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Proposed Rule

Promoting Transmission Investment Through Pricing Reform

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Start Preamble Start Printed Page 30869 May 19, 2011.

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Notice of inquiry.

SUMMARY:

In this Notice of Inquiry, the Federal Energy Regulatory Commission (Commission) seeks comment on the scope and implementation of its transmission incentives regulations and policies under Order No. 679. It has been nearly five years since the Commission promulgated rules to implement the directives of section 1241 of the Energy Policy Act of 2005 (EPAct 2005), which added a new section 219 to the Federal Power Act (FPA). In the past five years, the Commission has received over 75 applications for transmission incentives. The requested incentives have been varied, and the demonstrations supporting the incentives applications have likewise been varied.

During this time, the electric industry has continued to evolve, and the Commission has issued corresponding regulations, policy statements, and case-by-case determinations. Given the changes in the electric industry, the Commission's experience to date applying Order No. 679, and the ongoing need to ensure that our incentives regulations and policies are encouraging the development of transmission infrastructure in a manner consistent with FPA sections 219 and 205 and 206, the Commission now issues this Notice of Inquiry.

DATES:

Comments are due July 26, 2011.

ADDRESSES:

You may submit comments, identified by docket number and in accordance with the requirements posted on the Commission's Web site http://www.ferc.gov. Comments may be submitted by any of the following methods:

  • Agency Web Site: Documents created electronically using word processing software should be filed in native applications or print-to-PDF format, and not in a scanned format, at http://www.ferc.gov/​docs-filing/​efiling.asp.
  • Mail/Hand Delivery: Commenters unable to file comments electronically must mail or hand deliver an original of their comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street, NE., Washington, DC 20426. These requirements can be found on the Commission's Web site, see, e.g., the “Quick Reference Guide for Paper Submissions,” available at http://www.ferc.gov/​docs-filing/​efiling.asp, or via phone from FERC Online Support at 202-502-6652 or toll-free at 1-866-208-3676.
Start Further Info

FOR FURTHER INFORMATION CONTACT:

David Borden (Technical Information), Office of Energy Policy and Innovations, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-8734, David.Borden@ferc.gov.

Andrew Weinstein (Legal Information), Office of General Counsel—Energy Markets, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6230, Andrew.Weinstein@ferc.gov.

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SUPPLEMENTARY INFORMATION:

Notice of Inquiry

1. In this Notice of Inquiry, the Federal Energy Regulatory Commission (Commission) seeks comment on the scope and implementation of its transmission incentives regulations and policies under Order No. 679.[1] It has been nearly five years since the Commission promulgated rules to implement the directives of section 1241 of the Energy Policy Act of 2005 (EPAct 2005),[2] which added a new section 219 to the Federal Power Act (FPA).[3] In the past five years, the Commission has received over 75 applications for transmission incentives. Collectively, the applicants in those cases sought incentives for investment in over $50 billion in proposed transmission infrastructure to ensure reliability or to reduce the cost of delivered power to customers by reducing transmission congestion.[4] The requested incentives have been varied, and the demonstrations supporting the incentives applications have likewise been varied.

2. During this time, the electric industry has continued to evolve, and the Commission has issued corresponding regulations, policy statements, and case-by-case determinations.[5] Given the changes in the electric industry, the Commission's experience to date applying Order No. 679, and the ongoing need to ensure that our incentives regulations and policies are encouraging the development of transmission infrastructure in a manner consistent with FPA sections 219 and 205 and 206,[6] the Commission now issues this Notice of Inquiry.

I. Brief History/Background

3. Section 1241 of EPAct 2005 added a new section 219 to the FPA. Section 219(a) of the FPA requires the Commission to establish by rule 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. Section 219(b) requires that the Rule:

  • Promote reliable and economically efficient transmission and generation of electricity by promoting capital investment in the enlargement, improvement, maintenance, and operation of all facilities for the transmission of electric energy in interstate commerce, regardless of the ownership of the facilities;
  • 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 the recovery of all prudently incurred costs necessary to comply with mandatory reliability standards issued pursuant to section 215 of the FPA, and all prudently incurred costs related to transmission infrastructure Start Printed Page 30870development pursuant to section 216 of the FPA.[7]

4. Section 219(c) requires that the Rule provide for incentives to each transmitting utility or electric utility that joins a Transmission Organization and ensure that any recoverable costs associated with joining such Transmission Organization may be recovered through transmission rates charged by the utility or through the transmission rates charged by the Transmission Organization that provides transmission service to the utility. Finally, section 219(d) provides that all rates approved under the Rule are subject to the requirements of sections 205 and 206 of the FPA, which require that rates, charges, terms and conditions of service be just and reasonable and not unduly discriminatory or preferential.

5. On July 20, 2006, the Commission issued Order No. 679, Promoting Transmission Investment through Pricing Reform, which was further refined in Order No. 679-A, and a subsequent order on rehearing, issued in December 2006, and April 2007, respectively. In this series of orders, the Commission stated that Section 219 reflects Congress' determination that the Commission's traditional ratemaking policies may not be sufficient to encourage new transmission infrastructure.[8] Thus, the Commission identified instances where its policies may no longer have struck the appropriate balance in encouraging new investments and set forth several broad categories of incentive rate treatments. The Commission declined to adopt specific criteria or conditions that applicants would be required to meet in order for their projects to be considered eligible for incentive rate treatments. The Commission stated that it would not establish such criteria “at this time,” on the grounds that to do so “now would limit the flexibility of the Rule.” [9] Instead, as discussed more fully below, the Commission required that each applicant satisfy the statutory threshold set forth in section 219(a), by demonstrating that the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion. Once that threshold is met, the applicant must demonstrate that there is a nexus between the incentive sought and the investment being made.

6. With respect to the statutory threshold, the Commission established rebuttable presumptions to assist in determining whether proposed facilities either ensure reliability or reduce the cost of delivered power by reducing transmission congestion, consistent with section 219(a) of the FPA. The rebuttable presumptions apply to a transmission project that (i) 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) has received construction approval from an appropriate state commission or state siting authority.[10] If a proposed project does not qualify for the rebuttable presumption, an applicant bears the burden of otherwise demonstrating that its project satisfies the statutory criteria and therefore is eligible for incentives.

