

reasonable rate.10 

 9

 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 1. 

10 Id. P 2. Also, in the Final Rule, the Commission agreed with comments that 

new transmission technologies will be adopted when they are cost effective. The 

Commission determined that incentives will be considered for advanced technologies 

through the same evaluation process as other technologies. The Commission declined to 

make generic determinations regarding the applicability of incentives to particular 

technologies. Rather, the Final Rule determined that 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. Id. P 288-93, 298-99. The Final 

Rule required 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 deployed or have not been deployed, an explanation of why 

(continued) 
Docket No. RM06-4-001 -8- 

III. Discussion

A. Procedural Matters

11. In response to the Final Rule, a number of parties submitted timely requests for 

rehearing and/or clarification. On August 22, 2006, the Attorney General of the State of 

Connecticut (Connecticut AG) filed a request for rehearing out of time, seeking to 

support and join in all aspects the New England Commissions’ request for rehearing. On 

September 21, 2006, International Transmission Company (International Transmission) 

filed an answer to SoCal Edison’s request for rehearing. 

12. Pursuant to Rule 713(b) of the Commission’s Rules of Practice and Procedure, 

18 C.F.R. § 385.713(b) (2006), we will deny the request for rehearing of the Connecticut 

Attorney General because it was filed more than 30 days after issuance of the Final 

Rule.11 Rule 713(d) of the Commission’s Rules of Practice and Procedure12 prohibits an 

answer to a request for rehearing. Therefore, we deny International Transmission’s 

answer to SoCal Edison’s request for rehearing. 

 

they were not deployed. Id. P 302. No party sought rehearing concerning the Final 

Rule’s determinations regarding advanced technologies. 

11 We note, however, that the Connecticut Attorney General supports New 

England Commissions’ request for rehearing, which we address in this order. 

12 18 CFR 385.713(d) (2006). 
Docket No. RM06-4-001 -9- 

B. Statutory Arguments 

1. Rehearing Requests

13. APPA/NRECA argue that the Commission misinterpreted section 219 as requiring 

greater flexibility in ratemaking practices. According to APPA/NRECA, "incentives" are 

not necessary to attract capital because, under existing Supreme Court precedent, "a 

public utility's rate of return should also be sufficient to attract investment in new 

transmission facilities."13 APPA/NRECA therefore conclude that section 219 merely 

"codified the longstanding Commission and judicial interpretations of FPA section 205's 

requirement that rates be just and reasonable."14 

2. Commission Determination

14. We agree with APPA/NRECA that section 219 did not modify the requirement 

that rates be just and reasonable under section 205, but disagree that it did no more than 

restate that longstanding principle. Section 219 makes very clear that the Commission 

"shall establish, by rule, incentive-based (including performance-based) rate treatments" 

and that these rate treatments "shall . . . 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 

 13 APPA/NRECA at 12. 

14 Id. at 12-13. 
Docket No. RM06-4-001 -10- 

facilities; provide a return on equity that attracts new investment in transmission facilities 

(including related transmission technologies); 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 allow recovery of –

(A) all prudently incurred costs necessary to comply with mandatory reliability standards 

issued pursuant to section 215 and (B) all prudently incurred costs related to transmission 

infrastructure development pursuant to section 216."15 These words do far more than 

"codify" the just and reasonable standard; they command the Commission to use its 

discretion under section 205 to promote capital investment. Furthermore, Congress in 

section 219 even highlighted the importance of investment in economically or 

technologically efficient transmission infrastructure.16 Section 219 was enacted against 

the backdrop of a long decline in transmission investment that is imposing substantial 

costs – in congestion and service interruptions – on consumers. If Congress had deemed 

our existing practices sufficient to reverse this trend, there would have been little need to 

enact section 219. Section 219 does not simply "codify" our legal authority; it requires us 

to take affirmative action to promote new investment. Although the resulting rates must 

be just and reasonable, the Commission has significant discretion under section 205 in 

 15 16 U.S.C.A. 824s(a), (b)(1)-(4) (West Supp. 2006). 

16 See id. at 824s(a) and (b)(3). 
Docket No. RM06-4-001 -11- 

making that determination and section 219 provides clear direction that we use that 

discretion to promote new infrastructure, not simply maintain the status quo. 

15. While section 219 requires us to do more than maintain the status quo for 

transmission pricing, we recognize that our traditional ratemaking authority also requires 

us to establish a return on a public utility’s assets that is “reasonably sufficient to assure 

confidence in the financial soundness of the utility and should be adequate to maintain 

and support its credit and enable it to raise money necessary for the proper discharge of 

its public duties”17 and “should be sufficient to assure confidence in the financial 

integrity of the enterprise, so as to maintain its credit and to attract capital.”18 Thus, a 

base-level ROE sufficient to promote capital investment in transmission facilities 

historically has not been considered an “incentive,” but a requirement of establishing a 

just and reasonable rate.19 In this regard, we recognize that our responsibilities under 

 17 Bluefield Waterworks & Improvement Co. v. Pub. Serv. Comm’n of W. Va., 

262 U.S. 679, 693 (1923). 

18 FPC v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944). 

19 In contrast to a base-level ROE that reflects the financial and regulatory risks of 

an investment, an “incentive” has been more typically associated with specific basis point 

additions to a base ROE to satisfy discrete policy objectives. See, e.g., 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); Regional Transmission Organizations, Order No. 

2000, 65 FR 809 (Jan. 6, 2000), FERC Stats. & Regs. ¶ 31,089 (1999), order on reh’g, 

(continued) 
Docket No. RM06-4-001 -12- 

section 205 and our responsibilities under section 219 overlap in significant ways. We 

recognize that it may be difficult to meaningfully distinguish between an ROE that 

appropriately reflects a utility’s risk and ability to attract capital and an “incentive” ROE 

to attract new investment. Notwithstanding this difficult distinction, consistent with 

Congress’ direction in section 219, we are obligated to establish ROEs for public utilities 

that both reflect the financial and regulatory risks attendant to a particular project and that 

are sufficient to actively promote capital investment. We will do so within the zone of 

reasonableness, including above the midpoint where appropriate, to accomplish these 

regulatory responsibilities.20 This end-result ROE, whether characterized as an incentive 

pursuant to section 219 or as a base-level ROE consistent with the just and reasonable 

standard of section 205, will take into consideration financial and regulatory risks 

 

Order No. 2000-A, 65 FR 12088 (Mar. 8, 2000), FERC Stats. & Regs. ¶ 31,092 (2000), 

aff’d sub nom. Pub. Util. Dist. No. 1 of Snohomish County, Washington v. FERC, 272 

F.3d 607 (D.C. Cir. 2001) (Order No. 2000). Section 219 addresses both situations. In 

addition to requiring the Commission to establish, by rule, incentive rate treatments to 

promote transmission investment generally, section 219 also requires the Commission to 

establish incentive-based rates to encourage transmission technologies and other 

measures to increase the capacity and efficiency of existing transmission facilities. Thus, 

Congress intended for us to establish an ROE sufficient to reflect financial and regulatory 

risks and also to consider discrete ROE incentives for, among other things, participation 

in transmission organizations, projects with particular benefits to reliability or reducing 

congestion, new technologies and efficiency enhancements. 

20 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 93. 
Docket No. RM06-4-001 -13- 

attendant to the project and thereby satisfy Congress’ direction that the Commission 

“provide a return on equity that attracts new investment in transmission facilities . . . .”21

C. Nexus Requirement

16. In the Final Rule, the Commission stated that the applicant must demonstrate that: 

(1) 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; (2) there is a nexus between the incentive sought and the investment being 

made; and (3) the resulting rates are just and reasonable.22 The Commission stated that 

an applicant is not required to show that, but for the incentives, the expansion would not 

occur because Congress did not require such a showing. Nevertheless, the Commission 

maintained that it will 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.23 

1. Rehearing Requests

17. Industrial Consumers oppose allowing applicants to request multiple incentives, 

arguing that the Commission erred by determining that section 219 does not require 

applicants to demonstrate a relationship between an incentive proposal and transmission 

 21 16 U.S.C.A. 824s(b)(2) (West Supp. 2006). 

22 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 2, 26. 

23 Id. P 26, 48. 
Docket No. RM06-4-001 -14- 

investment.24 According to Industrial Consumers, the just and reasonable requirements 

of section 219(d) require that incentive rates must be based on a showing that there is a 

relationship between increased rates and the attraction of new capital.25 They assert that 

customers should not be forced to pay for incentives unless those incentives are actually 

necessary to deliver additional transmission capacity. Therefore, Industrial Consumers 

claim that contrary to the Commission’s conclusion, section 219 does not authorize the 

Commission to depart from judicial precedent on just and reasonable incentive rates.26 

Further, to the extent that the Commission relies on non-cost factors in determining just 

and reasonable incentive rates, the Commission must specify the nature of the relevant 

non-cost factors and offer a reasoned explanation of how the factors justify the resulting 

rates.27 Industrial Consumers contend that the reasoned explanation must calibrate the 

relationship between increased rates and the attraction of new capital, ensure that the 

increase is in fact needed, and is no more than needed to accomplish the objective.28 

18. APPA/NRECA also argue that applicants must demonstrate a need for the 

incentive rate treatments and make a showing sufficient for the Commission to find that a 

 24 Industrial Consumers at 3-7. 

25 Id. at 4, citing Farmers Union Cent. Exch. v. FERC, 734 F.2d 1486, 1503 (D.C. 

Cir. 1984) (Farmers Union). 

26 Id. at 5. 

27 Id. at 6-7 

28 Id.
Docket No. RM06-4-001 -15- 

particular incentive rate treatment “is in fact needed and no more than is needed” under 

the FPA and the Administrative Procedure Act.29 APPA/NRECA consider the nexus 

requirement to be inadequate because it fails to require applicants to show that a 

particular rate treatment is actually a lawful incentive under sections 205 and 219 of the 

FPA.30 They assert that under the nexus requirement, an applicant could show a 

sufficient rational relationship merely by claiming that granting the incentive rate 

treatment will make the investment more profitable and thus more attractive to 

investors.31 TDU Systems repeat these points and claim that the nexus requirement will 

have no effect on the granting or denying of incentive applications unless the 

Commission provides concrete examples of categories of asserted relationships between 

proposed incentives and facilities that will not satisfy the nexus requirement. They also 

do not consider the nexus requirement to be a reasonable substitute for a cost-benefit 

analysis.32

19. Likewise, TAPS argues that the nexus requirement is unduly vague because it fails 

to clearly require a causal connection between the incentive and consumer benefits. 

TAPS asserts that the nexus requirement should test whether a requested incentive would 

 29 5 U.S.C. 556 (2000). 

30 APPA/NRECA at 22. 

31 Id. at 23, citing Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 91, 117, and 

133. 

32 TDU Systems at 19-20. 
Docket No. RM06-4-001 -16- 

reasonably be expected to cause either a net decrease in delivered power costs even after 

considering incentive-increased transmission costs, or, where the expected net effect on 

delivered power costs is an increase, reliability gains that make that increase 

worthwhile.33 To remedy the alleged deficiencies of the nexus requirement, TAPS 

proposes that the nexus requirement be revised to provide: “that the incentive sought is 

designed to result in those facilities being invested in, completed, and placed into

service.”34 TAPS also recommends that the rule be amended to explicitly retain a 

reasonable calculation test, so that the Commission can determine which incentives return 

net consumer benefits and will be able to verify the accuracy of its prediction that 

granting incentives will spur increased investment.35

2. Commission Determination

20. Petitioners raise two related objections to the nexus requirement: (i) that it is too 

vague and therefore will be too easy to satisfy, and (ii) because it is not sufficiently 

rigorous, a different standard should be adopted. We address each in turn. 

21. The required nexus test requires an applicant to demonstrate that the incentives 

being requested are " tailored to the risks and challenges faced" by the project.36 By this 

 33 TAPS at 8-9. 

34 Id. at 11. 

35 Id. at 16, citing City of Charlottesville v. FERC, 661 F.2d 945, 955 (D.C. Cir. 

1981). 

36 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 26. 
Docket No. RM06-4-001 -17- 

we mean that the incentive(s) sought must be tailored to address the demonstrable risks 

and challenges faced by the applicant in undertaking the project.37 The required nexus 

test therefore satisfies the Industrial Consumers request that there be a relationship 

between the rate treatments sought and the attraction of new capital.38 It also satisfies 

TAPS' request that "the incentive sought is designed to result in" new facilities being 

constructed.39 We disagree with TAPS and APPA/NRECA, however, that the test is 

designed to be lenient or that it will necessarily be satisfied in every case. As we 

indicated in the Final Rule, "[n]ot 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."40 In evaluating whether the applicant 

has satisfied the required nexus test, the Commission will examine the total package of 

incentives being sought, the inter-relationship between any incentives, and how any 

requested incentives address the risks and challenges faced by the project. 

 37 We also note that the Commission retains its discretion to provide policy-based 

incentives. As the courts have said, even prior to our new authority in section 219, the 

Commission’s incentive rate determinations “involve matters of rate design . . . [and] 

policy judgments [that go to] the core of [the Commission’s] regulatory responsibilities.” 

Maine Public Utilities Commission v. FERC, 454 F.3d 278, 288 (D.C. Cir. 2006). See 

also Permian Basin Area Rate Cases, 390 U.S. 747 (1968) (Permian). 

38 Industrial Consumers at 4. 

39 TAPS at 11. 

40 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 26. 
Docket No. RM06-4-001 -18- 

22. TDU Systems complain that we did not provide "concrete examples" of showings 

that would either satisfy or fail the nexus test. Although that was not the purpose of the 

Final Rule – the purpose was to enunciate the criteria to be applied in individual cases – 

we did provide certain illustrations. For example, we emphasized the need for incentives 

for new transmission projects that can integrate new generation and load and thereby 

improve reliability and reduce congestion: 

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 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.[41] 

We also emphasized that "this does not mean that every new transmission investment 

should receive a higher return than otherwise would be the case. For example, routine 

 41 Id. P 25. 
Docket No. RM06-4-001 -19- 

investments to meet existing reliability standards may not always ..., qualify for an 

incentive-based ROE."42 

23. The Commission reaffirms that the most compelling case for incentives are new 

projects that present special risks or challenges, not routine investments made in the 

ordinary course of expanding the system to provide safe and reliable transmission 

service. We therefore reject the arguments of EEI and Southern Companies that such 

routine investments should be treated the same, for purposes of applying the required 

nexus test, as new projects that present special risks or challenges.43 

24. We also believe that the guidance provided in the Final Rule is sufficient. The 

purpose of the Final Rule was to establish criteria to be applied in individual cases, not to 

provide an exhaustive list of situations where incentives will be granted or denied. The 

decision whether to grant or deny incentives to a particular project is appropriately the 

subject of an individual rate application (or declaratory order) where the Commission can 

evaluate whether the applicants have fully supported any incentive rate treatments being 

sought. 

