This PDF is the current document as it appeared on Public Inspection on 08/08/2016 at 08:45 am.
On June 27-28, 2016, the Federal Energy Regulatory Commission held a Commissioner-led technical conference to discuss issues related to competitive transmission development processes, including, but not limited to, the use of cost containment provisions, the relationship of competitive transmission development to transmission incentives, and other ratemaking and transmission planning and development issues.
All interested persons are invited to file post-technical conference comments on the questions listed in the attachment to this Notice. Commenters need not respond to all questions asked. Commenters should organize responses consistent with the numbering of the attached questions and identify to what extent their responses are generally applicable, or pertain to a particular transmission planning region. Commenters may reference material previously filed in this docket, including the technical conference transcript, but are encouraged to submit new or additional information rather than reiterate information that is already in the record. In particular, Commenters are encouraged, when possible, to provide examples in support of their answers. These comments are due on or before September 2, 2016.
For more information about this Notice, please contact:
David Tobenkin (Technical Information), Office of Energy Policy and Innovation, (202) 502-6445 email@example.com
Zeny Magos (Technical Information), Office of Energy Market Regulation, (202) 502-8244 firstname.lastname@example.org
Erica Siegmund Hough (Legal Information), Office of General Counsel, (202) 502-8251 email@example.comStart Signature
Dated: August 3, 2016.
Kimberly D. Bose,
Post-Technical Conference Questions for Comment
Panel One: Cost Containment Provisions in Competitive Transmission Development Processes 
1. How do public utility transmission providers in regions compare proposals with and without cost containment provisions for transmission facilities eligible to be selected in a regional transmission plan for purposes of cost allocation? Please provide examples. What, if any, guidance or requirements should the Commission provide with respect to the comparison of proposals with and without cost containment provisions?
2. What can public utility transmission providers in regions do to ensure there is sufficient transparency for transmission developers to understand: (a) How a proposal will be evaluated in advance of the proposal submission; (b) developments, if any, that occur during the evaluation process; and (c) the reasons the selection decision was made? Should cost containment provisions in all proposals, and not just winning proposals, be made known? What, if any, guidance or requirements should the Commission provide with respect to this issue?
3. Should there be standardization of cost containment provisions or exclusions of certain costs to facilitate comparison of proposals with differing cost containment provisions? If so, what role should the Commission and/or public utility transmission providers in regions play in pursuing standardization?
4. What quantitative and qualitative methods can public utility transmission providers in regions use to evaluate proposals with different cost containment provisions, such as cost caps with different exclusions or that cap different components of the revenue requirement?
Panel Two: Commission Consideration of Rates That Contain Cost Containment Provisions and Result From Competitive Transmission Development Processes
1. Should the Commission have a role in evaluating the rate-related components of competing proposals for transmission facilities eligible to be selected in a regional transmission plan for purposes of cost allocation (e.g., terms of cost containment provisions, rate of return, transmission incentives) before the public utility transmission providers in a region select a proposal? If so, what role? What steps could the Commission take to prevent such a role from creating undue delays in transmission planning processes?
2. What types of performance-based rates could the Commission accept to reduce asymmetrical risk?
3. The Commission has accepted proposals to allow incumbent and non-incumbent transmission developers to recover, under certain circumstances, costs associated with developing transmission projects that are proposed but not selected in a regional transmission plan for purposes of cost allocation. Should the Commission reexamine, in general, whether such costs may be recovered?
4. Which entities should monitor, verify, and/or enforce compliance with cost containment provisions of selected transmission facilities? What are effective ways for them to do so and what are the advantages and disadvantages of different approaches?
Panel Three: Transmission Incentives and Competitive Transmission Development Processes
1. Should the Commission pre-approve any or all of the following incentives for transmission facilities selected in a regional transmission plan for purposes of cost allocation through competitive transmission development processes: 100 percent construction work in progress in rate base; regulatory asset treatment; or recovery of 100 percent of the cost of abandoned facilities?
2. If there are benefits to customers from risk mitigation measures that transmission developers use in competitive transmission development processes, should the Commission revise its incentive policy to encourage similar risk mitigation measures that may provide customer benefits for Start Printed Page 52674transmission projects that are not subject to a competitive transmission development process? If so, what risk mitigation measures should the Commission encourage through application of the incentive policy?
3. In light of the emphasis that Order No. 1000 places on regional transmission planning, do the risks and challenges of a particular transmission project remain an appropriate focal point for incentives requested pursuant to Federal Power Act section 219? If not, what are the attributes that warrant incentives?
4. What, if any, changes are needed to the framework the Commission uses to evaluate return on equity adders and other transmission incentives for transmission projects that use cost containment provisions?
5. Order No. 1000 requires public utility transmission providers in regions to have an ex ante cost allocation method for transmission facilities selected in the regional transmission plan for purposes of cost allocation. To what extent does the ex ante cost allocation method reduce risks to transmission developers?