7. As mentioned above, after satisfying the statutory threshold of section 219(a), applicants for incentives must then show that there is a nexus between the incentive sought and the investment being made, i.e., that the incentives being requested are “rationally tailored to the risks and challenges faced by a project.” [11] In Order No. 679-A, the Commission stated that “[i]n evaluating whether an applicant has satisfied this 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 a project.” [12]

8. The Commission stated that the rebuttable presumptions and the nexus test are not prescriptive by design, and are intended to be applied on a case-by-case basis.[13] The Commission also stated that the “most compelling” candidates 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.” [14]

9. The Commission also discussed the potential benefits of specific incentives for which applications could be filed under Order No. 679. These incentives included incentive adders to a base return on equity (ROE), recovery of 100 percent of prudently incurred costs of transmission facilities that are cancelled or abandoned due to factors that are beyond the control of the public utility, inclusion of 100 percent of construction work in progress (CWIP) in rate base, hypothetical capital structures, accelerated depreciation for rate recovery, and recovery of prudently incurred pre-commercial operations costs.

II. Subject of the Notice of Inquiry

10. In Order No. 679, the Commission established a policy for rate incentives to achieve the goals of section 219 to promote “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.”[15] The Commission believes that there remains a need for additional transmission investment to ensure the reliable operation of the grid and reduce the cost of delivered power by reducing transmission congestion.

11. By issuing this Notice of Inquiry, the Commission is not departing from the Congressional mandate set forth in section 219.

12. Similarly, by issuing this Notice of Inquiry, the Commission is not departing from its longstanding recognition of the need to balance consumer and investor interests. For example, in Order No. 679, the Commission stated:

The incentives adopted by this Final Rule are properly understood only in the context of the traditional regulatory principles they seek to further. The longstanding rule is that utility rate regulation must adequately balance both consumer and investor interests. It is not enough to ensure investors are properly compensated, and it is not enough to ensure that consumers are protected against excessive rates. Our policies must ensure both outcomes and, in doing so, strike the appropriate balance between these twin objectives.[16]

13. This Notice of Inquiry does not seek to overturn the need for balance between consumer and investor interests. In Order No. 679, the Commission stated that the purpose of the incentives policy “is to benefit customers by providing real incentives to encourage new infrastructure, not simply increasing rates in a manner that has no correlation to encouraging new investment.” [17] We will continue to balance the interests of consumers and investors and ensure that our implementation of section 219 provides Start Printed Page 30871incentives to encourage new infrastructure as we evaluate future requests for incentives for investment in transmission infrastructure.[18]

14. The Commission has discretion in implementing transmission incentives policies to achieve the broad goals of section 219. Through this Notice of Inquiry, the Commission is seeking input from stakeholders on the scope and implementation of its transmission incentives policies, and on what steps the Commission could take evaluating future requests for incentives for investment in transmission infrastructure to ensure that its incentives policies appropriately encourage the development of transmission infrastructure in a manner consistent with our statutory responsibilities.

15. Immediately below, the Commission poses a number of overarching questions about our incentives policies under Order No. 679. The ensuing sections of this Notice of Inquiry pose more specific questions with respect to various aspects of the Commission's implementation of its transmission incentive policies.

(Q1) What have been the effects of the incentives policies adopted in Order No. 679 with respect to the goals set forth in section 219?

(Q2) Are the Commission's incentives policies appropriately promoting investment in transmission infrastructure in accordance with section 219?

(Q3) Some barriers to construction of new transmission facilities fall outside of the Commission's jurisdiction. How do the Commission's incentives policies affect such barriers?

(Q4) How can the Commission's rate incentives policies balance the need for regulatory certainty with the changing investment climate over time? Are there metrics the Commission should monitor to achieve this balance, and if so, what are they? Are there other factors that change over time that the Commission should consider in evaluating incentives applications? Should the Commission consider these changes over time on a generic or case-by-case basis?

(Q5) Should specific rate incentives be tailored to address specific goals set forth by Congress in section 219?

(Q6) Are there other factors or considerations which the Commission should consider as part of its transmission incentives policies, in order to be consistent with the goals of section 219?

(Q7) Have the incentives granted to transmission projects had an impact on consumer rates and service, including impacts related to reliability and the reduction of congestion?

(Q8) Have the incentives granted to transmission projects had an impact on investment patterns in the electricity industry? Do the incentives impact the allocation of investment capital among transmission, generation, and distribution facilities?

(Q9) How should the Commission best balance the promotion of transmission investment with the assurance of just and reasonable rates?

A. Section 219(a) Statutory Threshold

16. In Order No. 679, the Commission required that each applicant seeking transmission incentives in accordance with section 219 of the FPA, first satisfy the statutory threshold set forth in section 219(a) by demonstrating that a proposed project for which it seeks incentives either ensures reliability or reduces the cost of delivered power by reducing transmission congestion. The Commission has established rebuttable presumptions that a proposed transmission project satisfies the section 219(a) statutory threshold if such project: (i) Results from a fair and open regional planning process that considers and evaluates a project for reliability and/or congestion, and is found to be acceptable to the Commission; or (ii) has received construction approval from an appropriate state commission or state siting authority. In the alternative, if a proposed project does not qualify for the rebuttable presumption, an applicant can nevertheless make an independent showing that its project either ensures reliability or reduces transmission congestion and therefore is eligible for incentives.

17. The Commission seeks comment regarding the following issues:

(Q10) Do the rebuttable presumptions established in Order No. 679 serve as appropriate bases for satisfying the statutory threshold for section 219(a)?

(Q11) Are there other criteria that the Commission should adopt as additional rebuttable presumptions for satisfying the statutory threshold for section 219(a)?

(Q12) What types of information, data, or studies should the Commission consider in evaluating whether an applicant has made an independent showing that satisfies section 219(a)?

(Q13) Would it assist applicants if the Commission established a procedure that applicants may follow to make such an independent showing? If so, what should be the characteristics of that procedure?

(Q14) In some cases, when an applicant has sought incentives, the Commission has conditionally approved the request subject to the project receiving approval in a regional transmission planning process or state siting process.[19] Intervenors in various rate proceedings have raised concerns that a project scope may change in the planning and siting process. In light of this, how should the Commission balance the value of and need for the requested incentives in promoting project development and financing with the potential uncertainty surrounding project scope?