25. We now turn to the alternative tests advocated by petitioners, discussing the "but 

for" test in this section and the "cost-benefit" test in the following section. The Final 

Rule rejected a "but for" test as inconsistent with Congressional intent in enacting section 

 42 Id. P 27. 

43 See infra P 52. 
Docket No. RM06-4-001 -20- 

219.44 We reaffirm that finding here. In doing so, we emphasize that both the required 

nexus test and the "but for" test share one thing in common: their common objective is to 

ensure that incentives are not provided in circumstances where they do not materially 

affect investment decisions. They differ sharply, however, in the means by which they 

seek to achieve that objective. The "but for" test requires an applicant to show that a 

facility would not be constructed unless the incentive is granted. We reject that test 

because it erects an evidentiary hurdle that could only, in very rare cases, be satisfied. 

There are many impediments to investing in new transmission, including siting concerns, 

financing challenges, rate recovery concerns, etc. It is therefore unreasonable to expect 

or require an applicant to show that a facility could not be constructed "but for" the 

removal of a single impediment – e.g., increased cash flow through 100 percent 

construction work-in-progress (CWIP) or an enhanced ROE. This test could rarely, if 

ever, be satisfied, particularly given that incentives are ordinarily sought before

investment decisions are made and, hence, before any siting impediments are even 

confronted. 

26. The Commission therefore reaffirms its rejection of the "but for" test as the 

appropriate test for applying section 219. It would erect a barrier that is nearly 

impossible to meet and is thereby fundamentally incompatible with Congressional intent 

in enacting section 219. In enacting EPAct 2005, Congress plainly understood that there 

 44 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 48. 
Docket No. RM06-4-001 -21- 

are many impediments to new transmission investment. Congress therefore took a 

variety of actions to address that problem, including giving the Commission backstop 

siting authority, requiring that entities have long-term transmission rights to support new 

investment and, in section 219, providing appropriate rate incentives. We decline to 

render section 219 essentially an empty letter by requiring the demonstration of a 

negative – that absent an incentive rate treatment, under no circumstance would a 

transmission project possibly be built. This would be directly contrary to the intent of 

Congress to encourage the construction of needed transmission. 

27. We will grant rehearing, however, in one respect. The Final Rule states that the 

nexus test is to be applied separately to each incentive, rather than to the package of 

incentives as a whole. We agree that this approach fails to protect consumers where an 

applicant seeks incentives that both reduce the risk of the project and offer an enhanced 

ROE for increased risk. Even though the applicant no longer has to apply the nexus 

requirement separately to each incentive, the applicant will be required to demonstrate 

that the total package of incentives is tailored to address the demonstrable risks or 

challenges faced by the applicant. In presenting a package to the Commission, applicants 

must provide sufficient explanation and support to allow the Commission to evaluate 

each element of the package and the interrelationship of all elements of the package. If 

some of the incentives would reduce the risks of the project, that fact will be taken into 

account in any request for an enhanced ROE. We are revising § 35.35(d) to reflect this 

clarification. 
Docket No. RM06-4-001 -22- 

D. Cost-Benefit Analysis

28. In the Final Rule, the Commission adopted the proposal in the NOPR not to 

require applicants for incentive-based rate treatments to provide cost-benefit analyses. 

The Commission noted that courts have recognized that the Commission may consider 

non-cost factors in its ratemaking decisions.45 Therefore, the Commission stated that it 

may consider non-cost factors as well as cost factors and that it will consider the justness 

and reasonableness of any proposal for incentive rate treatment in individual proceedings. 

1. Rehearing Requests

29. TDU Systems and APPA/NRECA contend that the Final Rule’s failure to require 

that incentive rates be justified by a cost-benefit analysis is inconsistent with sections 205 

and 219 of the FPA. They assert that the Commission needs the information in the costbenefit analysis to determine whether a particular incentive rate is just and reasonable, i.e. 

whether its cost is outweighed by the benefits customers will receive.46 APPA/NRECA 

also contend that the Commission has no basis for concluding that a particular incentive 

provides consumers with a net benefit, as required under section 219(a), without a costbenefit analysis.47 TDU Systems also point out that the Commission and affected 

 45 Id. P 65, citing Permian, 390 U.S. 747, 815 (1968); Pub. Utils. Comm’n of Cal. 

V. FERC, 367 F.3d 925, 929 (D.C. Cir. 2004) (CPUC v. FERC); Maine Pub. Utils. 

Comm’n. v. FERC, 454 F.3d 278, slip op. at 19 (D.C. Cir. 2006) (Maine PUC v. FERC). 

46 APPA/NRECA at 26; TDU Systems at 11. 

47 APPA/NRECA at 26-27. 
Docket No. RM06-4-001 -23- 

customers must have the information necessary to distinguish between proposed projects 

that would benefit customers a great deal and proposed projects that would benefit 

customers minimally if at all.48 Further, in considering non-cost factors, these parties 

argue that the Commission cannot make a reasoned decision about the appropriateness of 

non-cost factors in approving an incentive rate without first knowing the costs and 

benefits of the incentive rate.49 They assert that intervenors also need this information to 

evaluate the impact of the rate proposal on them and to understand how much the 

applicant is relying on non-cost considerations. Moreover, APPA/NRECA contend, if 

the applicant is not required to present any evidence that consumers obtain net benefits 

from an increase in their transmission rates, the Commission cannot strike a fair balance 

between the financial interests of the regulated company and the relevant public interests, 

both existing and foreseeable.50 Further, TDU Systems and APPA/NRECA state that the 

plain language of section 219 demonstrates that Congress’ intent is to promote only 

efficient investment, investment that benefits consumers. They assert that Congress’ 

unqualified adoption in section 219(d) of the statutory just and reasonable standard 

demands a cost-benefit analysis. 

 48 TDU Systems at 12. 

49 Id. at 15; APPA/NRECA at 27. 

50 APPA/NRECA at 29, citing Farmers Union, 734 F.2d at 1502 . 
Docket No. RM06-4-001 -24- 

30. TDU Systems and APPA/NRECA also argue that elimination of the cost-benefit 

analysis will be harmful to customers because of the two-stage application procedure.51 

They assert that applicants should be required to provide the Commission and customers 

with all relevant facts concerning costs and benefits at the petition for declaratory order 

stage, where the applicant’s right to the incentive will be decided, because the Final Rule 

precludes relitigation of these issues in the later section 205 proceeding.52 They state that 

the interested parties must have the information needed to raise specific issues as to 

whether the likely customer benefits of the project justify the likely costs of the 

incentives to be awarded. They also argue that without a rigorous cost-benefit analysis at 

the initial stage, the benefits that formed the Commission’s initial approval would be so 

amorphous that there would be little objective data for the Commission to assess in its 

periodic progress assessments. Allowing recipients of incentives to fix the term of their 

incentive-rate awards in the absence of a rigorous initial cost-benefit analysis would serve 

only to perpetuate the contravention of the statutory just and reasonable standard, 

according to APPA/NRECA. TDU Systems agree, stating that they can perceive no 

 51 Under the Commission’s two-stage application procedure, an applicant can 

petition for a declaratory order seeking an incentive-based rate treatment for its project. 

After the Commission issues the declaratory order, the applicant must seek to put the 

rates into effect through a separate single-issue or comprehensive section 205 filing. See

Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 76-78. 

52 TDU Systems at 12-14; APPA/NRECA at 29-30. 
Docket No. RM06-4-001 -25- 

justification for allowing incentive awardees to define the duration of their own awards in 

the absence of a rigorous initial cost-benefit analysis. 

31. Industrial Consumers argue that the Commission impermissibly departed from 

Order No. 2000,53 without a reasoned explanation, by eliminating the cost-benefit 

analysis. They assert that the Commission wrongly concluded that the cost-benefit 

analysis is not necessary because customers will be protected by the Commission’s 

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

all rates be just and reasonable and not unduly discriminatory or preferential.54 They 

state that in Order No. 2000, the Commission required applicants for innovative 

transmission rate treatments to demonstrate how the investment in the transmission 

system benefits consumers and to provide a cost-benefit analysis, including rate impacts. 

Such a disconnect with Commission precedent reflects an absence of reasoned decision 

making.55

32. Further, Industrial Consumers contend that, to successfully balance the competing 

interests of providing incentives to encourage transmission investment and its statutory 

responsibility of protecting customers from excessive rates, the Commission must 

narrowly tailor incentives that require a close calibration between the increased rates and 

 53 Order No. 2000, supra note 19. 

54 Industrial Consumers at 7-8. 

55 Id. 
Docket No. RM06-4-001 -26- 

a corresponding level of benefits. Without such a close calibration between the proposed 

incentive rates and the anticipated benefit, the Commission risks thwarting the just and 

reasonable requirements of the FPA. Thus, according to Industrial Consumers, applicants 

for incentive treatment must be required to demonstrate that incentives will actually yield 

a positive return in the form of otherwise unachievable reliability improvements and 

reduced congestion costs.56 

33. SMUD contends that the nexus requirement is not sufficient to justify eliminating 

the cost-benefit analysis required under Order No. 2000. It asserts that there is no 

connection between the lawfulness of non-cost factors and the elimination of the costbenefit test for incentive rates. SMUD states that, while the Commission recognized the 

non-cost-based nature of incentive ratemaking in the 1992 Policy Statement, the 

Commission, nonetheless concluded that benefits to consumers must be quantifiable, and 

SMUD asserts that nothing in section 219 alters the requirement for a cost-benefit test.57 

Further, SMUD contends that the nexus test results in a lower burden of proof for 

applicants without explaining why a cost-benefit test is no longer necessary. SMUD 

requests the Commission to clarify that the incentives for new construction to reduce 

congestion will be capped so that the delivered cost of power to the consumer is lower 

 56 Id. at 10. 

57 SMUD at 2, citing 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) (1992 Policy Statement). 
Docket No. RM06-4-001 -27- 

than what it was before the facilities were constructed, thereby ensuring that consumers 

will not pay incentive rates for congestion-reducing construction unless the result is a 

lower cost of delivered power. SMUD also requests clarification that incentives for 

reliability upgrades will not reward the construction of more transmission capacity than is 

reasonably necessary to meet new reliability standards, thereby ensuring that incentive 

payments for reliability improvements will not be awarded for more than what is needed 

to ensure reliability. 

34. TAPS asserts that the Commission’s authority to award above-cost incentives has 

always turned on whether the incentive’s cost is outweighed by the benefits customers 

will receive.58 TAPS advocates that the Final Rule be amended to explicitly retain a 

reasonable calculation test that analyzes which incentives spur increased investment, and 

require the Commission to use this test to replace the cost-benefit requirement. 

2. Commission Determination

35. The Commission reaffirms the decision not to adopt a "cost-benefit" analysis for 

four principal reasons. 

36. First, the arguments in favor of a cost-benefit analysis start from the premise that 

our traditional approach to setting transmission rates is fully sufficient to attract new 

transmission investment in all cases. This premise cannot be squared with section 219. 

As discussed above, section 219 was enacted to counteract a long decline in transmission 

 58 TAPS at 9, citing CPUC v. FERC, 367 F.3d at 929. 
Docket No. RM06-4-001 -28- 

investment. Its provisions are mandatory, not permissive, and they proceed from the 

premise that the Commission must use its full discretion under section 205 to "promot[e] 

capital investment." It did not, as noted above, simply codify the status quo; it required 

the Commission to pass a new rule adopting incentive-based rate treatments. 

37. These facts readily distinguish the Final Rule from prior instances where the 

Commission required a cost-benefit analysis.59 None of those policies was adopted in 

response to a Congressional directive to use the Commission's discretion under section 

205 to address a national problem – the decline in transmission investment that is 

threatening reliability and imposing billions of dollars in congestion costs on consumers. 

38. Second, petitioners fail to recognize that applicants will be required to show that 

all rates are just and reasonable under section 205. For example, any ROE will remain 

within the range of reasonable returns. Further, many of the incentives described in the 

Final Rule only change the timing of cost recovery (e.g., 100 percent CWIP), not the 

level of cost recovery. Others reduce the risks of investment (e.g., abandoned plant 

 

59 Order No. 2000 required as a condition for any innovative transmission rate 

treatment that the applicant demonstrate “a cost-benefit analysis, including rate impacts.” 

18 CFR 35.34(e)(ii) (2006). The Commission notes that in the 6 years since Order No. 

2000 was issued, we have not received a single application seeking any of the innovative 

rate treatments that were provided for in that order. We believe that the requirement of a 

cost benefit analysis was perceived as an insurmountable hurdle which inhibited the 

utilities from seeking innovative rate treatments. Accordingly, in developing incentive 

rate treatments under section 219, the Commission expressly deleted the requirement for 

a cost-benefit analysis. 
Docket No. RM06-4-001 -29- 

recovery), rather than changing the cost levels. We reiterate that each of the incentives 

adopted by the Final Rule is fully consistent with our responsibility to ensure that rates 

are just and reasonable under section 205. 

39. Third, those advocating a cost-benefit analysis fail to recognize that the courts 

have held that the Commission may consider non-cost factors in setting rates.60 Our 

authority to consider non-cost factors applies equally in the development of incentive 

rate-treatments.61

40. Finally, although the Commission is rejecting a cost-benefit analysis for the 

reasons stated above, applicants will nonetheless be required, as discussed above, to 

demonstrate the required nexus between the incentive being sought and the investment 

being made. This requirement will ensure that incentives are granted only where the 

incentives are tailored to address the demonstrable risks or challenges faced by the 

applicant. 

