United States: Significant Federal Energy Regulatory Commission Activity In Transmission Incentives, Planning And Cost Allocation

Last Updated: August 19 2011
Article by Bill De Grandis and Candice Castaneda

The Federal Energy Regulatory Commission ("FERC" or the "Commission") has recently taken significant action with regard to transmission incentives, planning and cost allocation. Virtually every industry group involved in buying, selling or consuming wholesale electric power, as well as in developing power plants, will be affected. You will want to determine how your organization is affected and to assess what steps your organization should take to protect your interests, and to ensure compliance, where applicable.

First, in May 2011, the Commission issued its Notice of Inquiry on Promoting Transmission Investment Through Pricing Reform (the "Transmission NOI"), seeking in depth comment on all aspects of its transmission incentive policies. Second, this July, the Commission followed up on its Notice of Proposed Rulemaking regarding Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities (the "NOPR") by issuing a final rulemaking in Order No. 1000 ("Order No. 1000" or the "Order"). This client alert summarizes Order No. 1000 and the Transmission NOI for a comprehensive update on critical transmission issues today.

Order No. 1000 contains many layers of procedural and substantive requirements or goals with regard to regional transmission planning and cost allocation of new transmission facilities and lines resulting from such planning measures. Until the compliance filings are accepted and steps taken pursuant to such plans, it will be difficult to assess whether actual progress will be made. Will these measures succeed by leading to transmission facilities being developed and constructed on a timely basis with their costs equitably allocated? Or will the new framework lead to a heavily federalized electric transmission planning process, with challenges or objections raised with the Commission at various stages, with resolution of such disputes unduly delaying the transmission planning and development process? While each affected organization will likely have a very different perspective on the answers to these questions, depending on its place in the industry, there should be little debate that the reach and scope of Order No. 1000 is far reaching and will impact virtually any organization involved in some way in constructing power plants or transmission facilities, or using the country's transmission system for electric power purchases, sales or deliveries.

Any requests for rehearing of Order No. 1000 are due August 22, 2011. Comments on the Transmission NOI are due September 12, 2011.

Order No. 1000: Transmission Planning and Cost Allocation Rulemaking

The NOPR That Led To Order No. 1000

Last June 17, 2010, the Commission issued its transmission planning and cost allocation NOPR. Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Notice of Proposed Rulemaking, 131 FERC ¶ 61,253 (2010). The NOPR proposed rules building on Order No. 8901 and sought to address intra- and interregional electric transmission planning and cost allocation of transmission facilities. Specifically, the NOPR addressed i) who should plan for new transmission and ii) who should pay for the new transmission facilities. The most significant changes proposed to the transmission planning and cost allocation regulations were the NOPR's proposals to remove the right of first refusal ("ROFR") of incumbent utilities and to impose new cost allocation requirements and principles.

According to the Commission, the ROFR gave incumbent public utilities the right to build proposed transmission facilities within their service territory even if a merchant entity was planning to build something similar in the area. Regarding transmission cost allocation, the NOPR proposed a "beneficiary pays" principle. Each transmission provider would have to establish a cost allocation method for new facilities in its regional transmission plan and for new facilities resulting from planning agreements implemented by neighboring regions. The NOPR also proposed to require revisions to public utility transmission providers' open access transmission tariffs ("OATTs") to demonstrate compliance with the new rules. The NOPR additionally provided the Commission's expectation that both jurisdictional and non-FERC jurisdictional entities would participate in the NOPR transmission planning processes.

Paul Hastings' August 2010 Client Alert on the NOPR (available here) provides a summary of the NOPR and this alert builds on that discussion now that the final rule was issued July 21, 2011.

The NOPR generated over 200 comments by interested parties and even commentary by members of the United States Senate. Certain entities, for example, questioned the Commission's legal authority to impose the proposed changes. Others supported the "beneficiary pays" concept, but emphasized that cost allocation should be based on real, quantifiable benefit consistent with Illinois Commerce Commission v. Federal Energy Regulatory Commission, 576 F3d 470, 476 (7th Cir. 2009). That cost allocation process involves identifying specific and measurable benefits, and then allocating costs in a way roughly commensurate with benefits. Many intervenors, including Senator Bob Corker, warned against socializing costs and others requested that the Commission clarify that public policy requirements should only be considered through the bottom-up transmission planning process provided in Order No. 890.