B. Additional Goals in Section 219

18. The Commission in Order No. 679 interpreted section 219 as intended to promote capital investment in a wide range of infrastructure that ensures reliability or reduces the cost of delivered power by reducing transmission congestion. This interpretation is primarily based on the language of section 219(a). In addition, section 219(b)(1) states that “the Commission 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 * * *” Similarly, section 219(b)(3) encourages the “deployment of transmission technologies and other measures to increase the capacity and efficiency of existing transmission facilities and improve the operation of the facilities.” The Commission stated that the “reliability benefits of operation and maintenance capital spending are obvious, and we expect applicants incurring this type of capital spending will be able to demonstrate reliability benefits and thereby be eligible for incentive treatment.” [20]

19. To date, the vast majority of applications for transmission incentives filed with the Commission have focused on the enlargement of facilities, including construction of new transmission facilities. Few applications have focused on the improvement, maintenance, and operations of transmission facilities or on increasing their capacity or efficiency.[21]

Start Printed Page 30872

20. The Commission requests comment on whether there is a need for the Commission to promote the other goals set forth in the statute, such as greater efficiency, including economic efficiency, and improved operations in transmission assets through specifically tailored incentives. The use of advanced transmission technologies to bring about efficiencies and/or improved operations is discussed further and separately below. Specifically, the Commission poses the following questions.

(Q15) Pursuant to section 219(b)(1), what steps could the Commission take to “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”?

(Q16) How would these steps affect other aspects of the Commission's rate-making policy?

(Q17) Pursuant to section 219(b)(3), what steps could the Commission take to “increase the capacity and efficiency of existing transmission facilities and improve the operation of the facilities”?

(Q18) As indicated above, applicants must show that their project meets the threshold under section 219(a). What showing should the Commission require to support a request for incentives under section 219(b)(1) and (b)(3)?

C. Order No. 679 Nexus Test

21. Once a proposed project satisfies the section 219(a) statutory threshold, the applicant must demonstrate that there is a nexus between the incentive sought and the investment being made—i.e., that the incentives being requested are “rationally tailored to the risks and challenges faced” by a project.[22] In evaluating whether an applicant for incentives has satisfied the nexus test, the Commission stated that it 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 a project.[23] The nexus test is not prescriptive by design and the Commission did not specify criteria for measuring the nexus. The Commission did emphasize that the “most compelling” candidates 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.” [24]

22. As the Commission has reached case-by-case determinations on incentive applications, and faced new facts and circumstances in each case, the Commission's application of the nexus test has evolved.

23. One development with respect to the nexus test is the Commission's finding that the question of whether a project is routine or non-routine is particularly probative in evaluating whether there is a nexus between a project and the incentives sought.[25] The Commission has offered guidance on the factors that will be considered in evaluating whether a project is routine or non-routine, including: (1) The scope of a project, e.g., investment dollars, increase in transfer capability, and size of a project; 2) the effect of a project, e.g., improving reliability or reducing congestion costs; and 3) the challenges or risks faced by a project, e.g., siting, long lead times, regulatory and political risks, and financing challenges.[26]

24. Another development with respect to the nexus test involves whether that test applies to each individual project for which an applicant requests incentives, or instead applies to groups of projects. The Commission has stated that an applicant may demonstrate that several individual projects are appropriately considered as a single overall project based on their characteristics or combined purpose, and seek incentives for that single overall project.[27] The Commission has also stated that if the applicant is unable to satisfy that criterion, then the applicant may still file a single application for incentives, but the Commission will consider each individual project separately in applying the nexus test and determining whether each project is routine or non-routine.[28]

25. Thus, the nexus test has been fundamental to the Commission's implementation of Order No. 679, and the required demonstration for satisfying the nexus test has evolved over time on a case-by-case basis. The Commission is interested in comments on the following:

(Q19) Does the focus of the nexus test on the risks and challenges of a given transmission project remain appropriate for the purpose of justifying incentives? Is that focus more appropriate for some incentives than others? What other factors should the Commission consider?

(Q20) Would focusing on project characteristics or effects be a more effective means than focusing on a project's risks and challenges as the basis for granting incentives? What characteristics or effects would be appropriate for the Commission to consider for that purpose, consistent with section 219? [29]

(Q21) What risks and challenges are transmission developers facing today? Have such risks and challenges evolved since the issuance of Order No. 679, and if so how?

(Q22) Is the distinction between a routine and non-routine project in analyzing “risks and challenges” useful in providing guidance to the industry on how to apply the nexus test? Does this distinction appropriately differentiate between the level of difficulty in constructing various transmission projects?

(Q23) What types of criteria should the Commission consider when evaluating the “scope of a project” or the “effect of a project,” in determining whether a project is routine or non-routine? Should the Commission establish bright line criteria, such that a project meeting those criteria is non-routine regardless of the applicant, or should this evaluation depend on the circumstances of the applicant, e.g. the estimated cost of the project relative to the applicant's transmission rate base?

(Q24) Are there aspects of the Commission's accounting and ratemaking policies, including the use of formula rates, that reduce or increase the risks and challenges of a transmission project? If so, how should the Commission take into account the effect of its accounting and ratemaking policies in evaluating incentive applications?

(Q25) In Order No. 679-A, the Commission stated that “[i]n 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 Start Printed Page 30873contractual commitment or statute may have a bearing on our nexus evaluation of individual applications.” [30] Is the existence of a contractual commitment to build a relevant factor in considering applications for rate incentives?

(Q26) The Commission has encouraged the joint ownership of transmission facilities but declined in Order No. 679 to make it a requirement for receiving incentives.[31] Does this approach adequately account for the benefits of joint ownership? Are there other approaches to providing incentives that encourage joint ownership of transmission facilities?

D. Interrelationship of Incentives

26. In determining whether an applicant has satisfied the nexus test, the Commission evaluates the interrelationship between the requested incentives.[32] However, the Commission has stated that receiving a particular incentive does not preclude receiving other incentives.[33] The Commission seeks comment regarding whether and/or how the Commission should consider the effects of granting certain incentives in evaluating whether to grant other incentives, and at what level. The Commission seeks comment on the following:

(Q27) Are there specific criteria the Commission should use in evaluating whether and how to adjust certain incentives to account for the impacts of other incentives?