E. Rebuttable Presumptions

41. In the Final Rule, the Commission adopted a set of processes that, if an applicant 

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

transmission incentives. First, it created a rebuttable presumption that an applicant has 

 60 See Permian, 390 U.S. 747 at 791-2; CPUC v. FERC, 367 F.3d 925 at 929. 

61 Maine PUC v. FERC, 454 F.3d at 289 (“particularly in view of the 

[Commission’s] authority to consider non-cost factors in setting rates, the State 

Commissions’ position on calibration demands too much”). 
Docket No. RM06-4-001 -30- 

met the requirements of section 219 if that project 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.62 Second, the Commission stated that 

regional planning processes can provide an efficient and comprehensive forum for 

evaluating transmission investments’ qualifications under section 219 by looking at a 

variety of options across a large geographic footprint. For example, such a process has 

the ability to determine whether a given project is needed, whether it is the better 

solution, and whether it is the most cost-effective option among other alternatives.63 The 

Commission also adopted a rebuttable presumption that an applicant has met the 

requirements of section 219 if a proposed project is located in a NIETC or has received 

construction approval from an appropriate state commission, agency or state siting 

authority.64 The Commission also stated that “other applicants not meeting these criteria 

may nonetheless demonstrate that their project is needed to maintain reliability or reduce 

 62 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 58. 

63 Id. The Commission noted that the value of regional planning was expressly 

recognized 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 the region. See Preventing Undue Discrimination and 

Preference in Transmission Service, Notice of Proposed Rulemaking, 71 FR 32,536 (June 

6, 2006), FERC Stats & Regs., Preambles ¶ 32,603 at P 36 (2006) (OATT Reform 

NOPR). 

64 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 58. 
Docket No. RM06-4-001 -31- 

congestion by presenting [to the Commission] a factual record that would support such a 

finding.”65

1. Rehearing Requests

42. NARUC and TAPS contend that the Final Rule’s rebuttable presumption is not 

consistent with the statutory requirements of section 219. They state that there was no 

showing in the Final Rule that assessments in the regional planning processes satisfy the 

requirements of section 219 and there is no basis to assume that the criteria employed in 

regional planning processes utilize the criteria set out in section 219.66 Therefore, they 

argue that it cannot be reasonably presumed that every project that is subject to regional 

planning will benefit customers by ensuring reliability and reducing the cost of delivered 

power by reducing transmission congestion. NARUC further contends that incentives for 

using regional planning processes are inappropriate in view of the Commission’s 

proposal in the OATT Reform NOPR to require all jurisdictional public utilities to 

engage in regional planning.67 Under such a mandatory requirement, all projects will 

effectively qualify for the rebuttable presumption because all projects will, presumably, 

be included in approved regional plans.68

 65 Id. P 57. 

66 NARUC at 5-6; TAPS at 7-8. 

67 See OATT Reform NOPR, FERC Stats & Regs., Preambles ¶ 32,603 at P 36. 

68 NARUC at 6. 
Docket No. RM06-4-001 -32- 

43. APPA/NRECA, NARUC, TDU Systems, and TAPS argue that the rebuttable 

presumption for state approvals should be deleted because there is no legal or logical 

basis to presume that projects falling into this category will ensure reliability or reduce 

the cost of delivered power.69 They assert that the criteria applied by the state may not 

resemble the criteria that the Commission is required to apply under section 219 of the 

FPA. They argue that state commissions are mainly concerned with protecting retail 

customers in their respective states and state authorities apply state laws to constructionpermit applications. Accordingly, states are not focused on public utility wholesale 

customers who may be in other states, or ensuring reliability or reducing transmission 

congestion. Therefore, APPA/NRECA assert that the Commission cannot delegate its 

responsibilities under section 219 to state authorities that may of necessity have a very 

different mission.70

44. NARUC also claims that projects receiving a designation as projects in NIETC 

should not receive a rebuttable presumption because such a designation, alone, cannot 

assure that the statutory prerequisites of section 219 have been satisfied when the criteria 

for NIETC designation do not mirror those set out for incentives under the statute.71 

 69 Id. at 7; TAPS at 6; APPA/NRECA at 37-39; TDU Systems at 25-27. 

70 APPA/NRECA at 38. 

71 NARUC at 7. 
Docket No. RM06-4-001 -33- 

45. Additionally, NARUC, APPA/NRECA, and TDU Systems claim that the scope of 

the rebuttable presumption is ambiguous and needs to be clarified. They state that it is 

not clear to which part of the three-part showing that the rebuttable presumption applies 

to.72 They state that the rebuttable presumption should only apply to the first part (ensure 

reliability or reduce the cost of delivered power by reducing transmission congestion) of 

the three-part showing because the only way an applicant can appropriately satisfy the 

statutory requirements of FPA section 219 is to demonstrate on the record that the project 

either ensures reliability or reduces the cost of delivered power and that the rates satisfy 

sections 205 and 206 of the FPA. Therefore, the applicant must still demonstrate with 

factual evidence that there is a nexus between the incentive sought and the investment 

being made and that the resulting rates are just and reasonable.73 APPA/NRECA also 

request the Commission to clarify that this interpretation applies to both section 205 

filings and petitions for declaratory order.74 TAPS contends that the rebuttable 

presumptions conflict with the Commission’s intended limitations on the receipt of 

incentives, such as routine investments, which may be included in a regional plan and 

 72 Under section 35.35(d) of the regulatory text, an applicant for incentive rates is 

required to make a three-part showing that: (1) 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; (2) there is a nexus between 

the incentive sought and the investment being made; and (3) resulting rates are just and 

reasonable. 18 CFR 35.35(d) (2006). 

73 APPA/NRECA at 35-36; NARUC at 7-8; TDU Systems at 24-25. 

74 APPA/NRECA at 36. 
Docket No. RM06-4-001 -34- 

required to receive state siting approval prior to construction, but may not always qualify 

for an incentive-based ROE.75

2. Commission Determination

46. We will grant rehearing and clarification in part. The Commission created the 

rebuttable presumption for the purpose of avoiding duplication in determining whether a 

project maintains reliability or reduces congestion. We do not wish to repeat the work of 

state siting authorities, regional planning processes, or the DOE in evaluating these 

issues. However, we agree with NARUC that if such processes do not in fact include 

such a determination, a rebuttable presumption would not be appropriate. Accordingly, 

we grant rehearing and are modifying § 35.35 in three ways. 

47. First, we agree with NARUC that the NIETC process will not necessarily 

determine that every transmission project within a designated corridor will meet the 

section 219(a) requirements, nor is DOE required to make such a determination. 

However, we do not believe it is necessary to retain this particular rebuttable presumption 

in our regulations because any project which is proposed in a NIETC will of necessity 

have to go through a state or federal siting process. If an applicant’s proposed project is 

within a NIETC, we expect that it will be sited in most instances by the appropriate state 

siting authority and the applicant will be able to rely on the state siting rebuttable 

presumption for meeting the requirements of section 219(a). In those cases where 

 75 TAPS at 8, citing Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 94. 
Docket No. RM06-4-001 -35- 

projects within a NIETC are sited by this Commission pursuant to our new authority in 

section 216, an applicant may rely on our findings in our siting process for meeting the 

requirements of section 219(a).76 Thus, applicants with projects in a NIETC have an 

opportunity to rely upon the appropriate siting processes to meet the requirement that a 

project ensure reliability or reduce the cost of delivered power by reducing transmission 

congestion, and we need not include the NIETC process as a rebuttable presumption.77 

48. We are amending our regulations to provide that an applicant that obtains 

Commission authorization under section 216 to site electric transmission facilities in 

interstate commerce shall be deemed to satisfy the requirements of section 219(a).78 

 76 As stated in section 216, the Commission may exercise its new siting authority 

if inter alia it finds that the construction or modification of the facilities “significantly 

reduce transmission congestion in interstate commerce and protects or benefits 

consumers.” Since the Commission is required to find that a project reduces transmission 

congestion before it can authorize the siting of a transmission facility within a NIETC, 

such facilities necessarily satisfy the requirement of section 219(a) and these regulations. 

77 While DOE is not required to determine whether all projects within a NIETC 

meet the pre-requisites of section 219, we anticipate that DOE is likely to consider 

whether transmission projects within these corridors ensure reliability or reduce the cost 

of delivered power by reducing transmission congestion. Thus, an applicant that does not 

rely upon a rebuttable presumption for meeting the pre-requisites of section 219 may 

nonetheless use the findings made by the DOE. Accordingly, the Commission will give 

due weight to the DOE’s determinations concerning the ability of transmission projects 

within a NIETC to ensure reliability or reduce the cost of delivered power by reducing 

transmission congestion. 

78 Section 216(b)(4). See also Regulations for Filing Applications for Permits to 

Site Interstate Electric Transmission Facilities, Order No. 689, 71 FR 69,440 at P 41 

(Dec. 1, 2006) (“The Commission will review the proposed project and determine if it 

reduces the transmission congestion identified in DOE’s study and if it will protect or 

(continued) 
Docket No. RM06-4-001 -36- 

49. Second, we will modify our regulations to require each applicant seeking to 

invoke the rebuttable presumption to explain in its filing how the applicable process 

(regional planning or state approval) in fact considered whether the project ensures 

reliability or reduce congestion. We continue to believe that, these approval processes 

will, in all likelihood, examine whether the project maintains reliability or reduces 

congestion. But in instances where this is not the case the applicant will bear the full 

burden of demonstrating such facts. 

50. Third, we also clarify that the rebuttable presumption applies only to the 

requirement that an applicant demonstrate, that a project is needed to ensure reliability or 

to reduce congestion. It does not apply to any other requirement in 18 C.F.R. § 35.35, 

such as the requirement, that the applicant demonstrate the required nexus between the 

incentive sought and the investment being made79 and that the resulting rates are just and 

reasonable in either the petition for declaratory order or section 205 filing. We will 

modify our regulations accordingly. 

F. ROE Sufficient to Attract Investment

51. In the Final Rule, the Commission adopted the NOPR’s proposal to allow, when 

justified, an incentive-based ROE to all public utilities (i.e., traditional public utilities and 

 

benefit consumers. It will investigate and determine the impact the proposed facility will 

have on the existing transmission grid and the reliability of the system”). 

79 We note that the Final Rule’s statement regarding routine investment cited by 

TAPS, applies to the nexus demonstration, and therefore there is no conflict between the 

rebuttable presumption and that statement. 
Docket No. RM06-4-001 -37- 

Transcos) for new investments in transmission facilities that benefit consumers by 

ensuring reliability or reducing the cost of delivered power by reducing congestion.80 By 

including this provision in the Final Rule, the Commission stated that it satisfied the 

requirement of section 219 to provide an ROE that attracts new investment in 

transmission facilities (including related transmission technologies). The Commission 

stated that it will provide ROEs at the upper end of the zone of reasonableness for 

transmission investments that meet the requirements of section 219. Further, the 

Commission clarified that it will continue to use the DCF analysis for ROE 

determinations.81 The Commission also noted that not every investment that increases 

reliability or reduces congestion will qualify for an incentive-based ROE. For example, 

routine investments may continue to be assessed under traditional ROE determinations 

because there is an obligation to construct them and high assurance of recovery of the 

related costs.82

1. Rehearing Requests

52. EEI and Southern Companies take exception to the statement in the Final Rule that 

“routine investments made to comply with existing reliability standards may not always 

 80 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 91. 

81 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. Id. P 92. 

82 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 94. 
Docket No. RM06-4-001 -38- 

qualify for an incentive-based ROE.”83 They argue that the statement discriminates 

against projects or upgrades that may be proposed to address reliability concerns, and 

therefore the statement should be deleted.84 Southern Companies emphasize that the 

statutory requirement under 219 makes no distinction between routine or non-routine 

status; therefore, regardless of status, an investment that promotes reliability should be 

entitled to incentive rate treatment. In that respect, Southern Companies request the 

Commission to confirm that all reliability-related investments qualify for incentive-based 

ROEs.85 Furthermore, Southern Companies request the Commission to clarify that a 

single incentive-based ROE should apply to all, not just new, transmission investment.86

53. TDU Systems contend that the Commission should reconsider its commitment to 

grant incentive applicants an ROE at the upper end of the zone of reasonableness. 

Specifically, TDU Systems claim that the Commission may have difficulty handling all 

the rate filings that seek extremely high ROEs because of the two-stage process. They 

 83 Id. 

84 EEI at 11; Southern Companies at 3. 

85 Southern Companies at 4. 

86 Southern Companies argue that section 219(b)(2) should be read to require the 

Commission to re-examine its ratemaking methods and revise it current ROE policies for 

all transmission investment, and that the base ROE must be sufficient to attract new 

investment. It contends that Congress did not state that the Commission shall provide a 

return on equity for new investment in transmission. Instead, section 219(b)(2) states 

that the Commission shall “provide a return on equity that attracts new investment in 

transmission.” See Id. at 5 (emphasis provided by commenter). 
Docket No. RM06-4-001 -39- 

contend that the Commission is placing too much reliance on its ability to protect 

consumer interests in the second stage, section 205 review, and recommends that the 

Commission relieve some of the pressures by giving incentive applicants a more specific 

message that the incentives have limits.87 APPA/NRECA also assert that the 

Commission has not explained why such an increase in allowed ROEs is, or could be, 

either necessary to attract capital or otherwise just and reasonable and that the rule does 

not balance investor and consumer interests in setting incentive ROEs.88 Accordingly, 

these parties assert that the Commission should permit incentives only if the package as a 

whole results in a just and reasonable rate. In so doing, they argue, the Commission 

should disavow any intent to allow ROEs near the top of the zone of reasonableness and 

ensure that companies in the proxy group with ROEs at the top of the zone of 

reasonableness do not become the basis for determining the zone, particularly to the 

extent incentive ROEs become the base case in future DCF analyses. 

54. Similarly, TAPS argues that the Commission must be prepared to apply a much 

stricter scrutiny to the composition of the proxy group that determines the range of the 

zone of reasonableness to the extent the Commission continues to declare in favor of 

 87 TDU Systems at 27-29. 

88 APPA/NRECA at 9, 47. 
Docket No. RM06-4-001 -40- 

rates set at the top of a range that has not yet been established.89 Also, TAPS 

recommends that the Commission modify its methodology for proxy results by first 

averaging the two results per proxy company so that there is one, average result per proxy 

company, as it does in gas cases,90 thereby providing a more defensible basis for just and 

reasonable returns. TAPS requests the Commission to clarify that it will ensure that the 

top of the range does not become a self-escalating spiral with the highest proxy result 

reflecting an investor expectation that the proxy itself will garner above-cost incentive 

profits.91

55. Southern Companies consider the Commission’s continued reliance on DCF 

analysis in the Final Rule to be contrary to Congressional intent and policy.92 

 89 TAPS explains that many transmission owners will request rates at the high end 

of the zone of reasonableness and that the main restraint on transmission rates will be the 

ceiling that is set by the placement of the top of the zone of reasonableness. The zone has 

been defined by taking a sample group that includes a large number of proxy companies 

and calculating two data points per proxy. Each pair of points represents the extreme 

values for each company. The zone of reasonableness is often characterized as reaching 

up to the higher data point for the most extreme company in the proxy set. Thus, when 

the top of the range sets the return, it becomes critical to ensure that every company 

included in the proxy group very closely resembles the utility whose return is being 

capped, i.e., its capital structure, business risk, financial risk, and associated capital costs. 