Order No. 1000

Over a year since the NOPR, the Commission has now acted and issued Order No. 1000, its new transmission planning and cost allocation rulemaking. Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, 136 FERC ¶ 61,051 (2011).2 All of the FERC Commissioners provided statements on Order No. 1000. FERC Chairman Jon Wellinghoff noted in support of the Order that "[t]he key driver of the action we consider today in this Final Rule is reliable transmission service at just and reasonable rates."3 The Chairman also emphasized the increase expected in renewable energy resources and the need for additional transmission to support integration of those renewable resources into the bulk power system over the next decade. Chairman Wellinghoff noted in his statement, however, that Order No. 1000 is technology neutral. In contrast,

FERC Commissioner Phillip Moeller was more critical, noting in his partial dissent that the rulemaking should have gone further and characterized Order No. 1000 as mainly addressing long-distance transmission lines. Order No. 1000 (Moeller, P., dissenting in part). As illustrated below, most of the proposals described above and contemplated in the NOPR came to fruition in Order No. 1000. The following include the main provisions of Order No. 1000 and reflect some of the Commission's responses to the various comments received on the NOPR:

  • Transmission Planning Requirements:
  • Public utility transmission providers must participate in a regional transmission planning process that satisfies the principles of Order No. 890 and produces a regional transmission plan.4
  • Local and regional transmission planning processes must consider Public Policy Requirements established by laws or regulations, though there is no requirement that any particular transmission facility be considered with regards to such Public Policy Requirements.
    • The Commission found that current requirements under Order No. 890 are inadequate to meet this objective.
    • Order No. 1000 states that its reference to Public Policy Requirements means "public policy requirements established by state or federal laws or regulations....By 'state or federal laws or regulations,' we [FERC] mean enacted statutes (i.e., passed by the legislature and signed by the executive) and regulations promulgated by a relevant jurisdiction, whether within a state or at the federal level." Order No. 1000 at P 2.
    • FERC Commissioner Cheryl LaFleur provided in her separate statement regarding the Order, that an example of such Public Policy Requirements includes the requirements in 28 states and the District of Columbia that utilities "purchase a sizable and growing portion of their supply from renewable resources." The Order also references renewable portfolio standards.5
    • Chairman Wellinghoff stated that Order No. 1000 takes into account those state policies and works to ensure "adequate transmission to serve those state needs."6
  • Public utility transmission providers must establish procedures to identify transmission needs driven by Public Policy Requirements and evaluate proposed solutions. Order No. 1000 at P 206.
  • Public utility transmission providers in neighboring transmission planning regions must coordinate efforts in finding solutions to common transmission needs, and thereby engage in interregional transmission coordination. Id. at PP 369-73.
  • The Commission notes that it is not prescribing "the exact manner in which public utility transmission providers must fulfill the requirements of complying with the regional transmission planning principles." Id. at P 157. Consequently, the Commission is not proposing additional rules regarding stakeholder procedures or planning cycles, not establishing timelines for evaluating regional transmission projects in the regional transmission planning process, nor did it add additional requirements to the Order No. 890 dispute resolution transmission planning principles. Id.
  • Transmission Cost Allocation Requirements:
  • Public utility transmission providers must participate in a regional transmission planning process that has a regional cost allocation method for new transmission facilities selected for purposes of cost allocation.
  • If a region cannot decide on a method, the Commission will choose one. Id. at PP 9, 482.
  • A key component of the cost allocation initiative in Order No. 1000 is that the cost allocation method must satisfy the following principles:

1. Costs allocated roughly commensurate with estimated benefits

2. Those who do not benefit from transmission do not have to pay for it

3. Benefit-to-cost thresholds must not exclude projects with significant net benefits

4. No allocation of costs outside a region unless other region agrees

5. Cost allocation methods and identification of beneficiaries must be transparent

6. Different allocation methods could apply to different types of facilities. Id. at PP 587, 604.

  • Public utility transmission providers in non-regional transmission organization ("RTO") areas must reach agreement with other public utility transmission providers in the planning region on a transmission cost allocation methodology. See, e.g., id. at P 485.
  • Public utility transmission providers in neighboring transmission planning regions must have a common interregional cost allocation method for new interregional transmission facilities. The method must satisfy cost allocation principles similar to those listed above.
  • Note though, there is no requirement to engage in interconnectionwide planning and the Commission is not requiring public utility transmission providers in one region to adopt the methods of another with which it engages in interregional transmission coordination. Id. at PP 9, 735.
  • Participant-funding of new transmission facilities is permitted generally, but not allowed as either the regional or interregional cost allocation method, because the Commission expressed concern that participant-funding as a cost allocation method would increase the incentive for individual beneficiaries to defer investment in the hopes that another beneficiary will value a project enough to provide the funding. Id. at PP 723-29.
  • Stakeholder participation is an important aspect of Order No. 1000 and discussed throughout the Order.
  • As the Commission explains, "[a]t its core, the set of reforms adopted in this Final Rule require the public utility transmission providers in a transmission planning region, in consultation with their stakeholders, to create a regional transmission plan." Id. at P 11. The Commission adds that the reforms regarding regional transmission planning are geared towards ensuring that "stakeholders have an opportunity to express their needs, have access to information and an opportunity to provide information, and thus participate in the identification and evaluation of regional solutions." Id. at P 150. Stakeholder participation is also discussed in the context of interregional coordination and cost allocation. With regard to applying the new rules regarding Public Policy Requirements, for example, the Commission explains, "[a]t a minimum, however, we require that all such procedures allow for input from stakeholders, including but not limited to those responsible for complying with the Public Policy Requirement(s) at issue and developers of potential transmission facilities that are needed to comply with one or more Public Policy Requirements." Id. at P 208.
  • If stakeholders do not feel that they have been given an appropriate opportunity to participate in transmission planning and cost allocation, they can raise concerns in their region's compliance proceedings in response to the Order or may seek to raise a complaint for non-compliance with the requirements of Order No. 1000.
  • ROFR Reforms:

Order No. 1000 states that public utility transmission providers must remove the ROFR for a transmission facility selected in a regional transmission plan for purposes of cost allocation from FERC-approved tariffs and agreements, subject to the following four limitations:

  • The removal of ROFR does not apply to a transmission facility not selected in a regional transmission plan for purposes of cost allocation (this limitation would encompass facilities listed in a regional transmission plan for information or other non-cost allocation purposes). Id. at P 318;
  • The removal of ROFR does not apply to upgrades. Id. at P 319;
  • Public utility transmission providers in a transmission planning region may use competitive bidding to solicit projects or developers. Id. at PP 321, 336; and
  • The requirement does not affect state or local rules regarding construction of transmission facilities (including rules related to siting or permitting). Id. at P 287.

The Commission also adds that incumbent transmission providers could continue to propose transmission projects as part of the transmission planning and cost allocation process. Id. at PP 262, 264. Order No. 1000 declines to implement the proposal that would have guaranteed project sponsors project rights for a defined period of time. Id. at P 334.

  • Reliability Concerns:

Order No. 1000 requires public utility transmission providers to amend their tariffs to require reevaluation of regional transmission plans to determine whether delays in development of a transmission facility requires evaluation of alternative solutions to meet the transmission need, including solutions proposed by incumbents, to ensure that incumbents can meet reliability needs or service obligations. Id. at P 263. In her statement, Commissioner LaFleur emphasized that this requirement, along with i) the fact that ROFR still applies to upgrades to existing facilities and transmission facilities not selected in a regional transmission plan for purposes of cost allocation, and ii) that incumbents may still submit projects, work together to protect an incumbent's right to build transmission needed to meet reliability obligations.

In addition, the Commission addresses the intersection between Order No. 1000 and the NERC Reliability Standards. The Commission explains that if public utility transmission providers "follow[ ] the NERC approved mitigation plan, the Commission will not subject that public utility transmission provider to enforcement action for the specific NERC reliability standard violation(s) caused by a nonincumbent transmission developer's decision to abandon a transmission facility." Id. at P 344.

  • Non-Public Utilities:

Order No. 1000 also addresses concerns raised as to the application of the rulemaking to nonpublic utilities, by stating that participation by non-public utilities in Order No. 1000's requirements while expected, is voluntary.

In particular, the Commission in Order No. 1000 states:

In response to G&T Cooperatives and others, we note that the Commission is not acting here under the FPA to require non-public utility transmission providers to participate in regional transmission planning processes or to agree to a method or methods for allocating the costs of their transmission facilities. Under the reciprocity provision, if a public utility transmission provider seeks transmission service from a non-public utility transmission provider to which it provides open access transmission service, the non-public utility transmission provider that owns, controls or operates transmission facilities must provide comparable transmission service that it is capable of providing on its own system. A non-public utility transmission provider that elects to receive such service, therefore, must do so on terms that satisfy the reciprocity condition. Id. at P 819.