(Q28) Do certain incentives sufficiently mitigate the risks and challenges of a transmission project so as to obviate the need for granting other incentives, or warrant adjustment in the level of those incentives? For example, should granting 100 percent CWIP and recovery of the costs of abandoned plant affect the evaluation of a request for an incentive ROE adder based on a project's risks and challenges?

E. The Role of Cost Estimates

27. The Commission has generally denied proposals to limit incentives to budgeted amounts.[34] Intervenors in various transmission incentive proceedings have asserted that the Commission's incentive policies may have the unintended effect of discouraging cost containment. However, others have responded that changes in cost estimates are not due to any failure of the applicant to contain costs but are due to changes imposed on the applicant in the state siting process or other factors beyond the applicant's control that cause costs to change.

28. As noted above, the Commission created a rebuttable presumption that a project is eligible under FPA section 219 for incentive rate treatments if that project results from a fair and open regional planning process that evaluates projects for reliability and/or congestion. The submission of an estimate of project costs is part of some regional planning processes. These estimates may be used to select certain projects for development. Because the estimated and actual costs of a project may change significantly through the development and construction process, and there can be significant unknowns at the time a project is selected for development in a regional transmission planning process, the Commission seeks comment on the following:

(Q29) Should the Commission limit the application of incentives to the cost estimate utilized for including or retaining the project in the plan submitted through the regional planning process? If so, which incentives should be applied to the cost estimate, and which should be applied to all prudently incurred costs?

(Q30) How could such an approach be implemented? Would this approach work in all regions of the country? What processes for developing, evaluating, and updating cost estimates must be in place within regional transmission planning processes to facilitate such an approach?

(Q31) If a change in cost estimate is not due to the failure to contain costs but instead reflects the real cost in building the proposed transmission line, should the Commission take that consideration into account, and if so, how?

(Q32) Should new reporting requirements be in place to allow the Commission to audit compliance with a requirement to limit incentives to some project cost estimate?

F. Individual Incentives

29. Order No. 679 identified specific incentives that the Commission may grant to qualifying applicants, including: Incentive ROE adders, opportunity to recover 100 percent of prudently incurred costs of transmission facilities that are cancelled or abandoned for reasons beyond the control of the public utility, inclusion of 100 percent of prudently incurred CWIP in rate base, recovery of pre-commercial operations costs, hypothetical capital structures, accelerated depreciation, and deferred cost recovery. Below the Commission briefly explains each incentive and seeks comment on a number of questions. The Commission also poses questions immediately below on two more general matters:

(Q33) The Commission has general ratemaking policies with respect to CWIP and recovery of abandoned plant costs, as discussed below. Pursuant to Order No. 679, incentives above and beyond those general ratemaking policies may be requested on a case-by-case basis. Would it be appropriate to remove these issues from the case-by-case analysis of incentive requests, in favor of exploring changes to the Commission's general ratemaking policies? What would be the impact on ratepayers of revising these ratemaking policies, rather than authorizing higher levels of CWIP or recovery of costs of abandoned plant on a case-by-case basis?

(Q34) The Commission stated in Order No. 679 that it had not established specific eligibility criteria or conditions for incentives because it would limit the Commission's flexibility with respect to its application of the Rule. The Commission is interested in receiving comments regarding whether the establishment of criteria for eligibility for particular incentives would enhance regulatory certainty and predictability and serve to further encourage appropriate investment in transmission infrastructure. Should the Commission establish specific criteria or conditions that applicants must meet in order to be eligible for these individual incentives?

i. Incentive ROE Adder for Project Risks and Challenges

30. Under Order No. 679, the Commission allows for an incentive ROE based on a project's risks and challenges that was intended to make transmission investment more attractive where the “risks of a particular project exceed the normal risks undertaken by a utility (and hence are not reflected in a traditional discounted cash flow (DCF) analysis).” [35] An applicant's overall ROE, inclusive of any incentive ROE adder, is capped at the top end of the zone of reasonableness for the applicable proxy group under the Commission's traditional DCF analysis.

31. The Commission seeks comment on the application of this incentive, and whether the Commission considers the appropriate factors in evaluating Start Printed Page 30874whether a project is entitled to an incentive ROE adder based on a project's risks and challenges. Specifically:

(Q35) What risks and challenges are appropriately addressed by the incentive ROE adder? Is it appropriate for the Commission to evaluate these risks and challenges on a project-by-project basis or on an aggregate basis for the applicant?

(Q36) Are there other considerations that the Commission should focus on when awarding an incentive ROE adder?

(Q37) Does the base ROE adequately compensate investors for the financial risk of the company, including risks associated with the particular transmission project for which incentives are sought?

(Q38) In determining the incentive ROE adder, and the requisite risks and challenges that support such an adder, should the Commission identify with specificity the types of risks and challenges that most warrant an incentive ROE adder?

(Q39) In determining the incentive ROE adder, should the Commission make a distinction between financial barriers to transmission development such as the ability to attract capital, and regulatory barriers, such as siting or environmental challenges? If so, how?

(Q40) In determining the incentive ROE adder, how should the Commission balance the impact of other risk-reducing incentives (such as CWIP and abandoned plant recovery)?

(Q41) Does regulatory assurance of cost recovery, either at the state or regional levels, mitigate the risks and challenges facing a transmission project? If so, how should the Commission give consideration to this mitigation in evaluating a request for incentive ROE adder based on a project's risks and challenges?

ii. Other Incentive ROE Adders

32. In Order No. 679, the Commission offered incentive ROE adders for the creation of a Transco or participation in a regional transmission organization (RTO) or independent system operator (ISO). Those incentive ROE adders are discussed below.

(1) Transcos

33. In Order No. 679, the Commission addressed incentives to encourage the development of transmission only companies (i.e., Transcos),[36] and in particular, found it appropriate to “provide to Transcos a ROE that both encourages Transco formation and is sufficient to attract investment after the Transco is formed.” [37] The Commission seeks comment regarding the following questions:

(Q42) Is it appropriate to promote voluntary formation of Transcos, as defined in Order No. 679, through an ROE adder? Would other incentives promote Transco formation more effectively?