See TAPS at 18-22. 

90 Id. at 21, citing High Island Offshore System, L.L.C., 110 FERC ¶ 61,043, at P 

148 (2005). 

91 Id. at 22. 

92 According to Southern Companies, section 219’s requirement that the 

Commission provide ROEs that are sufficient to attract new transmission investment is 

evidence of Congress’ conclusion that the Commission’s current ROE methodology is 

(continued) 
Docket No. RM06-4-001 -41- 

Accordingly, Southern Companies request the Commission to clarify that it will allow the 

use of additional ROE estimation methodologies93 because these methodologies will 

better ensure that an entity is ensured a reasonable rate of return. Southern Companies 

assert that failure to consider the results of more than one methodology, although there 

are other sound methods, constitutes arbitrary and capricious decision making.94 

Furthermore, Southern Companies consider the Final Rule’s refusal to recognize the 

flaws in the current DCF analysis to be arbitrary and capricious and its finding that the 

DCF analysis yields just and reasonable results to be in error, particularly in light of the 

fact that the DCF analysis drives a utility’s stock price to its book value while market 

values exceed book values by approximately 2.47 to 1 as of December 31, 2005 and the 

constant-growth DCF model often produces divergent and meaningless results.95

56. Southern Companies also argue that ROE adders should be provided to all new 

transmission construction. They assert that section 219 directs the Commission to 

promote investment of all facilities and therefore the Commission’s determination in the 

 

not producing adequate results. Therefore, the Commission should construe section 

219(b)(2) as a mandate from Congress to re-examine its traditional ratemaking policies. 

Southern Companies at 5-6. 

93 Such methodologies include the risk premium approach, the capital asset pricing 

model and the comparable earnings approach. Id. at 7. 

94 They state that using multiple methodologies recognizes that no single approach 

can accurately predict an appropriate ROE level so as to satisfy the constitutional and 

statutory requirements. Id. at 8. 

95 Id. at 11. 
Docket No. RM06-4-001 -42- 

Final Rule that it will not create specific ROE adders is contrary to EPAct 2005 and 

requiring applicants to go through a rate case prior to receiving any incentives would 

unnecessarily impede Congress’ stated goal of encouraging new transmission 

investment.96

57. The California Commission claims that the Commission did not engage in 

reasoned decision making in the Final Rule because it failed to consider risk assessment 

and did not address its arguments about the relative low risk of transmission investment.97 

It argues that the Commission failed to explain why transmission entities should be 

eligible for a higher ROE given the low risk associated with transmission investments. 

The California Commission states that transmission businesses have a low financial risk 

because they generate a steady revenue stream as a regulated monopoly. Also, among the 

three functions of an integrated utility’s electricity business, i.e. generation, distribution, 

and transmission, the transmission business carries the lowest risk.98 Further, the 

California Commission argues that the Commission did not consider the effect the 

multiple incentives created by the Final Rule will have on lowering the risk, such as 100 

percent recovery of CWIP before a transmission project is used and useful. Accordingly, 

 96 Id. at 18. 

97 California Commission at 7-10.

98 Id. at 8. 
Docket No. RM06-4-001 -43- 

it contends that above-average ROEs for transmission are not needed to effect new 

transmission facilities.99

58. New England Commissions argue that the Commission arbitrarily, capriciously, 

and without a reasonable factual foundation, determined that ROE incentives encourage 

investment and make transmission projects attractive.100 They state that the New England 

ROE proceeding in Bangor Hydro-Electric101 demonstrated that an enhanced ROE will 

not change transmission owners’ performance in any material respect, but will merely 

give them an unjust and unreasonable windfall. Accordingly, New England 

Commissions assert that the Commission’s finding that transmission incentives are 

necessary is not supported by the record in this rulemaking or in the Bangor HydroElectric proceeding.102 According to the New England Commissions, it is contrary to the 

directive in section 219(d) that rates be just and reasonable to dispense with any showing 

of need before awarding ROE incentives.103 New England Commissions requests the 

Commission to clarify that it will judge the justness and reasonableness of ROE adders in 

 99 The California Commission states that even without the high ROE incentive, 

California IOUs have planned and constructed numerous transmission facilities in the last 

10 years. Id. at 9. 

100 New England Commissions at 5. 

101 Bangor Hydro-Electric Co., 106 FERC ¶ 61,280 (2004). 

102 New England Commissions at 6-10. 

103 Id. at 12. 
Docket No. RM06-4-001 -44- 

New England based on the record in Bangor Hydro-Electric proceeding and specify in 

the rule that only a case-by-case evaluation can determine whether an ROE incentive will 

produce justifiable benefits. 

2. Commission Determination

59. We will grant rehearing and clarification in part on certain issues and deny 

rehearing on all other issues. 

60. We reject the argument of investor-owned utilities that ROE incentives be applied 

without regard to the nature of the facility being constructed or the risks associated with 

it. Specifically, the Commission reaffirms that the most compelling case for incentive 

ROEs are new projects that present special risks or challenges, not routine investments 

made in the ordinary course. We therefore reject the arguments of EEI and Southern 

Companies that such routine investments should be treated the same, for purposes of 

applying the nexus test, as new projects that present special risks or challenges. Although 

we will consider applications for ROE incentives for all projects, we reiterate that not all 

projects will be able to meet the nexus requirement. EEI and Southern Companies have 

provided no compelling reason why a routine investment made in the ordinary course 

should, as a general matter, receive an incentive ROE 

61. We also reject the argument that incentive ROEs should apply to existing 

transmission rate base that has already been built. The purpose of section 219 is to attract 

investment in transmission. Southern Companies have not provided any evidence that 

higher ROEs for transmission rate base that has already been built are necessary to ensure 
Docket No. RM06-4-001 -45- 

reliability or to reduce congestion; nor have they shown why such ROEs are necessary to 

attract new investment in transmission. 

62. We also reject the contentions of certain customer groups that incentive ROEs will 

"destabilize" the DCF methodology. First, as indicated above, all ROEs approved 

pursuant to section 219 will be within the range of reasonableness, as determined 

consistent with our precedents. Second, any incentive ROEs granted under 219 should 

have a minimal effect, if any, on the overall range of reasonableness derived from the 

appropriate proxy group. The DCF methodology uses proxy groups of entire companies, 

not individual transmission projects. In other words, the "cash flows" being measured in 

the DCF method are the cash flows of entire companies. These cash flows should not be 

significantly affected by an incentive return for any particular transmission project for 

one company within the proxy group. Moreover, to the extent there is any small effect on 

the overall range of reasonableness, it will appropriately reflect the substantial risks 

associated with constructing new transmission, as discussed above.104 

63. We also reject requests to cease our utilization of the DCF method. Inasmuch as 

the DCF method yields just and reasonable rates, as the Commission has recognized in 

numerous proceedings, we see no basis to require other methods for the evaluation of 

incentive applications. As we stated in the Final Rule, the Commission will consider on a 

 104 The Commission retains the discretion to adjust ROEs if we find that the results 

of a DCF analysis do not accurately reflect the risk of the applicant and its ability to 

attract capital. 
Docket No. RM06-4-001 -46- 

case-by-case basis whether the application of the traditional DCF analysis should be 

modified.105 

64. We also do not consider the process for approving incentive ROEs, i.e., setting a 

zone of reasonableness and a DCF analysis requirement, to be an unnecessary 

impediment to encouraging transmission investment. Generic adders, as recommended 

by Southern Companies, would still require the Commission to make a determination that 

the proposed ROEs are just and reasonable, and its findings would have to be based on 

reasoned decision-making. Therefore, the Commission necessarily would be required to 

establish a zone of reasonableness and a justification for the approved ROEs. 

65. Responding to the California Commission, the Final Rule explained the basis for 

its decision to provide an incentive ROE, based on the need to attract investment in the 

context of long-term industry underinvestment and the need to re-evaluate the balance of 

investor and ratepayer interests, and therefore has provided the reasons for its decisions. 

The Commission is not, in this rule, setting the incentive ROE, but rather leaves that 

determination to future proceedings that will authorize a unique ROE appropriate to the 

facts and circumstances of each applicant. It is in those proceedings that the California 

 105 We agree with TAPS that averaging each company’s low and high DCF return 

would result in a single average DCF result for each electric company, making it like the 

single DCF return for gas and oil pipelines, from which a median return on equity for the 

group can be calculated. While this is an acceptable method, we will not require use of 

that method in the Commission’s DCF analysis because that issue is beyond the scope of 

this proceeding and is more appropriately addressed in the individual application 

proceedings. 
Docket No. RM06-4-001 -47- 

Commission can raise its concerns regarding comparative returns within the energy 

industry and the specific characteristics of California utilities. However, we agree with 

the California Commission that utilities should consider the effect that certain incentives 

(e.g. CWIP in rate base, recovery of abandoned plant) may have on risk and that return 

on equity in the upper end of the zone of reasonableness may not be appropriate when 

combined with incentive rate treatments that lower overall risk. 

66. We do not address the issues raised by New England Commission with respect to 

the Bangor Hydro-Electric proceeding because they have been addressed in a recent 

Commission order and are now pending on rehearing.106

67. We will, however, grant clarification in part. Several petitioners express the fear 

that the Commission will routinely grant ROEs at the top end of the zone of 

reasonableness. Although the Commission has broad discretion to establish returns on 

equity anywhere within the zone of reasonableness, we must be careful in the manner in 

which we exercise this discretion. The Commission clarifies that we do not intend to 

grant incentive returns "routinely" or that, when granted, they will always be at the "top" 

of the zone of reasonableness. Rather, each applicant will, first, be required to justify a 

higher ROE under the revised nexus test and, second, to justify where in the zone of 

reasonableness that return should lie. In some instances, where the risks or challenges 

faced by a new investment are substantial, we may grant an ROE at the top end of the 

 106 Bangor Hydro-Electric Co., Opinion No. 489, 117 FERC ¶ 61,129 (2006). 
Docket No. RM06-4-001 -48- 

zone of reasonableness. However, we have no expectation of doing so in all cases or 

even routinely. 

68. We also provide clarification on the timing of an ROE determination. In most 

instances, an ROE determination occurs in a hearing that considers the justness and 

reasonableness of the costs of the investment for purposes of setting rates under section 

205. In that hearing, the overall range of reasonableness would be established, as well as 

a determination of where within that range the ROE should be set. If the Commission 

granted a request for an incentive ROE at the upper end of that range in a petition for 

declaratory order, the hearing would establish where in the upper end the ROE would fall 

– whether at the top end or at a different point in the upper end of the range. The 

Commission would then review any determination by an administrative law judge on that 

issue. 

69. We recognize, however, that our hearing procedures for determining ROE can 

create uncertainty for investors. Under traditional ratemaking processes, the rates for a 

particular project, including the ROE for that project, are determined only after an 

investment decision is made and the facility is constructed. This may provide a 

disincentive to new investments that are sensitive to our ROE determinations. Although 

our processes are designed to provide a just and reasonable return, we recognize that 

there can be significant uncertainty as to the ultimate return because of the uncertainties 

associated with administrative determinations (e.g., selection of the proxy group, changes 
Docket No. RM06-4-001 -49- 

in growth rates, etc.) This can itself constitute a substantial disincentive to new 

investment. 

70. Recognizing this, we will clarify the approach adopted in the Final Rule. We will 

continue to allow applicants to request, in a petition for declaratory order, an ROE that is 

at the upper end of the zone of reasonableness and, in such instances, the ultimate ROE 

will be determined in the hearing process. However, if an applicant desires up-front 

certainty of the ROE it will receive, we clarify that we also will consider requests for -

declaratory orders that set the ROE for a particular project, and that include the 

appropriate support for the ROE, including, for example, a DCF analysis. An applicant 

seeking to use this process will have to meet the required nexus requirement, such as by 

showing that an up-front ROE determination is important for its investment decision. An 

applicant seeking such an up-front ROE determination also may request an ROE at the 

upper end of the zone of reasonableness; however, the fact that an up-front ROE 

determination is itself an incentive that tends to reduce risk will be taken into account in 

considering any such request. 

G. Incentives Available to Transcos

71. In the Final Rule, the Commission approved incentive-based rate treatments 

applicable to Transcos to encourage Transco formation and attract investment.107 

 107 Section 35.35(b)(1) defines Transcos as stand-alone transmission companies 

approved by the Commission that sell transmission services a wholesale and/or on an 

(continued) 
Docket No. RM06-4-001 -50- 

Specifically, the Commission approved an ROE that encourages Transco formation and is 

sufficient to attract investment and an adjustment to 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.108 The Commission noted 

that its decision to approve such incentives for Transcos is based on the “proven and 

encouraging track record of Transco investment” in transmission facilities.109 

1. Rehearing Requests

72. EEI argues that applicants seeking transmission incentives should be treated 

equally, without regard to their form of business. It argues that the incentives applicable 

to stand-alone transmission companies should be expanded to apply to all transmitting 

utilities.110 EEI also urges the Commission to recognize that all forms of transmission 

business models can effectively provide transmission facilities and to reiterate that it will 

evaluate each applicant’s proposed incentives, in particular the upper range of reasonable 

 

unbundled retail basis, regardless of whether they are affiliated with another public 

utility. 

108 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 222-224. The incentive 

ROE does not preclude a Transco from applying for other incentives, including 

hypothetical capital structure, allowance for deferred income taxes (ADIT), acquisition 

premiums, formula rates or deferred cost recovery. Id. P 221. 

109 See id. P 221-23. 

110 EEI at 5, 7-9. 
Docket No. RM06-4-001 -51- 

ROEs, without regard to the applicant’s form of business and without bias as between 

forms of business.111

73. Southern Companies contend that additional incentives for Transcos are not 

justified on grounds that the Transcos have a good record of transmission investment.112 

They state that vertically-integrated utilities like Southern Companies have consistently 

invested significantly in transmission maintenance and expansion. Southern Companies 

also claim that special ROE incentives solely for Transcos would be discriminatory by 

favoring one corporate structure over another to the extent both business structures have 

similar transmission investment records113 and the requirements of section 219 to 

promote investment regardless of the ownership of the facilities. 