6. Transmission developers face at least two types of risks: risk associated with participation in the transmission planning processes and risk associated with developing a transmission project. The Commission's current incentive policies focus on the latter. Please comment on risks associated with participation in the transmission planning processes and indicate what, if any, changes to the planning processes could mitigate the risk.
7. Do public utility transmission providers in regions consider that a transmission developer may request and be awarded transmission incentives when evaluating transmission proposals and, if so, how? For example, how would public utility transmission providers in regions consider a proposal with a potential transmission incentive given that the incentive might or might not be granted? Should a competitive transmission development process clearly state whether, and, if so, how incentives should be part of a developer's proposal and how requests and grants of such incentives will be evaluated by the public utility transmission providers in the region? Is there an optimal time for submission of incentive requests to the Commission and for Commission decisions upon them?
Panel Four: Interregional Transmission Coordination Issues
1. What factors have contributed to the lack of development of interregional transmission facilities (i.e., a transmission facility that is located in two or more transmission planning regions)? Are there actions the Commission could take to facilitate such development?
2. What would be the advantages and disadvantages to the use of common models and assumptions by public utility transmission providers in regions in their interregional coordination processes? Are there problems that such an approach would solve or create? If such common models and assumptions could be developed, how should they be developed and by which entity or entities?
3. Should the Commission revisit Order No. 1000's requirement that an interregional transmission facility be selected in the regional transmission plan of all transmission planning regions where the facility will be located before it is eligible for interregional cost allocation? Why or why not?
4. What reforms, if any, could the Commission adopt to facilitate the identification of shared interregional transmission needs?
5. Do interregional cost allocation methods accepted by the Commission, such as the “avoided cost only” method, impede interregional transmission coordination?  If so, are there alternative cost allocation methods that could better facilitate interregional transmission development? Would those methods be consistent with interregional transmission coordination processes or would the interregional transmission coordination processes need to change to accommodate such alternative cost allocation methods?
Panel Five: Regional Transmission Planning and Other Transmission Development Issues
1. To maximize the benefits of competition, should the Commission broaden or narrow the type of transmission facilities that must be selected through competitive transmission development processes? If so, how?
2. Has the introduction of competition into the regional transmission planning processes led public utility transmission providers to focus more on developing local transmission facilities or other transmission facilities not subject to competitive transmission development processes?
3. Are there other competitive approaches compared to the existing competitive transmission development processes that could potentially reduce the time and cost to conduct the process, or the risk of litigation over proposal selection, but still benefit consumers? If so, what are the strengths and weaknesses of such approaches and could they be used in transmission planning regions in specified circumstances, for example, for transmission projects needed in the near-term to address reliability needs, in conjunction with existing competitive transmission development processes?
4. What types of information (please be specific) could be used to measure the impact of the Order No. 1000 reforms on transmission development? For example, what information could be used to evaluate whether the more efficient or cost-effective transmission facilities are being selected within and between transmission planning regions? How should that information be tracked and reported or posted? Should common metrics be developed for evaluation of the information?
5. How do the sponsorship model and competitive bidding model, respectively, and variations on these models, capture the benefits of competition, such as increased innovation and selection of the more efficient or cost-effective transmission facilities? What are the positive features and drawbacks of each model? How can their drawbacks be addressed?
6. Are changes to the Commission's current application of the Discounted Cash Flow (DCF) analysis needed to better accommodate nonincumbent transmission developers, in particular with respect to the identification of appropriate proxy groups? If so, what changes are necessary?End Preamble
1. Competitive Transmission Development Processes refer to the process to select transmission facilities in the regional transmission plan for purposes of cost allocation and the process to provide a transmission developer of a selected transmission facility with the eligibility to use the regional cost allocation method. See Further Supplemental Notice of Technical Conference, Attachment—Description of Key Concepts, Docket No. AD16-18-000, at 13 (June 20, 2016).Back to Citation
2. See, e.g., N.Y. Indep. Sys. Operator, Inc., 143 FERC ¶ 61,059, at P 326-327 (2013), order on reh'g, 148 FERC ¶ 61,044, at P 282 (2014); ISO New England Inc., 143 FERC ¶ 61,150, at PP 350-351, 398-401 (2013); and Xcel Energy Southwest Transmission Co., LLC, 149 FERC ¶ 61,182, at P 94 (2014).Back to Citation
3. See, e.g. Midcontinent Indep. Sys. Operator, Inc., 150 FERC ¶ 61,045, at PP 176-180 (2015) (describing an “avoided-cost only method” and finding such an approach can comply with Interregional Cost Allocation Principle 1).Back to Citation
[FR Doc. 2016-18826 Filed 8-8-16; 8:45 am]
BILLING CODE 6717-01-P