(Q43) Order No. 679 does not distinguish between Transcos that are independent of generation-owning market participants and Transcos that are affiliated with such market participants. Would such a distinction be appropriate in terms of eligibility for, or the amount of, a Transco adder?

(Q44) Further, Order No. 679 did not distinguish between Transcos that result from divestiture of a vertically-integrated utility's existing transmission system and Transcos that are created for the purpose of developing a particular new transmission facility. Would such a distinction be appropriate in terms of eligibility for, or the amount of, a Transco adder?

(2) Transmission Organizations (RTO/ISO)

34. Section 219(c) directs that the Commission “shall to the extent within its jurisdiction, provide for incentives to each transmission utility or electric utility that joins a Transmission Organization.” In pre- as well as post-Order No. 679 cases, the Commission typically has awarded a 50 basis-point ROE adder to utilities that either join or already are members of an RTO or ISO.[38]

35. While section 219 requires an incentive for membership in a Transmission Organization, the Commission invites comments on what level of the RTO/ISO ROE adder is appropriate. In particular, the Commission seeks comment on the following:

(Q45) Is it appropriate to offer a standard ROE adder for all utilities that join or remain members of an RTO/ISO?

(Q46) In the alternative, are there other incentives that the Commission should consider to encourage joining or remaining in an RTO/ISO?

(Q47) Should the existing 50 basis point adder be increased to better encourage the formation and continuance of RTO/ISO arrangements?

(Q48) Is the existing 50 basis point adder appropriately scaled to encourage the formation and continuance of RTO/ISO arrangements?

iii. Abandonment

36. Order No. 679 stated that transmission developers may be entitled to recover 100 percent of the prudently incurred costs related to certain transmission facilities if such facilities are later abandoned or cancelled. The genesis of the Commission's abandoned plant policy can be found in Opinion No. 295,[39] where the Commission stated that ratepayers and shareholders should equally share the costs of prudently incurred investments in abandoned or cancelled generation facilities. Thus, it was originally Commission policy that 50 percent of the prudently incurred costs would be amortized over the life of the plant as an expense, and the remaining 50 percent would be written off as a loss. This policy was later extended and made applicable to transmission projects.[40] In Southern California Edison (SCE),[41] the Commission granted the recovery of 100 percent of the prudently incurred costs related to certain proposed transmission facilities in the event those facilities were later cancelled or abandoned. The Commission's determination in SCE served as the foundation for the abandoned plant policy articulated in Order No. 679.

(Q49) How does the current incentive allowing recovery of 100 percent of prudently incurred abandoned plant costs affect the sharing of risks between investors and customers? Are there reasonable conditions or safeguards that could be imposed to ensure risks are appropriately allocated? For example, should recovery of abandoned plant costs be exclusive of carrying charges? Should carrying charges exclude any ROE incentive?

(Q50) Should abandoned plant costs be prohibited in instances where an affiliated project eliminates the need for a transmission project?

(Q51) Are there additional measures that can be taken to either limit the risk of abandonment, or mitigate the impact of allowing recovery of 100 percent of abandoned plant costs on customers?

(Q52) Some intervenors in various transmission incentives proceedings have raised concerns that the incentive of allowing 100 percent recovery of prudently-incurred abandoned plant costs could encourage applicants to pursue projects of greater risk. How Start Printed Page 30875should the Commission consider and address this factor?

(Q53) Should the Commission allow recovery for partial abandonment of projects? If so, how should partial abandonment be defined? What criteria should the Commission consider when deciding whether a project has been partially abandoned? What would be the consequences of the Commission allowing recovery of abandoned plant cost for a portion of a project and later denying recovery of abandoned plant costs for the entire project (e.g., finding that abandonment of the full project was under the control of the project developer)?

(Q54) If the recovery of abandoned plant costs were made contingent on the abandonment or cancellation of all or a substantial portion of a transmission project, how should the Commission define a “project” for the purpose of applying the abandoned plant incentive? The Commission has stated that several individual transmission projects may be characterized as a single project, or as several individual projects, depending on the showing made by the applicant. Should this characterization limit how an applicant may recover abandoned plant costs?

(Q55) If a project developer is granted the incentive for 100 percent recovery of abandoned plant costs, but is denied a request to recover abandoned plant costs under this incentive, then is it appropriate to recover those costs through other accounting treatments in a subsequent section 205 filing? If so, what accounting treatments would be appropriate?

(Q56) If a utility receives recovery of abandoned plant costs incentives and subsequently abandons its project, what rate of return (including incentive ROE adders), if any, should be applied to the abandoned plant costs until the costs are ultimately recovered in rates?

iv. Construction Work in Progress (CWIP) in Rate Base

37. Order No. 679 provides the opportunity for public utilities, where appropriate, to include 100 percent of prudently incurred transmission-related CWIP in rate base.[42] The Commission's general policy has been to allow only 50 percent of the non-pollution control/fuel conversion construction costs as CWIP in rate base. The remaining construction costs, including allowance for funds used during construction (AFUDC), generally would have been capitalized and included in rate base only when the plant went into commercial operation, i.e., when the plant became used and useful.[43] The Commission's policy set forth in Order No. 679 authorizes 100 percent of CWIP to be included in rate base prior to commercial operation provides utilities with additional cash flow in the form of an immediate earned return.[44] Order No. 679 also eliminated the requirement that utilities provide forward-looking cost allocation ratios based on the customers' average usage of the transmission line.

(Q57) What are the appropriate bases for evaluating a request to recover 100 percent of CWIP? Does including 100 percent of CWIP in rate base more appropriately address project specific risks and challenges or the aggregate risks and challenges associated with all projects an applicant is undertaking in a certain time period? If the aggregate risks and challenges are more appropriately addressed by including 100 percent of CWIP in rate base, how should the risks be reconciled with a Commission policy to evaluate risks and challenges on a project specific basis?

(Q58) What is the impact on ratepayers of allowing 100 percent CWIP in rate base prior to commercial operation? What kind of information should an applicant submit to make a showing that granting 100 percent CWIP will benefit consumers?