74. APPA/NRECA assert that because the Commission’s definition of Transcos 

includes affiliated Transcos under the control of one or more parent public utilities, 

granting incentive rate treatment greater than that afforded to public utilities would 

constitute a financial windfall.114 They argue that such affiliated Transcos should not be 

 111 Id. at 5. EEI claims that section 219(b) provides that the rule shall promote 

transmission investment “regardless of the ownership of facilities” and the Commission 

noted in the Final Rule that it will not limit incentives based on corporate structure or 

ownership. Id. at 7, citing Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 4, 225. 

112 Southern Companies at 16-17. 

113 Id. at 17, citing Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 225. 

114 APPA/NRECA at 31, 34-35. In the Final Rule, the Commission stated that the 

definition of Transco does not exclude affiliated Transcos with active ownership by 

market participants, or stand-alone transmission companies that own transmission and 

(continued) 
Docket No. RM06-4-001 -52- 

eligible for special incentive rate treatment because such a payment would neither induce 

new construction nor provide any new benefit to the customer paying the incentive 

rate.115

75. Furthermore, TDU Systems oppose passive ownership interests in Transcos and 

contend that, if authorized, passive ownership interests should only be authorized upon a 

showing that the option of investment in the Transco is open to all load-serving entities 

(LSEs) in the region up to their load ratio shares.116 They also argue that the Commission 

must rigorously scrutinize and monitor relationships among the passive owners to deter 

the potential for abuse. TDU Systems also contend that the Commission should clarify 

that Transcos may only receive incentive rates if there are no interests within the Transco 

competing with transmission for capital. They recommend that the Commission 

condition the granting of incentives by imposing limits on business investments in other 

industries to avoid the dilution of capital funding from competing sources within the 

company.

117 They also claim that incentives for new investment in transmission 

 

distribution facilities. The Commission said that it would 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 Transcos the Commission already approved. 

See Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 202. 

115 APPA/NRECA at 31. 

116 TDU Systems at 39. 

117 Id. at 40. 
Docket No. RM06-4-001 -53- 

infrastructure should not be necessary because, as the Commission noted in the Final 

Rule, such incentives are inherent in the corporate business model to encourage 

investment.118 Therefore, encouraging additional incentives provides no incremental 

benefit to consumers.119

2. Commission Determination

76. We affirm the finding in the Final Rule that the Commission will not limit an 

applicant’s ability to seek incentive-based rate treatments based on corporate structure or 

ownership.120 The Commission will evaluate these applications to determine if incentive 

treatment is justified based on their demonstrations that the projects meet the 

requirements of section 219 and this rule. Certain types of incentives, such as the ADIT 

incentive may be more appropriate where transmission is being spun off or otherwise 

transferred to a new corporate entity, such as a Transco. But we see no basis for the 

claim that the Transco incentives are unduly discriminatory or contrary to the goals of 

section 219. 

77. The Final Rule described at great length the very significant transmission 

investment that has been undertaken by Transcos, to date.121 There is no reason to repeat 

 118 See Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 204. 

119 TDU Systems at 41. 

120 See Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 4. 

121 Id. P 222-23. 
Docket No. RM06-4-001 -54- 

those examples again here, but we disagree with comments that suggest that Transcos do 

not have a good record of transmission investment. Furthermore, their singular focus on 

transmission investment by transmission-only companies, the elimination of competition 

for capital between generation and transmission investments, and the access to capital 

markets have all been cited in support of the value of the Transco business model for 

getting new transmission built. For all of these reasons, the Commission adopted 

incentive-based rate treatments applicable to Transcos that would both encourage 

Transco formation and attract investment. 

78. As we stated in the Final Rule, the Commission will consider concerns regarding 

affiliated Transcos in specific applications for incentive treatment.122 We believe the 

Final Rule fulfills the requirements of section 219 by determining eligibility for Transco 

status and incentive-based rate treatment based on a showing of how the specific 

characteristics of a proposed Transco affect its ability and propensity to increase 

transmission investment in individual case proceedings. Therefore, we do not consider 

this proceeding to be the appropriate forum for adopting preconditions related to other 

issues, such as affiliation or passive ownership. Inasmuch as Transcos are subject to the 

Commission’s market behavior rules, their activities will be monitored for any potential 

market abuse. Therefore, we affirm the availability of ROE incentives to Transcos. As 

stated in the Final Rule, we expect that the incentive ROE will be used for additional 

 122 See id. P 202. 
Docket No. RM06-4-001 -55- 

capital spending, and thereby provide consumer benefits, as demonstrated by the negative 

cash flow profiles of Transcos and their future capital spending plans. 

H. Transmission Organization Incentive

79. In the Final Rule, the Commission stated that it will authorize, when justified, an 

incentive-based rate treatment for public utilities that join and/or continue to be a member 

of an ISO, RTO, or other Commission-approved Transmission Organization.123 

Applicants for the incentive-based rate treatment must make a filing with the 

Commission under section 205 of the FPA. For purposes of section 35.35(e), an 

incentive-based rate treatment means an ROE that is higher than the ROE the 

Commission might otherwise allow if the public utility were not a member of a 

Commission-approved Transmission Organization. The Commission stated that it will 

not create a generic adder for such membership, but instead will consider appropriate 

ROE incentives on a case-by-case basis. The Commission also stated that transmitting 

utilities or electric utilities that join a Transmission Organization would be eligible to 

apply to recover prudently-incurred costs associated with joining the Transmission 

Organization, either through rates charged by transmitting utilities or electric utilities or 

through transmission rates charged by the Transmission Organization that provides 

 123 Id. P 326. Transmission Organization is defined 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.” Id. P 328. 
Docket No. RM06-4-001 -56- 

services to such utilities.124 Furthermore, the Commission stated that based on its 

interpretation of section 219, eligibility for this incentive flows to an entity that “joins” a 

Transmission Organization and is not tied to when the entity joined. Therefore, the 

Commission clarified that 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.125 However, as the Commission noted, any public utility receiving 

an incentive ROE for joining a Transmission Organization but withdraws from such 

organization is no longer eligible for the ROE incentive. 

1. Rehearing Requests

80. Petitioners contend that public utilities should not be eligible for the Transmission 

Organization incentive if the public utilities are already members because the payment 

would neither induce new construction nor provide any new benefit to the customer 

paying the incentive rate.126 They argue that the Final Rule’s determination that 

incentives may go to entities that are already members of a Transmission Organization is 

contrary to court and Commission precedent interpreting incentive rates as forward-

 124 Id. P 329. 

125 Id. P 331. 

126 TDU Systems at 43; APPA/NRECA at 31-32, citing Southern California 

Edison Company, 114 FERC ¶ 61,018, at P 16 (2005) (“The rationale for this incentive is 

to encourage transmission owners to turn over the operational control of their 

transmission facilities to a regional transmission organization; therefore, it does not apply 

to transmission owners who have already done so, as they need no inducement to take 

such action”)(Southern California Edison). 
Docket No. RM06-4-001 -57- 

looking inducements, not a reward for past behavior.127 The California Commission 

claims that the Final Rule’s interpretation of section 219 exceeds the Commission’s 

authority by creating an incentive that is broader than specified in the FPA.128 

Furthermore, TDU Systems assert that many public utilities have already joined ISO or 

RTOs without ROE incentives and have benefited from such membership. Those public 

utilities that have not joined have chosen not to do so because their business interests 

would not be advanced by a reduction in transmission barriers and constraints. 

Therefore, they argue that “recalcitrant utilities” should not be awarded windfall profits 

for holding out on participating in Transmission Organizations because such action 

would only amount to rewarding the exercise of market power.129

81. Furthermore, the California Commission states that an incentive for utilities that 

have already joined a Transmission Organization and are planning to build transmission 

facilities provides no balancing of the consumer interests and represents an unjust 

windfall.130 By continuing its membership in an ISO/RTO, a transmission company will 

not incur any additional risks and will still remain a monopoly. The California 

 127 E.g., APPA/NRECA at 32; SMUD at 3-7; TDU Systems at 43. The California 

Commission argues that the courts have not permitted ROE adders for past conduct. 

California Commission at 18-19, citing Maine PUC v. FERC, 454 F.3d 278 (2006) and 

Allegheny Power Systems Operating Co., 111 FERC ¶ 61,308 (2005). 

128 California Commission at 14-15. 

129 TDU Systems at 42. 

130 California Commission at 16. 
Docket No. RM06-4-001 -58- 

Commission and TDU Systems argue that the Commission did not provide any evidence 

that current RTO/ISO members may leave a Transmission Organization without the 

incentive of higher ROEs and therefore such a conclusion constitutes unreasonable, 

unlawful decision making.131 APPA/NRECA assert that if a member leaves the 

Transmission Organization, the Commission can simply deny that utility a rate 

incentive.132 Further, SMUD notes that there is no assurance that members will be 

permitted to leave since such a decision is subject to Commission review, and expresses 

concern that extending incentives to existing members of a Transmission Organization 

for not leaving may discourage parties legitimately dissatisfied with the Transmission 

Organization’s performance and thereby make these organizations less accountable.133 

Finally, APPA/NRECA argue that the Commission’s statement that it would be unduly 

discriminatory not to award all members of a Transmission Organization an incentive 

ROE has no basis because nothing in the FPA forbids different rates if these 

arrangements are necessary to carry out the provisions of the FPA and to serve the 

regulatory purposes contemplated by Congress.134. 

 131 Id. P 17-18; TDU Systems at 43. 

132 APPA/NRECA assert that the Commission rejected such a remedy without a 

reasoned explanation in the Final Rule. APPA/NRECA at 32. 

133 SMUD at 3-7. 

134 APPA/NRECA at 33. 
Docket No. RM06-4-001 -59- 

82. TDU Systems request clarification that the Commission will not consider single 

company entities as Transmission Organizations. They state that to ensure new 

transmission investment serves regional markets, a “collaborative [and] open regional 

planning process” is necessary. Therefore, TDU Systems claim that only entities that 

provide for, or participate in, regional planning that spans a number of public utility 

transmission systems should be eligible for incentives.135 

83. TDU Systems recommend a reduction, i.e. negative 50 basis point penalty, in the 

authorized ROE for public utilities that withdraw from Transmission Organizations 

within the first five to ten years of participation to recognize the costs paid by consumers 

in anticipation of long-term savings. TDU Systems also argue that the incentive should 

not be allowed for public utilities ordered to join Transmission Organizations by statute, 

merger conditions or other regulatory requirements because there is no nexus between the 

incentive rates and demonstrated consumer benefits.136 Finally, SMUD argues that the 

Final Rule offered no explanation for providing an incentive for utilities that are required 

to join Transmission Organizations as a merger condition.137

84. MISO TOs state that the Final Rule was unclear on the mechanics of requesting 

incentives by RTO members and request clarification that transmission owners may seek 

 135 TDU Systems at 41-42. 

136 Id. at 42-43. 

137 SMUD at 7. 
Docket No. RM06-4-001 -60- 

this incentive without opening up a Commission-accepted ROE or additional rates or 

formulas.138 Specifically, they state that the Commission did not clarify that such a 

single-issue filing will not open up the already Commission-accepted ROE. 

85. Finally, APPA/NRECA argues that the Final Rule does not comply with section 

219(c) to provide incentives to each transmitting utility or electric utility that joins a 

Transmission Organization because it disregards incentives to non-jurisdictional 

utilities.139 The Commission reasoning that it does not have jurisdiction to provide 

incentives for non-public utilities joining Transmission Organizations is unjustified when 

it has asserted jurisdiction in other proceedings.140 APPA/NRECA recommend the 

Commission to consider incentives for non-public utilities such as assurances that these 

entities will fully recover all their costs of joining and participating in the Transmission 

Organization. 

2. Commission Determination

86. We affirm the finding in the Final Rule that the incentive applies to all utilities 

joining transmission organizations, irrespective of the date they join, based on a reading 

of section 219 in its entirety. Section 219 specifically provides that “the Commission 

 138 MISO TOs at 2-3. 

139 APPA/NRECA at 53-54. 

140 Id. P 54, citing City of Vernon, California and CAISO, Opinion No. 479, 

111 FERC ¶ 61,092, reh’g granted in part and denied in part, 112 FERC ¶ 61,207 (2005), 

reh’g denied, 115 FERC ¶ 61,297 (2006). 
Docket No. RM06-4-001 -61- 

shall . . . provide for incentives to each transmitting utility or electric utility that joins a 

Transmission Organization.” The stated purpose of section 219 is to provide incentivebased rate treatments that benefit consumers by ensuring reliability and reducing the cost 

of delivered power. We consider an inducement for utilities to join, and remain in, 

Transmission Organizations to be entirely consistent with those purposes. The consumer 

benefits, including reliability and cost benefits, provided by Transmission Organizations 

are well documented,141 and the best way to ensure those benefits are spread to as many 

consumers as possible is to provide an incentive that is widely available to member 

utilities of Transmission Organizations and is effective for the entire duration of a 

utility’s membership in the Transmission Organization. To limit the incentive to only 

utilities yet to join Transmission Organizations offers no inducement to stay in these 

 141 In Order No. 2000, in which the Commission's goal was to promote efficiency 

in wholesale electricity markets and to ensure that electricity consumers pay the lowest 

price possible for reliable service, the Commission stated that: 

These benefits [of RTOs] will include: increased efficiency through 

regional transmission pricing and the elimination of rate pancaking; 

improved congestion management; more accurate estimates of ATC; more 

effective management of parallel path flows; more efficient planning for 

transmission and generation investments; increased coordination among 

state regulatory agencies; reduced transaction costs; facilitation of the 

success of state retail access programs; facilitation of the development of 

environmentally preferred generation in states with retail access programs; 

improved grid reliability; and fewer opportunities for discriminatory 

transmission practices. All of these improvements to the efficiencies in the 

transmission grid will help improve power market performance, which will 

ultimately result in lower prices to the Nation's electricity consumers. 