(Q59) In addition to the rate impact data required under 18 CFR 35.13(h)(31) and (32), what rate impacts tests could be considered in evaluating a request for including 100 percent of CWIP in rate base?

(Q60) Should the CWIP incentive not apply or be suspended in circumstances where an incentives project has been suspended for an indefinite period of time and there is no additional construction activity on the project?

(Q61) In the past, the Commission implemented a phasing-in of rate treatments to limit their rate impact to consumers.[45] Should the Commission consider such limits for certain incentives such as CWIP?

(Q62) If the applicant is granted an incentive ROE adder and 100 percent CWIP in rate base, should the incentive ROE adder be applied to 100 percent of CWIP included in rate base?

v. Other Incentives

1. Hypothetical Capital Structure

38. A hypothetical capital structure allows an applicant to determine its overall rate of return for revenue requirement and ratemaking purposes based on a capital structure that is usually more heavily weighted towards equity financing compared to its actual capital structure. The relatively higher cost of equity compared to the cost of debt and the heavier weighting of equity may serve to increase the overall return, enhance cash flows, lower financing costs, and improve credit ratings. In practice, the Commission has placed limitations on this incentive by requiring that the actual capital structure match the hypothetical capital structure at some point over time, such as when a project commences operations. The Commission seeks comment on the following:

(Q63) Is there a reasonable debt to equity split, or a procedure for determining such, that should be applied generally to future applications, or that can be applied generally to classifications, such as a general split for publicly owned projects and a general split for investor owned projects? Or is this best suited for case by case determination? What kind of information should an applicant provide in order to support an application for a hypothetical capital structure?

(Q64) Is there a reasonable point in time at which the actual capital structure should be required to match the hypothetical capital structure and that should be applicable generally to future applications?

2. Pre-Commercial Cost Recovery

39. In Order No. 679, the Commission permitted, as an incentive, applicants to Start Printed Page 30876expense pre-commercial costs and to recover them in current rates.[46] Absent this incentive, pre-commercial costs would generally be capitalized as part of CWIP, and subsequently earn a return on equity as well as a return of equity through depreciation, once a project goes into service. The incentive aspect of pre-commercial cost recovery allows applicants to expense and recover the costs through rates during the construction period which improves project cash flows and financial metrics, and mitigates the uncertainty over cost recovery of expenditures incurred prior to a project's regulatory approval and commercial operation. Further, for new market entrants with no established rate mechanism, the Commission has allowed the deferral of pre-commercial costs as a regulatory asset.[47] Where deferred recovery and regulatory asset treatment are provided, utilities defer the pre-commercial costs until they have an established rate structure in place, at which time they may file to recover the costs, including carrying charges,[48] generally over the construction period, or five years. The Commission seeks comment on the following questions:

(Q65) CWIP related costs should not be recorded as pre-commercial costs. What additional measures could be considered to prevent the inclusion of costs as pre-commercial that should appropriately be recorded as CWIP and recovered over the useful life of a project? In the case of deferred recovery, would limiting the period of time that carrying charges will be allowed help to ensure timely development of a project and guard against unreasonable delays?

(Q66) If incentives for both pre-commercial cost recovery on a deferred basis and 100 percent recovery of abandoned plant costs are granted, is there a relationship between the two incentives such that the Commission should review the types of costs that are included in the regulatory asset, the allowance of carrying charges, or the time period over which a regulatory asset is recovered in rates for pre-commercial cost recovery?

(Q67) Does the current practice of allowing carrying charges on deferred recovery of pre-commercial costs at the overall cost of capital, including incentive ROE adders, appropriately balance the sharing of risks of transmission project development between utility applicants and customers and affect the overall level of pre-commercial costs? How should this practice be changed to better allocate the risks between applicants and customers and to ensure that pre-commercial costs are reasonable?

3. Accelerated Depreciation

40. Accelerated depreciation is a regulatory incentive that allows an applicant to recover its return of capital costs more rapidly than under traditional regulatory treatment, e.g., 15 years or less. As a non-cash expense, accelerated depreciation may serve to enhance the applicant's cash flows and credit ratings. There have been very few incentive requests for accelerated depreciation as a transmission incentive. The Commission seeks comment on whether there are issues that the Commission should consider in reviewing this incentive.

4. Advanced Technology

41. In Order No. 679, the Commission required each applicant seeking incentives under the rule to submit a Technology Statement that describes the advanced technologies it considered for the subject project and, if those technologies are not to be employed in a project, an explanation for that decision.[49] The Commission recognized that in enacting FPA section 219 as part of EPAct 2005, Congress envisioned a connection to section 1223 of EPAct 2005, which required the Commission to “encourage, as appropriate, the deployment of advanced transmission technologies.” [50] The Commission observed that section 1223 lists 18 specific advanced transmission technologies, but also stated that this list of technologies was not intended to be exclusive and that the Commission “expect[s] new technologies to continually evolve.” [51]

42. The Commission's consideration of the required Technology Statements has evolved with experience in processing applications under Order No. 679. For example, the Commission has clarified that an applicant's proposal to use a technology listed in section 1223 does not compel the Commission to grant that applicant any particular incentives. The Commission has stated that it retains discretion to make such determinations on a case-by-case basis, noting that the Congressional directive in section 1223 requires the Commission to encourage the deployment of such technologies “as appropriate.” [52]

43. The Commission has also explained that an applicant's proposal to use advanced technologies may be relevant both as part of the Commission's nexus analysis for an incentive ROE adder based on a project's risks and challenges and as a possible basis for a separate advanced technology incentive ROE adder. In the former context, the Commission has observed that advanced technologies present “technology-related” risks and challenges that are appropriately considered under the Order No. 679 nexus test together with other types of risks and challenges associated with a project.[53] In the latter context, the Commission has stated it reviews record evidence to decide if the proposed technology warrants a separate adder because it reflects a new or innovative domestic use of the technology that will improve reliability, reduce congestion, or improve efficiency.[54] The Commission has explained the relationship between these issues, noting that consideration of an applicant's proposal to use advanced technologies as part of the nexus analysis does not necessarily mean that the applicant qualifies for a separate advanced technology incentive ROE adder.[55] As discussed above, the use of advanced technology may be relevant to achieving the goals of section 219, including increasing the efficiency of new and existing transmission facilities.

44. The Commission is interested in receiving comments on the following issues:

(Q68) Should the Commission change the way it determines what constitutes Start Printed Page 30877an “advanced” technology that is appropriate for incentives?

(Q69) Section 1223 of EPAct 2005 defines advanced transmission technology and lists technologies that fall within that definition. How should the Commission account for what Order No. 679 identified as the evolving nature of technology?

(Q70) Does the above-noted standard—examining whether a proposal reflects a new or innovative domestic use of a technology that will improve reliability, reduce congestion, or improve efficiency—strike an appropriate balance?

(Q71) Should an applicant's level of previous experience with a technology be a factor in determining whether that technology is “advanced” for purposes of evaluating a request for incentives? If an applicant has previous experience using a technology that otherwise has not been widely adopted, should that applicant's proposed use of the technology be considered “advanced”? If an applicant has no previous experience in using a technology that is otherwise widely adopted, should that applicant's proposed use of the technology be considered “advanced”?

(Q72) Where the Commission grants an incentive ROE adder for the use of advanced technology, should that adder apply to the entire cost of a project, or just to the advanced technology?

(Q73) Should incentives for advanced technology continue to be assessed on a case-by-case basis, or would it be preferable and practical to establish generic standards for advanced technology incentives? For example, should the Commission consider identifying particular technologies or applications of technology that may be appropriately granted incentives?

(Q74) What types of incentives, e.g., incentive ROE adder, accelerated depreciation, will be most effective in encouraging the deployment of advanced technology?

Comment Procedures

45. The Commission invites interested persons to submit comments, and other information on the matters, issues and specific questions identified in this notice.

46. Comments are due July 26, 2011. Comments must refer to Docket No. RM11-26-000, and must include the commenter's name, the organization they represent, if applicable, and their address in their comments.

47. The Commission encourages comments to be filed electronically via the eFiling link on the Commission's Web site at http://www.ferc.gov. The Commission accepts most standard word processing formats. Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format. Commenters filing electronically do not need to make a paper filing.

48. Commenters unable to file comments electronically must mail or hand deliver an original copy of their comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street, NE., Washington, DC 20426. These requirements can be found on the Commission's Web site, see, e.g., the “Quick Reference Guide for Paper Submissions,” available at http://www.ferc.gov/​docs-filing/​efiling.asp, or via phone from FERC Online Support at 202-502-6652 or toll-free at 1-866-208-3676.

49. All comments will be placed in the Commission's public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments on other commenters.

Document Availability

50. 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 p.m. Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.

51. 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.

52. User assistance is available for eLibrary and the FERC's website during normal business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) or e-mail at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at public.referenceroom@ferc.gov.

Start Signature

By direction of the Commission. Commissioner Moeller is concurring with a separate statement attached.

Issued: May 19, 2011.

Kimberly D. Bose,

Secretary.

End Signature

MOELLER, Commissioner, concurring:

Because regulatory certainty is critically important to those who invest in our nation's infrastructure, this Commission should ensure that if it decides to make changes to its incentive policies, it does so only prospectively. The law explicitly requires this Commission to “provide a return on equity that attracts new investment in transmission facilities” and to “provide for incentives to each * * * utility that joins a Transmission Organization.” [56] These directives from Congress would be frustrated were this Commission to increase regulatory uncertainty by changing long-held investor expectations.

As I have repeatedly stressed, this nation should have policies that encourage needed investment in transmission projects.[57] The new construction of transmission lines is often the lowest-cost way to improve the delivery of electricity service. By building needed transmission, our electrical service can maintain reliability at levels that are the envy of the world, while simultaneously improving consumer access to lower cost power generation—all while permitting more efficient and cost-effective renewable resources to compete on an equal basis with traditional sources of power.[58]

I look forward to reviewing the responses of the public on this Notice of Inquiry, as they will inform this Commission as it moves forward in its Start Printed Page 30878consideration of its incentive policy. Given my interest in getting needed transmission built, I am particularly interested in any comments regarding how our incentive policies have been successful in encouraging investment, and comments that show how our policies can be improved in a way that encourages further development of needed transmission.

Philip D. Moeller,

Commissioner.

End Supplemental Information

Footnotes

1.  Promoting Transmission Investment through Pricing Reform, Order No. 679, 71 FR 43294 (Jul. 31, 2006), FERC Stats. & Regs. ¶ 31,222 (2006), order on reh'g, Order No. 679-A, 72 FR 1152 (Jan. 10, 2007), FERC Stats. & Regs. ¶ 31,236, order on reh'g, 119 FERC ¶ 61,062 (2007).

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2.  Energy Policy Act of 2005, Public Law 109-58, §§ 1261 et seq., 119 Stat. 594 (2005).

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4.  This figure is the sum of the proposed investment amounts included in transmission incentive applications submitted to the Commission pursuant to Order No. 679, as of April 2011. However, the approval of transmission rate incentives for many of those proposed projects does not mean that all of those proposed projects have gone into service or ultimately will be completed.

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5.  In the past five years, the electric industry has experienced significant changes. Among others, such changes include the implementation of Order No. 890 transmission planning processes; adoption of mandatory and enforceable reliability standards; increasing diversity of the generation fleet; and increasing investment in the development of smart grid technologies.

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6.  16 U.S.C. 824(d) and 824(e) (2006).

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7.  Section 216 addresses designation of and siting of transmission facilities within National Interest Electric Transmission Corridors. 16 U.S.C. 824p (2006).

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8.  Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 5.

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9.  Id. P 43.

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10.  Id. P 58.

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11.  Id. P 26.

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12.  Order No. 679-A, FERC Stats. & Regs. ¶ 31,236 at P 21.

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13.  Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 22, 24.

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14.  Id. P 23, 60.

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15.  Id. P 1.

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16.  Id. P 21.

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17.  Id. P 6.

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18.  During the pendency of this proceeding, the Commission will continue to evaluate incentive requests under Order No. 679 on a case-by-case basis.

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19.  As discussed above, these processes are related to satisfying the rebuttable presumptions set forth in Order No. 679.

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20.  Id. P 56.

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21.  For example, this could include software improvements that enhance scheduling and dispatch or investment in tools to enhance self-healing grid capabilities or improved situational awareness.