Order No. 2000, FERC Stats. & Regs. ¶ 31,089 at 31,024. 
Docket No. RM06-4-001 -62- 

organizations for members with the option to withdraw, and hence risks reducing 

Transmission Organization membership and its attendant benefits to consumers. Because 

the incentive is applicable to utilities that join Transmission Organizations and is 

consistent with the requirements of section 219 of the FPA, the incentive complies with 

EPAct 2005 and the FPA.142 

87. We consider the claim of APPA/NRECA that the incentive is inappropriate 

because it does not induce construction to be misplaced. Section 219(c), applicable to the 

Transmission Organization incentive, is separate from the construction incentives in 

subsection (b), and therefore was not intended to directly encourage construction.143 

However, we note that regional transmission organizations provide a platform for 

regional planning and cost allocation associated with transmission expansion and 

 142 In light of our determination here, we reverse the policy adopted in our decision 

in Southern California Edison. Our decision in Southern California Edison failed to 

recognize that incentives are equally important in inducing utilities to join and remain in 

Transmission Organizations. Southern California Edison Co., 114 FERC ¶ 61,018, at P 

16 (2005). 

143 We note that a more accurate interpretation of section 219(c) must recognize 

that an important component of section 219(c) is ensuring cost recovery, and therefore 

this section differs from the rest of section 219 that only address incentive-based rate 

treatments. We note that the Midwest ISO tariff provisions governing pass-through of 

transmission costs are consistent with this section, and this section would provide the 

basis for approval of pass-through of costs in other ISOs. 
Docket No. RM06-4-001 -63- 

planning144 and therefore can help support the identification and construction of 

transmission needed to ensure reliability and to reduce congestion. 

88. We will not specify a particular method for establishing the appropriate ROE for 

entities that join and/or continue to be a member of an ISO, RTO, or other Commissionapproved Transmission Organization in this generic proceeding. For example, the 

mechanics of setting an incentive ROE is an issue best addressed in a proceeding 

evaluating the Transmission Organization incentive for transmission owners that belong 

to the particular Transmission Organization. We recognize that the issue was remanded 

to the Commission with respect to Midwest ISO.145 In the order on remand, the 

Commission observed that Midwest ISO or the MISO TOs can make a filing under 

section 205 to include an incentive adder.146

89. We affirm the Final Rule finding that this incentive applies to public utilities, as 

required by section 219, and therefore does not apply to non-public utilities and that non-

 144 PJM Interconnection, L.L.C., 117 FERC ¶ 61,218 (2006); Midwest 

Independent Transmission System Operator, Inc., 114 FERC ¶ 61,106 (2006), order 

denying reh’g, 117 FERC ¶61,241, (2006); Midwest Independent Transmission System 

Operator, Inc., et al., 113 FERC ¶ 61,194 (2005); Midwest Independent Transmission 

System Operator, Inc., 109 FERC ¶ 61,168, order granting clarification, 109 FERC 

¶ 61,243 (2004), reh’g pending. 

145 Midwest Independent Transmission System Operator, Inc., 100 FERC ¶ 61,292 

(2002), order on reh’g, 102 FERC ¶ 61,143 (2003), order on remand, 106 FERC ¶ 61,302 

(2004), aff’d in part and reversed in part, 397 F.3d 1004 (D.C. Cir. 2005). 

146 Midwest Independent Transmission System Operator, Inc., 111 FERC 

¶ 61,355, at P 5 (2005). 
Docket No. RM06-4-001 -64- 

public utilities may be permitted incentive-based rate treatments under section 211(a) of 

the FPA. 

90. We will not make determinations on acceptable Transmission Organization 

structures and affiliations in this proceeding. The Commission will consider applications 

to form Transmission Organizations, based on the requirements of § 35.35(b), and make 

its determinations on the facts and circumstances of each filing. 

I. Hypothetical Capital Structure

91. In the Final Rule, the Commission found that hypothetical capital structures can be 

an effective tool available to public utilities to foster transmission investment in 

appropriate circumstances. The Commission stated that it has allowed the use of 

hypothetical structures to improve access to capital markets for transmission investment 

and for specific projects when shown to be necessary for project financing.147 To 

encourage the development of new transmission investment, the Commission noted that it 

will evaluate each proposal on a case-by-case basis and will not prescribe specific criteria 

or set target debt/equity ratios for evaluating hypothetical capital structures. As with 

other incentives, the applicant is required to demonstrate the required nexus between its 

proposed incentive and the facts of its particular case.148

 147 The Commission noted that American Transmission and Trans-Elect are 

examples of the use of hypothetical capital structure to foster the development of 

transmission investment. Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 131. 

148 Id. P 133. 
Docket No. RM06-4-001 -65- 

1. Rehearing Requests

92. The California Commission considers the hypothetical capital structure incentivebased rate treatment unnecessary for regulated utilities. According to the California 

Commission, when a company increases its actual debt ratio to a level higher than its 

optimal capital structure, the company will expose itself to financial risks at the expense 

of ratepayers, or will unnecessarily increase ratepayer costs. The California Commission 

also faults the Commission for not mandating the degree of rigorous scrutiny necessary 

for all cases before they are approved.149 TDU Systems urge the Commission to adhere 

to Allegheny Power precedent that rejected hypothetical capital structures unless the 

utility’s actual capital structure was so far out of line with the market-driven capital 

structures of representative proxy companies so as to be anomalous.150

2. Commission Determination

93. We repeat our finding in the Final Rule that hypothetical capital structures can be 

an appropriate ratemaking tool for fostering new transmission in certain relatively narrow 

circumstances. Historically, those circumstances have been somewhat unique, such as 

consortiums that require a special capital structure or projects that need project financing. 

As with other incentive ratemaking treatments, the Commission will require any 

applicant to demonstrate the required nexus between the need for a hypothetical capital 

 149 California Commission at 11-14. 

150 TDU Systems at 35-36, citing Allegheny Power Co. 103 FERC ¶ 63,001, at P 

28 (2003), aff’d, 106 FERC ¶ 61,241, at P 27 (2004) (Allegheny Power). 
Docket No. RM06-4-001 -66- 

structure and the proposed investment project. We would not normally expect traditional 

regulated utilities to propose incentives based on hypothetical capital structures (as was 

suggested by the California Commission) and we note that the Commission and state 

commissions have the ability to prevent any regulated company from increasing its debt 

ratio to a level that unnecessarily exposes wholesale or retail customers to unnecessary 

risk. 

J. Single-Issue Ratemaking 

94. The Commission concluded in the Final Rule that single-issue ratemaking can 

provide a significant incentive for new investment in transmission infrastructure 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.151 

The Commission stated that single-issue ratemaking applicants are only required to 

address cost and rate issues associated with the investment in the section 205 proceeding 

to approve rates. The applicant, however, is still required to fully develop and support 

any transmission rate design to recover the costs of a particular transmission system 

facility or upgrade, including cost allocation and rate design.152 Further, the Commission 

noted that each application will be evaluated by balancing the need for new 

 151 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 191. 

152 Id. P 192. 
Docket No. RM06-4-001 -67- 

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 reopen existing rates or whether the traditional complaint processes are sufficient for that 

purpose.153

1. Rehearing Requests

95. Petitioners claim that single-issue ratemaking, as described in the Final Rule fails 

to balance shareholders’ and consumers’ interests and permits transmission owners to 

earn an unjust and unreasonable return on their overall transmission assets. They also 

assert that the Commission ignored its long-standing policy of rejecting single-issue 

ratemaking based on precedent that shows that single-issue ratemaking can lead to 

transmission providers earning super-normal returns while using single-issue rate filings 

to shield that fact from Commission scrutiny.154 They argue that the Final Rule allows 

public utilities to increase their transmission rates on a piecemeal basis without providing 

procedures, short of section 206 complaints, to ensure that the public utility’s steadily 

increasing rates do not become unlawful. They also contend that the Commission failed 

 153 Id. 

154 APPA/NRECA argue that, if a public utility has experienced load growth but 

has not invested in new transmission facilities, the public utility will have a strong 

disincentive not to file a section 205 rate case, because it will be earning a high rate of 

return on its highly depreciated rate base. They further assert that it has been their 

members’ general experience that when public utility transmission providers believe they 

are undercollecting their transmission revenue requirements, they are quick to address the 

situation through a section 205 filing. APPA/NRECA at 41. 
Docket No. RM06-4-001 -68- 

to consider reasonable alternatives such as a mandatory full transmission rate case every 

three years or allowing utilities to use formula rates that ensure a balance between risks 

borne by shareholders and ratepayers.155 

96. Xcel states that the Final Rule anticipates the possibility of placing the applicant at 

risk for being ordered to file a section 205 rate case for its existing investments and 

contend that this potential risk will have the practical effect of discouraging limited 

section 205 incentive proposals. Accordingly, Xcel recommends that the Final Rule be 

modified so that it can achieve its stated purpose of providing 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.156 According to Xcel, to the extent the 

Commission believes the new single-issue rate must be harmonized with existing rates, 

the burden of proof should remain on the Commission, or the utility’s customers, to show 

the existing filed rates are unjust and unreasonable and not shift the burden to the public 

utility.157

 155 Id. at 40-43; TDU Systems at 21-23. 

156 Xcel at 4-5. 

157 Id. at 5. 
Docket No. RM06-4-001 -69- 

2. Commission Determination

97. The Final Rule recognized that requiring transmission owners to open up their 

existing rates for review and litigation anytime they sought recovery of costs associated 

with a new transmission project could discourage new investment. Accordingly, the 

Final Rule permits an applicant to propose transmission rates associated with a particular 

project without proposing any changes to its existing transmission rates under section 

205. We disagree with TDU Systems and APPA/NRECA that single-issue ratemaking 

will permit transmission owners to earn an unjust and unreasonable return on their overall 

transmission investment and we specifically committed that the Commission would 

consider the need to combine or reconcile any project-specific transmission rate proposal 

with any existing transmission rate, where necessary. 

98. Indeed, the Final Rule specifies that the Commission may require the applicant to 

file a full rate case for existing transmission rates when evaluating a single-issue rate 

application, and therefore provides a procedure for additional rate review. However, we 

agree with Xcel that further clarification is necessary.158 As indicated in the Final Rule, 

applicants for single-issue ratemaking are only required to address cost and rate issues 

associated with the new investment and therefore are not obligated to justify the 

 158 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 192. 
Docket No. RM06-4-001 -70- 

reasonableness of unchanged rates.159 As PSC of N.Y. and Winnfield make clear, if 

intervenors or the Commission seek to challenge the applications beyond the limited 

issues raised in their applications, the intervenors or the Commission bear the burden of 

proof under section 206 in establishing that the existing, unchanged components of the 

rate are unjust and unreasonable. We further clarify that Commission review of the 

single-rate application will not be delayed in the event a separate section 206 

investigation is initiated, thereby ensuring that new investments are not impeded because 

of existing-system rate issues.160 

 159 Public Service Comm’n of New York v. FERC, 642 F.2d 1335 (D.C. Cir. 

1980)(“we cannot accept the proposition that because a company files for higher rates, it 

bears the burden of proof on those portions of its filing that represent no departure from 

the status quo. . . . The emphasis is on making the petitioner justify the changes in rates, 

not the constant elements”) (PSC of N.Y.); City of Winnfield, La. v. FERC, 744 F.2d 871 

(D.C. Cir. 1984) (“The statutory obligation of the utility . . . is not to prove the continued 

reasonableness of unchanged rates or unchanged attributes of its rate structure”) 

(Winnfield). 

160 This clarification is also consistent with Commission precedent: 

Protesters object to this option because of a concern that it 

may permit certain transmission owners to continue to 

overrecover their cost-of-service. However, this option 

provides just and reasonable cost recovery for the RTEP 

upgrades, and provide the necessary incentive for TOs to 

complete quickly the construction of RTEP projects that are 

essential to the efficient operation of PJM. As we said in the 

NYISO proceeding, if a concern arises regarding overrecovery of transmission costs, such parties are free to seek 

relief by filing a complaint with the Commission pursuant to 

section 206 of the FPA 

(continued) 
Docket No. RM06-4-001 -71- 

99. Based on the precedent cited above, we disagree with the conclusion that 

acceptance of single-issue rate filings would represent a dramatic shift in the historic 

balance between interests, and we therefore see no need to require additional consumer 

protections such as mandatory rate cases. 

K. Public Power

100. In the Final Rule, the Commission noted that ratemaking incentives are generally 

not directly available to non-jurisdictional entities, i.e. public power entities, because they 

do not file their rates with the Commission.161 However, the Commission recognized that 

public power participation can play an important role in the expansion of the transmission 

system and stated that public power participation in new transmission projects are 

encouraged. The Commission stated that the Commission will review 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.162

 

Allegheny Power System Operating Co., 111 FERC ¶ 61,308, at P 46 (2005), 

order on reh’g and clarification, 115 FERC ¶ 61,156 (2006). 

161 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 354. 

162 Id. The Commission did not require a consortium approach that includes 

public power and other entities for new investment because it would be more appropriate 

for applicants to fashion proposals tailored to the specific circumstances and needs of a 

particular project. Id. P 356-57. 
Docket No. RM06-4-001 -72- 

1. Rehearing Requests

101. TAPS requests the Commission to clarify that any approved incentive will be 

equally available to all owners of facilities that are found to merit incentives, regardless 

of the entity’s form or business model and that the Commission will look with disfavor 

on incentive rate treatment applications by vertically-integrated utilities that exclude 

other utilities from co-owning a facility located in their common footprint.163 TAPS 

contends that it is unduly discriminatory to allow large utilities to veto transmission 

incentives by refusing to participate in inclusive ownership arrangements. TDU Systems 

request the Commission to clarify that the option to participate in planning, financing and 

construction of new investment belongs to the public power system and that public 

utilities should not be allowed to use the availability of this option to avoid their 

obligation to construct needed network upgrades. TDU Systems urge the Commission to 

reconsider its determination that the Commission will not require public power or other 

joint participation in a transmission project in order for investment in a project to be 

eligible for incentives. They assert that conditioning a grant of any incentive rate 

treatments upon a robust, collaborative and open joint and regional planning process with 

all LSEs in the region and mandating compensation or credits for public power systems 

transmission facilities would better promote the Commission’s goal under section 219.164 

 163 TAPS at 22. 

164 TDU Systems at 34-35. 
Docket No. RM06-4-001 -73- 

Similarly, APPA/NRECA state that public power participation ensures that the lowest 

cost facilities are built, provide cash flow, and reduce uncertainty, thereby reducing the 

overall need for incentive rate treatments.165 NECOE and APPA/NRECA also argue that 

public utilities should be required to offer joint ownership opportunities as a condition to 

receiving incentives. NECOE asserts that merely encouraging transmission owners to 

seek participation by public power has not worked in New England, thereby denying 

ratepayers the low cost benefits of public power. NECOE further contends that the 

exclusion of non-transmission owner investment from network upgrades violates Order 

No. 2000’s open-architecture principles.166 At a minimum, NECOE recommends that the 

Commission should require incentive applicants to state whether they have sought 

potential LSE co-investors, including public and consumer-owned utilities and where coinvestors were sought but not permitted to participate, the proponent of an incentive 

should be required to explain why this was the case.167

2. Commission Determination

102. The Final Rule determined that the Commission would not condition recovery of 

incentives on the type of business structure and stated that the Commission will entertain 

appropriate requests for incentive ratemaking for investment in new transmission projects 

 165 APPA/NRECA at 51. 

166 NECOE at 9, citing Carolina Power and Light Cos., 95 FERC ¶ 61,282 at 

61,995 (2001). 