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22.  Id. P 26.

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23.  Order No. 679-A, FERC Stats. & Regs. ¶ 31,236 at P 21.

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24.  Id. P 23, 60.

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25.  Baltimore Gas and Electric Company, 120 FERC ¶ 61,084 (2007).

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26.  Id. P 43.

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27.  See PJM Interconnection, L.L.C., 133 FERC ¶ 61,273 at 45 (2010) (citing PacifiCorp, 125 FERC ¶ 61,076 (2008)).

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29.  For example, this could include transmission projects that are multi-state or high voltage in nature.

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30.  Order No. 679-A, FERC Stats. & Regs. ¶ 31,236 at P 122.

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31.  Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 356, 357; Order No. 679-A, FERC Stats. & Regs. ¶ 31,236 at 102.

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32.  Order No. 679-A, FERC Stats. & Regs. ¶ 31,236 at P 21.

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34.  Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 121, n. 81; P 166. See also Virginia Electric and Power Co., 124 FERC ¶ 61,207 at P 53 (2008).

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35.  Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 27.

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36.  Order No. 679 defines a Transco broadly. Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 201.

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37.  See Id. P 221.

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38.  See Proposed Pricing Policy for Efficient Operation and Expansion of Transmission Grid, 102 FERC ¶ 61,032 (2003).

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39.  New England Power Company, 42 FERC ¶ 61,016 (1988).

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40.  Public Service Company of New Mexico, 75 FERC ¶ 61,266, at 61,859 (1996).

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41.  Southern California Edison Company, 112 FERC ¶ 61,014 (2005).

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42.  See Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 29.

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43.  There are two mutually exclusive ratemaking methodologies by which public utilities may recover financing costs (also referred to as “carrying charges”) on construction capital in rates: accrue carrying charges on CWIP in the form AFUDC or earn a return on CWIP included in rate base. Under AFUDC, carrying charges are capitalized as a component of construction and recovered from ratepayers when the completed construction project goes into service. Under CWIP in rate base, carrying charges are recovered through its return on rate base while construction is underway unlike AFUDC. CWIP in rate base increases the regulated utility's cash flow during the construction period. This in turn decreases the amount of capital the regulated utility must raise to finance construction projects, and thus may reduce the cost of capital. When a regulated utility is permitted to include CWIP in rate base, it is not allowed to also accrue AFUDC on the same construction project costs.

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44.  See Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 103 n.70 (citing 18 CFR 35.25(c)(3)).

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45.  Construction Work In Progress for Public Utilities; Inclusion of Costs in Rate Base, Order No. 298, 48 Fed. Reg. 24,323 (June 1, 1983), FERC Stats. & Regs. ¶ 30,455 (1983), clarification on order on reh'g, Order No. 298-B, 48 Fed. Reg. 55,281 (December 12, 1983), FERC Stats. & Regs. ¶ 30,524 (1983). (Where the Commission limited the rate increase due to CWIP in rate base to 6 percent in the first year and an additional 6 percent in the second year, stating that “[t]his initial limitation on CWIP in rate base ensures that, in those instances in which utilities have disproportionately large construction programs, the initial impacts of the final rule on consumers will not be severe.”).

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46.  The Commission explained that pre-commercial costs generally include, for example, expenditures for preliminary surveys, plans and investigations, made for the purpose of determining the feasibility of utility projects, and the costs of studies and analyses mandated by regulatory bodies related to plant in service which are included in Account 183. The Commission also stated that it would entertain proposals by public utilities to expense other types of costs on a case-by-case basis. Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 122.

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47.  The Commission has allowed legal fees and company formation and start-up costs to be expensed and recovered, with recovery contingent on the entity having a rate in place to recover such costs. The grant of the incentive does not create the mechanism by which to recover the costs.

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48.  Applicants seeking deferred recovery of pre-commercial costs as a regulatory asset have typically requested carrying charges on the regulatory asset from the time it is established until it is fully amortized. The Commission, in practice, permits carrying charges on pre-commercial costs at the overall cost of capital, including the incentive ROE adder.

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49.  Order No. 679, FERC Stats. & Regs. ¶ 31,222 at P 302.

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50.  Id. P 290, 302.

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51.  Id. P 290.

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52.  The Nevada Hydro Co., Inc., 122 FERC ¶ 61,272, at P 84 (2008); NSTAR Electric Co., 127 FERC ¶ 61,052, at P 27 (2009) (NSTAR).

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53.  PacifiCorp, 125 FERC ¶ 61,076, at P 51 (2008); Tallgrass Transmission, LLC, 125 FERC ¶ 61,248, at P 55 (2008) (Tallgrass).

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54.  The United Illuminating Co., 126 FERC ¶ 61,043, at P 14 (2009); NSTAR, 127 FERC ¶ 61,052 at P 27.

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55.  Tallgrass, 125 FERC ¶ 61,248 at P 59-60.

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56.  Section 219 of the Federal Power Act at 16 U.S.C. 824s.

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57.  Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities 131 FERC ¶ 61,253 (2010) (Moeller, Comm'r, concurring); NSTAR Elec. Co., 125 FERC ¶ 61,313 (2008) (Moeller, Comm'r, dissenting in part) (“* * * the Commission should do what it can to encourage capital investment in needed transmission infrastructure projects.”); Commonwealth Edison Co. and Commonwealth Edison Co. of Indiana, 125 FERC ¶ 61,250 (2008) (Moeller, Comm'r, dissenting) (“* * * now is not the time for this Commission to discourage investment in needed transmission infrastructure.”); New York Indep. Sys.Operator, Inc., 129 FERC ¶ 61,045 (2009) (Moeller, Comm'r, dissenting) (“The main issue here is whether needed transmission is being built * * * I have encouraged investment in transmission infrastructure * * *”); Southern California Edison Co., 129 FERC ¶ 61,013 (2009) (Moeller, Comm'r, dissenting in part) (“The transmission that is needed in this nation will not be built unless the companies that build it can attract adequate investment dollars.”);

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58.  Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities 131 FERC ¶ 61,253 (2010) (Moeller, Comm'r, concurring).

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[FR Doc. 2011-13150 Filed 5-26-11; 8:45 am]

BILLING CODE 6717-01-P