167 NECOE at 5. 
Docket No. RM06-4-001 -74- 

when public power participates as part of a proposal for incentives for a particular joint 

project.168 While the Commission encourages public power participation, we will not 

require such participation as a condition of any proposed incentive rate treatment. As we 

state elsewhere in this order, the Commission cannot compel investment or certain types 

of investment. Our focus in this rule is to provide incentives that will facilitate voluntary 

investments by utilities. However, the Commission will look favorably on an incentive 

request that includes public power joint ownership. A wide variety of entities, such as 

merchant companies, private equity participants, and pool administrators can potentially 

build transmission infrastructure. In the context of a rule to provide rate incentives for 

the construction of new transmission and to encourage deployment of technologies to 

increase the capacity and efficiency of existing transmission facilities, we do not believe 

that mandating an opportunity for public power participation is necessary nor do we 

believe that failure to do so would be unduly discriminatory. However, we note that the 

Commission has initiated a rulemaking in Docket Nos. RM05-17-000 and RM05-25-000 

to investigate necessary reforms to its existing pro forma OATT.169 Among the reforms 

under consideration is to require all jurisdictional public utilities to establish regional 

transmission planning open to all participants in a region – including public entities. We 

believe that the OATT reform rulemaking is a more appropriate forum to consider any 

 168 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 354. 

169 See OATT Reform NOPR, supra note 63. 
Docket No. RM06-4-001 -75- 

issues or allegations regarding undue discrimination with regard to public power 

participation in transmission expansion decisions. Accordingly, we will not restrict 

eligibility for incentive rate treatment to projects that allow public power participation. 

L. Other Issues

103. Parties request rehearing on a number of other issues discussed below. 

1. Recovery of Costs of Abandoned Facilities

104. In the Final Rule, the Commission allowed applicants to seek recovery of 100 

percent of prudently-incurred costs associated with abandoned transmission projects due 

to factors beyond the control of the public utility. The purpose of the incentive was to 

reduce the risk associated with potential upgrades or other improvements to the 

transmission system. 

105. TDU Systems assert that the Commission should clarify that it would allow 

prudently incurred abandoned plant costs under limited circumstances. They contend that 

applicants for the incentive rate treatment that allows recovery of prudently-incurred 

abandoned plant costs should be required to demonstrate that, as a precondition to 

receiving the incentive, they will suffer cash flow problems if such a recovery was not 

allowed.170 APPA/NRECA argue that the Commission should allow the incentive of 

abandoned cost recovery only on the condition that the public utility has engaged in open, 

regional transmission planning process to ensure some balance between the interests of 

 170 TDU Systems at 38. 
Docket No. RM06-4-001 -76- 

shareholders and ratepayers. They claim that the Commission wrongly relied on its 

granting of incentive rate treatment to American Transmission Company as a basis for 

this incentive without recognizing that the project was the result of joint planning.171 

Therefore, they assert that the Commission should not ask customers to pay for 

abandoned projects that they never had an opportunity to consider in the first instance. 

106. We decline to specify any particular demonstration that an applicant must make to 

justify recovery of abandoned plant cost beyond the required nexus test described earlier. 

Also, as discussed in the prior section on public power participation, we do not intend to 

mandate public power participation as a pre-requisite for any particular transmission rate 

treatment in this rule – including recovery of abandoned plant costs. We note that in a 

recent case involving incentives,172 the Commission expressly conditioned its approval of 

incentives (including a request for recovery of costs associated with any abandonment of 

the project) upon the project being included in the PJM regional transmission expansion 

plan.173 For these reasons, we deny rehearing on this issue. 

107. According to TDU Systems, the Commission must ensure that there is no double 

recovery of costs in instances in which other incentives are allowed for an abandoned 

 171 APPA/NRECA, 44-45. See Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 

1, 116, 122, 131; American Transmission Co., LLC, 105 FERC ¶ 61,388 (2003). 

172 Allegheny Energy, Inc., 116 FERC ¶ 61,059 (2006), reh’g pending. 

173 American Electric Power Service Corp., 116 FERC ¶ 61,059 (2006), reh’g 

pending.
Docket No. RM06-4-001 -77- 

project. In the event the applicant receives the ROE incentive and the abandoned plant 

incentive rate treatment, TDU Systems argue there should be an offset of the rate impacts 

of these incentives to avoid over-recovery of costs so that the incentive can be provided 

at the least reasonable cost to consumers.174 As described earlier in this order, we intend 

to evaluate any incentives requested as a package. To the extent that certain requested 

rate treatments have the effect of lowering the risk of a particular project, the 

Commission will take that into account in establishing an appropriate equity return for 

the project. 

2. Prudently Incurred Costs

108. MISO TOs request clarification that limited section 205 filings are permissible for 

the recovery of costs of prudently-incurred costs necessary to comply with mandatory 

reliability standards in section 215.175 MISO TOs argue that these costs may be imposed 

on transmission owners pursuant to statutory requirements and that without this 

clarification, they may be subject to extensive and expensive litigated cases, thereby 

discouraging utilities from recovering these costs that Congress authorized them to 

recover. 

 174 TDU Systems at 38. 

175 MISO TOs at 4-5. 
Docket No. RM06-4-001 -78- 

109. We agree that rapid processing of the recovery of mandatory reliability costs will 

facilitate more timely investment in these important projects. Therefore, we clarify that 

applicants may file to recover these costs in limited section 205 filings. 

3. Regional Planning

110. Parties contend that any public utility seeking incentive rates for its new 

transmission project should be required to demonstrate that the project was formulated 

through an open, regional planning process. Industrial Consumers assert that 

conditioning the granting of incentives upon the inclusion of a proposed transmission 

project in a regional planning process is critical to satisfying section 219’s requirements 

to demonstrate customer benefit and promote economically efficient transmission. They 

claim that a coordinated regional planning process that considers the relative costs and 

benefits of multiple projects provides an optimal forum for determining least-cost 

solutions and avoiding unnecessary duplication of expenditures.176 Similarly, NARUC 

and TAPS argue that no incentive should be available for projects that are to be sited in 

regions that plan regionally but which bypass the regional planning processes, noting that 

the Commission is proposing to require all jurisdictional public utilities to engage in 

regional planning in other Commission proceedings.177 Further, TDU Systems argue that 

nothing in section 219 suggests that the Commission may not impose a regional planning 

 176 Industrial Consumers at 11. 

177 NARUC at 6; TAPS at 7. 
Docket No. RM06-4-001 -79- 

requirement and that making regional planning process a threshold requirement for 

incentive applications would be congruent with the mandate of section 219 to promote 

reliable and economically efficient transmission and generation of electricity.178 

APPA/NRECA also contend that the Commission has broad discretion in deciding 

particular incentives and that a regional planning requirement would harmonize section 

219 with the objectives of section 217(b) to facilitate the planning and expansion of 

transmission facilities to meet the reasonable needs of LSEs. They also argue that the 

imposition of regional planning as a threshold requirement for incentive applicants is 

required by the mandate of section 219.179

111. The Final Rule grants a rebuttable presumption that projects resulting from 

regional planning qualify for incentive rate treatments, and we affirm that finding as 

discussed above. We will not, however, limit incentive rate treatments to projects that 

result from regional planning processes. While the Commission agrees that there are 

substantial benefits to be derived from regional planning, there may be transmission 

projects that arise outside of the context of a regional plan that help to ensure reliability 

or reduce the costs of delivered power and which deserve incentive rate treatment. 

Although the Commission has proposed to require regional planning as part of its OATT 

 178 TDU Systems at 9-10. 

179 APPA/NRECA at 16-19. 
Docket No. RM06-4-001 -80- 

reform effort,180 we note that many utilities are in regions in which no formal regional 

planning process exists at this time. However, as we stated in the Final Rule, and as 

modified by this order, projects are not entitled to a rebuttable presumption if they have 

not gone through a regional planning process, or have not received construction approval 

from an appropriate state commission or siting authority.181 Applicants seeking 

incentives for such projects must independently demonstrate that the project will 

maintain reliability or reduce congestion. 

4. CWIP

112. Because the long lead times required to plan and construct new transmission can 

negatively affect cash flow and the ability of a utility to attract capital at reasonable 

prices, the Final Rule allows public utilities to propose including 100 percent CWIP in 

rate base and expensing pre-commercial operations costs associated with new 

transmission investment.182

113. TDU Systems assert that the Commission should only allow 100 percent recovery 

CWIP and pre-commercial operations costs in the event the applicant shows that the 

transmission project will take more than four years to complete and that the applicant 

should have to demonstrate a regional need for the project to ensure that consumers 

 180 OATT Reform NOPR, supra note 63. 

181 In addition, and as modified by this order, an applicant may also rely upon the 

Commission’s siting authority for meeting the requirements of section 219(a). 

182 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 115-22. 
Docket No. RM06-4-001 -81- 

receive measurable benefits.183 In addition, TDU Systems contend that, with respect to 

pre-commercial expenses, the Commission should: (1) ensure that these costs are not 

later capitalized in subsequent rate filings; and (2) limit the pre-commercial costs to be 

expensed to planning, siting and environmental costs so that costs that raise intergenerational equity concerns, such as the design and construction of facilities, are not 

included.184 

114. We decline to establish any generic restrictions on the types of transmission 

projects or construction periods in order for a project to qualify for CWIP treatment under 

this rule. We leave to the applicant’s discretion whether the construction project is of 

sufficient size to merit making a rate request to the Commission seeking to include CWIP 

in rate base or to expense pre-commercial operations costs. There may be reasons that 

justify seeking CWIP for projects with relatively short construction schedules e.g., a 

project may take only a few years to build but rates will not go into effect for a number of 

additional years because the project can not recover costs until other projects are built, 

and therefore CWIP recovery is justified. We clarify that the Commission’s review 

process under section 205 will include a review to determine that the applicant does not 

double recover these costs. The Final Rule’s definition of costs approved by the 

Commission to be recoverable as pre-certification costs in account 183, i.e., preliminary 

 183 TDU Systems at 9-10. 

184 Id. at 37. 
Docket No. RM06-4-001 -82- 

survey and investigation costs,185 does not include facility costs and therefore should not 

raise the inter-generational issues of concern to TDU Systems. 

115. Finally, while CWIP and abandoned plant are characterized as “incentive-based 

rate treatments” in the Final Rule, we clarify that both of these rate mechanisms have 

been found previously to be just and reasonable under the Commission’s authority 

pursuant to section 205.186 More importantly, these are rate treatments which may be 

needed (and requested) in advance of a project being approved through a regional 

planning process or receiving any necessary siting approvals. To the extent an applicant 

demonstrates that the incentives sought (i.e., CWIP and abandoned plant) are tailored to 

address the demonstrable risks and challenges of the applicant, we will permit recovery 

of such prudently-incurred costs. 

 185 See Order No. 679, FERC Stats. & Regs. ¶31,222 at P 122 and n 82. 

186 See, e.g., American Electric Power Service Corp., 116 FERC ¶ 61,059, at P 55 

(2006), reh’g pending (allowing recovery of 100 percent CWIP); Allegheny Energy, Inc., 

116 FERC ¶ 61,058, at P 74 (2006), reh’g pending; American Transmission Co., L.L.C., 

105 FERC ¶ 61,388, at P 27 (order establishing hearing and settlement judge procedures 

concerning, inter alia, the company’s proposal for recovery of 100 percent CWIP), order 

dismissing reh’g and approving settlement, 107 FERC ¶ 61,117 (2004); Boston Edison 

Co., 109 FERC ¶ 61,300 (2004), order on reh’g, 111 FERC ¶ 61,266 (2005) (recovery of 

50 percent CWIP); Southern California Edison Co., 112 FERC ¶ 61,014, at P 58-61, 

reh’g denied, 113 FERC ¶ 61,143, at P 9-15 (2005) (granting recovery of 100 percent of 

prudently incurred abandoned or cancelled plant costs); New England Power Co., 

Opinion No. 295, 42 FERC ¶ 61,016, at 61,068, 61,081-83 (recovery of 50 percent of 

prudently incurred cancelled plant costs), order on reh’g, 43 FERC ¶ 61,285 (1988); 

Public Service Co. of New Mexico, 75 FERC ¶ 61,266, at 61,859 (1996), order 

approving settlement, 87 FERC ¶ 61,040 (1999) (50 percent recovery of cancelled plant 

costs). 
Docket No. RM06-4-001 -83- 

116. For example, where an applicant has satisfied our nexus requirement and has been 

granted authority to recover CWIP or abandoned plant, and subsequently the applicant’s 

project is, for example, unable to obtain state or federal siting authority (and thus no 

showing is made with respect to ensuring reliability or reducing the cost of delivered 

power by reducing congestion because the applicant was relying upon those processes) 

we would not require refunds for the costs already prudently-incurred by the applicant. 

To require refunds in such circumstances would be contrary to our long-standing policy, 

which permits recovery of all prudently-incurred costs.187

5. Reporting Requirement: FERC-730

117. The Final Rule adopted an annual reporting requirement, FERC-730, for utilities 

that receive incentive rate treatment for specific transmission projects. The annual 

reporting requirement includes projections and related information that detail the level of 

transmission investment.188

118. TAPS argues that FERC-730’s tracking of capital spending is misdirected by 

failing to identify how much consumers are spending as incentive rate treatments and 

 187 The Commission “has applied the ‘prudence’ test to determine the 

recoverability of a utility’s expenses. Under this test [a utility] is entitled to recover its 

costs from consumers if it acted ‘prudently’ in incurring those costs, or stated conversely, 

[a utility] may not recover its costs if those costs were incurred ‘imprudently.’” 

Connecticut Yankee Atomic Power Co., 108 FERC ¶ 61,212, at P 42 (2004), quoting 

Violet v. FERC, 800 F.2d 280, 282 (1st Cir. 1986). See also, e.g., City of New Orleans v. 

FERC, 67 F.3d 947 (D.C. Cir. 1995) (citing Violet v. FERC)). 

188 Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 367-76. 
Docket No. RM06-4-001 -84- 

what they are getting in return. TAPS recommends that the Commission expand FERC730 to include budgeted amounts by project on an annual basis, segregation of generation 

or distribution investments, a listing of which network service customers are 

predominantly paying for the project costs and the expected differential cost to 

consumers of each project’s approved above-cost incentives.189 

119. As the Commission explained in the Final Rule, the purpose of the FERC-730 

reporting requirement is not to provide a quantitative measure of the consumer benefits 

that result from transmission infrastructure investments. In the proceeding approving 

incentives and recovery of the costs of incentives in rates, the Commission will determine 

whether proposed projects meet the requirements of section 219 and thereby provide 

consumer benefits and also set metrics to ensure those benefits are justified on an ongoing basis. Therefore no further quantitative tracking of consumer benefits or expected 

differential costs to consumers is necessary. We repeat and affirm the Final Rule’s 

statement that year-by-year capital spending estimates are not necessary for each 

individual project listed since the goal of the rule is not to ensure the achievement of 

annual capital spending targets but rather to ensure the overall projects are completed, 

and if not, the reasons for delay. 

 189 TAPS at 29-31. 
Docket No. RM06-4-001 -85- 

120. We will not limit the capital spending information requested from account 

numbers 350 through 359190 to only investment in the transmission function, and exclude 

transmission investment in the generation or distribution functions. Capital investment in 

transmission facilities that interconnect generation facilities are ensuring reliability, and 

therefore are meeting the requirements of section 219. Accordingly, it is appropriate to 

include these amounts in transmission investment. Likewise, capital investment in lower 

voltage transmission facilities that are classified as part of the distribution function also 

accomplish the reliability and congestion reduction requirements of section 219 and 

therefore should be included in the survey of transmission investment. We see no need to 

require additional information on which customers pay for investment projects and the 

differential cost impact of the incentives. The purpose of FERC-730 is restricted to 

information on progress toward meeting the requirements of section 219. Customer 

allocation of cost responsibility is beyond the scope of that provision, and therefore that 

information does not need to be collected. 

6. Miscellaneous

121. TDU Systems and APPA/NRECA argue that no incentives should be approved for 

projects that already have a binding commitment to build, including commitments under 

 190 18 CFR Part 101. 
Docket No. RM06-4-001 -86- 

RTO arrangements, or for which applicants are obligated to build by statute, regulation or 

order.191 

122. In general, we do not consider that contractual commitments or mandatory 

projects, such as section 215 reliability projects, disqualify a request for incentive-based 

rate treatment. Provided applicants are able to demonstrate they meet the requirements of 

section 219, including establishing the required nexus between the requested incentive 

and the investment, they may qualify for incentive-based rate treatments. A prior 

contractual commitment or statute may have a bearing on our nexus evaluation of 

individual applications. 

123. EEI requests clarification that an applicant or group of applicants may propose rate 

incentives for a group of interrelated projects rather than for each single project 

individually, and thereby reduce the Commission burden.192 

124. We clarify that applicants may propose incentives as a group, and note that such a 

group application process has been used by groups of transmission owners that are 

members of RTOs. With this clarification, we believe that revision of § 35.35(d) is 

unnecessary. 

125. TAPS asserts that the Final Rule failed to explicitly provide that applicants’ 

proposed incentives will be modified when doing so will advance the customer-

 191 APPA/NRECA at 4; TAPS at 35. 

192 EEI at 6. 
Docket No. RM06-4-001 -87- 

benefiting objectives of section 219. For example, TAPS argues that in order to modify 

the investment to which incentives will apply, an applicant may propose an incentiveworthy, congestion-reducing, new line packaged with mundane existing facility 

replacements that have already been committed to and do not advance the objectives of 

section 219.193 In such a case, TAPS argues that the Commission should be able to 

modify the proposal to target incentives to the new line alone. 

126. We do not consider this rulemaking to be the proper forum to assess whether a 

hypothetical application would meet the requirements of section 219 and Order No. 679. 

The Commission will determine whether incentive applications are just and reasonable 

based on the specific facts and circumstances of each proposal. 

127. TDU Systems request clarification that metrics are required because certain 

statements in the Final Rule imply metrics are optional.194 To the extent the use of 

metrics determines that a project does not provide the anticipated benefits, ratepayers 

should receive refunds based on the monetary value of the incentive, according to TDU 

Systems. 

128. We clarify that applicants are required to propose metrics in their incentive 

applications. However, it is not the Commission’s intention to approve incentive rate 

 193 TAPS at 12. 

194 See Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 36 (“an applicant may 

propose periodic progress assessments....”). 
Docket No. RM06-4-001 -88- 

treatments “subject to refund.” To the extent that a customer has a reason to believe that 

any rate that has been approved by the Commission is no longer just, reasonable, and not 

unduly discriminatory or preferential, they will need to file an appropriate complaint 

under section 206. 

129. TAPS contends that the Commission is not statutorily free to rule out symmetrical, 

i.e. performance-based approaches to setting an appropriate return regardless of whether 

they are sponsored by incentive applicants or recommended with appropriate support by 

intervenors. TAPS states that section 219 expressly provides that incentive programs 

may be performance-based and has long been a foundation for Commission incentive rate 

policy.195 SMUD asserts that the Commission failed to explain its departure from the 

1992 Policy Statement that symmetry is an inherent part of all incentive ratemaking.196 

130. The purpose of this rule is to provide incentive-based rate treatments that benefit 

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

transmission congestion. The primary focus of the rule is necessarily on investment. 

However, while the Final Rule declined to adopt generic performance-based ratemaking 

measures, we did encourage the industry to work on developing performance-based 

ratemaking proposals. While we agree that section 219 does not rule out symmetrical 

approaches to return, to the extent applicants or intervenors propose performance-based 

 195 TAPS at 28. 

196 SMUD at 9-10. 
Docket No. RM06-4-001 -89- 

rate treatments under section 219, they must justify their proposals in terms of their 

capability to attract investment and either ensure reliability or reduce the cost of delivered 

power by reducing congestion. 

131. TAPS asserts that the Commission cannot determine if an incentive will be nondiscriminatory, as required under section 219(d), unless it ascertains what ratepayer 

classes are subject to paying for the incentive. TAPS also claims the Commission needs 

to consider whether an incentive request should be conditioned on geographically 

broadened cost spreading in order to determine whether the requested incentives can be 

better formulated to advance the consumer benefits of section 219. TAPS further argues 

that the Commission should state its willingness to consider in declaratory petition 

proceedings how costs will be allocated for the subject facilities and whether altering that 

treatment should be part of the incentive program.197 TDU Systems assert that the 

Commission must require roll-in of new and existing rates to encourage investment. 

132. We repeat the finding in the Final Rule that the section 205 proceedings 

addressing recovery of the costs of incentive-based rate treatments are the appropriate 

forum for determining whether the resulting rates are just, reasonable and nondiscriminatory, and therefore are the appropriate proceedings to consider cost allocation 

and rate design issues.198 The primary purpose of the declaratory petition proceeding is 

 197 TAPS at 17-18. 

198 E.g., Order No. 679, FERC Stats. & Regs. ¶ 31,622 at P 81. 
Docket No. RM06-4-001 -90- 

to determine if the proposed incentives meet the requirements of section 219, and 

therefore cost allocation and rate design issues will not be considered. Finally, we 

consider rate design issues, such as roll-in of rates to beyond the scope of this proceeding, 

and therefore affirm the Final Rule’s determination to not require roll-in of rates.199

133. Southern Companies assert that the Commission’s routine imposition of a fivemonth suspension of rates is a disincentive to the construction of new transmission 

infrastructure, claiming that delaying the effective date of a rate change forces the utility 

to absorb costs associated with new facilities and reduces the utility ROE.200 

134. The Commission addressed this concern in the Final Rule by stating that we will 

not revise our suspension policy in this proceeding. We affirm the Final Rule’s finding 

that utilities should raise concerns with the Commission’s suspension policy in our prefiling process. 

135. Energy Financing requests clarification that its proposed performance-based 

financing option for transmission investment is not excluded as an alternative method of 

achieving the Commission’s and Congress’ goal of encouraging more transmission 

investment, or in the alternative, it seeks rehearing arguing that alternative financing 

methodologies are viable vehicles to increase transmission investment, in lieu of or in 

 199 Id. P 192. 

200 Southern Companies at 19-20. 
Docket No. RM06-4-001 -91- 

addition to the incentives identified in the Final Rule.201 Energy Financing’s proposal 

concerns how a project is financed rather than an incentive-based rate treatment. We do 

not consider it an alternative to the incentive-based rate treatments specified in § 35.35. 

Also, we can not make a determination as to whether the option will increase 

transmission investment because Energy Financing has not provided any information to 

indicate that its option is having the purported effect on investment. For these reasons, 

we deny rehearing on this issue. 

136. Finally, the introductory text in § 35.35(d)(1) is revised to delete redundant 

language. 

IV. Information Collection Statement

137. Order No. 679 contains information collection requirements for which the 

Commission obtained approval from the Office of Management and Budget (OMB). The 

OMB Control Number for this collection of information is 1902-0203. This order denies 

most rehearing requests, clarifies the provisions of Order No. 679, and grants rehearing 

on only three minor issues. This order does not make substantive modifications to the 

Commission's information collection requirements and, accordingly, OMB approval for 

this order is not necessary. However, the Commission will send a copy of this order to 

OMB for informational purposes. 

 201 Energy Financing at 4-5. 
Docket No. RM06-4-001 -92- 

V. Document Availability

138. 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 FERC's Home Page 

(http://www.ferc.gov) and in FERC'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. 

139. From FERC's Home Page on the Internet, this information is available on 

eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft 

Word format for viewing, printing, and/or downloading. To access this document in 

eLibrary, type the docket number excluding the last three digits of this document in the 

docket number field. 

140. User assistance is available for eLibrary and the FERC's website during normal 

business hours from our Help line at (202)502-8222 or the Public Reference Room at 

(202) 502-8371 Press 0, TTY (202)502-8659. E-Mail the Public Reference Room at 

public.referenceroom@ferc.gov. 

VI. Effective Date

141. Changes to Order No. 679 made in this order on rehearing will become effective 

on [insert 30 days after publication in the Federal Register]. 
Docket No. RM06-4-001 -93- 

List of subjects in 18 CFR Part 35 

Electric power rates 

Electric Utilities 

Reporting and record keeping requirements 

By the Commission. 

( S E A L ) 

 Magalie R. Salas, 

 Secretary. 

 
Docket No. RM06-4-001 -94- 

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. 

2. Section 35.35 is amended as follows by: 

a. Revising the third sentence in paragraph (d) introductory text , 

b. Revising paragraph (d)(1) introductory text; 

c. Revising paragraph (i); and 

d. Adding a new paragraph (j) to read as follows: 

Subpart G – Transmission Infrastructure Investment Provisions

§ 35.35 Transmission infrastructure investment. 

* * * * *

(d) Incentive-based rate treatments for transmission infrastructure investment. 

* * * 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 the total package of 

incentives is tailored to address the demonstrable risks or challenges faced by the 

applicant in undertaking the project, and that resulting rates are just and reasonable.* * * 
Docket No. RM06-4-001 -95- 

 (1) For purposes of this paragraph (d), incentive-based rate treatment means any of 

the following:

* * * * *

 (i) Rebuttable presumption. (1) The Commission will apply a rebuttable 

presumption that an applicant has demonstrated that its project is needed to ensure 

reliability or reduces the cost of delivered power by reducing congestion 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; or 

 (ii) A project that has received construction approval from an appropriate state 

commission or state siting authority. 

 (2) To the extent these approval processes do not require that a project ensures 

reliability or reduce the cost of delivered power by reducing congestion, the applicant 

bears the burden of demonstrating that its project satisfies these criteria. 

 (j) Commission authorization to site electric transmission facilities in interstate 

commerce. If the Commission pursuant to its authority under section 216 of the Federal 

Power Act and its regulations thereunder has issued 1 or more permits for the 

construction or modification of transmission facilities in a national interest electric 

transmission corridor designated by the Secretary, such facilities shall be deemed to 

either ensure reliability or reduce the cost of delivered power by reducing congestion for 

purposes of section 219(a). 
Docket No. RM06-4-001 -96- 

Note: The following appendix will not appear in the Code of Federal Regulations. 

APPENDIX A 

Requests for Rehearing

American Public Power Association and National Rural Electric Cooperative Association 

(together, APPA/NRECA) 

Coalition of Midwest Transmission Customers, PJM Industrial Customer Coalition, 

NEPOOL Industrial Customer Coalition, Southeast Electricity Consumers Association, 

and Southwest Industrial Customer Coalition (collectively, Industrial Consumers) 

Connecticut Department of Public Utility Control, the Massachusetts Municipal 

Wholesale Electric Company, the Connecticut Municipal Electric Energy Cooperative, 

the New Hampshire Electric Cooperative, the Maine Public Utility Commission, and the 

New England Conference of Public Utility Commissioners (collectively, New England 

Commissions) 

Edison Electric Institute (EEI) 

Energy Financing, Inc. (Energy Financing) 

Midwest ISO Transmission Owners (MISO TOs) 

National Association of Regulatory Utility Commissioners (NARUC) 

New England Consumer-Owned Entities (NECOE) 

Public Utilities Commission of the State of California (California Commission) 

Sacramento Municipal Utility District (SMUD) 

Southern California Edison Company (SoCal Edison) 

Southern Company Services, Inc., on behalf of Alabama Power Company, Georgia 

Power Company, Gulf Power Company, and Mississippi Power Company (collectively, 

Southern Companies) 

Transmission Access Policy Study Group (TAPS) 

Transmission Dependent Utility Systems (TDU Systems) 

Xcel Energy Services, Inc. (Xcel) 
Docket No. RM06-4-001 -97-