Order No. 890 summarized the principle of reciprocity by explaining:

Under the reciprocity provision ..., if a public utility seeks transmission service from a non-public utility to which it provides open access transmission service, the non-public utility that owns, controls, or operates transmission facilities must provide comparable transmission service that it is capable of providing on its own system. Under the pro forma OATT, a public utility may refuse to provide open access transmission service to a non-public utility if the non-public utility refuses to reciprocate. Order No. 890 at P 163.

The language in Order No. 1000 may cloud the principle of reciprocity, because it appears to state without equivocation that if a non-public utility receives open access transmission service from a public utility it must provide comparable transmission service that it is capable of providing on its own system. However, reciprocity as stated under Order No. 890 would allow the non-public utility to refuse to do so, but in return the public utility could refuse to provide service to it.

Also, Order No. 1000 states that if a non-public utility transmission provider chooses to join a transmission planning region and is determined under the transmission planning process to benefit from facilities selected for purposes of cost allocation, that non-public utility will be allocated costs associated with the benefits. Order No. 1000 at P 629. This would seem to follow from the "beneficiary pays" cost allocation principle. Left unsaid is whether non-public utilities that do not join transmission planning regions cannot be allocated costs associated with facilities selected in the regional transmission planning process for purposes of cost allocation.

  • Merchant Transmission Projects:

Order No. 1000 provides that merchant transmission developers may participate in regional transmission planning processes, however, as they assume the risk for the projects being developed, are not required to participate if the developer does not seek to use the regional cost allocation process. As a caveat to this, Order No. 1000 states that regional transmission plans must require merchant transmission developers to provide information allowing the region to assess potential reliability and operational impacts of the proposed facilities. Id. at PP 163-64.7

  • Compliance Filings:
  • Public utility transmission providers must make compliance filings on most of the issues addressed in Order No. 1000. Regional transmission coordination plans and cost allocation methods must be filed with the Commission by October 11, 2012. Interregional transmission coordination plans and cost allocation methods must be filed with the Commission by April 11, 2013. Id. at P 792.
  • As described above, the Commission noted that public utility transmission providers must consult with stakeholders when developing and implementing compliance filings. Id. at PP 792-98.
  • Reviewing Order No. 1000, it is readily apparent that many complicated issues, such as the geographic scope of transmission planning regions, processes for interregional coordination, and cost allocation methods, may be addressed not as part of the Order No. 1000 docket but instead in compliance filing proceedings. For example, Order No. 1000 states that rules regarding interregional coordination apply to entities in non-RTO regions, however, the Commission declines to implement its interregional coordination requirements in non-RTO regions by requiring certain actions, such as mandating that public utility providers in such non-RTO regions form planning consortia. The Commission states, "[p]ublic utility transmission providers are free to do so; however, we do not want to foreclose other approaches to meeting the interregional transmission coordination requirements." Id. at P 420. With regards to cost allocation methods, the Commission states that "[w]ith the exception of the limitation on participant funding ..., we decline to prejudge any particular method or set of methods generically in this Final Rule." Id. at P 606.
  • Transmission Planning Region Map
  • The Commission's presentation on Order No. 1000 also incorporated the following map generally depicting current transmission planning regions. These regions, as depicted, may be what the Commission means when it refers in Order No. 1000 to the transmission planning regions, although the Commission accepts that the geographic scope of the regions may change as the Order No. 1000 processes develop and decided "not [to] prescribe in this Final Rule the georgraphic scope of any transmission planning region." Id. At P160.

  • The presentation also noted, that the "Those borders [in the map] may not be depicted precisely for several reasons (e.g., not all transmission providers complying with Order No. 890 have a defined service territory). Additionally, transmission planning regions could alter because transmission providers may choose to change regions."8
  • Generation Interconnection Rules Not Affected
  • The Commission made clear that its generation interconnection rules under Order No. 2003 are not affected by Order No. 1000. See e.g., Order No. 1000 at P 760. This might disappoint some industry participants and FERC practitioners, because new network upgrades might be planned to accommodate siting of new generators as well as enhance reliability. So the same network upgrade might arise in two different contexts (i.e., regional transmission planning and generator interconnection), and therefore be subject to two different sets of cost allocation rules. The potential disconnect of applying two different sets of rules to the same transmission line could lead to delays in the development and construction of new transmission lines.

This summary only touches upon the over 800 paragraph order. Parties should review Order No. 1000 to understand its full scope and meaning. Any requests for rehearing on Order No. 1000 will be due August 22, 2011.

Notice of Inquiry: Promoting Transmission Investment Through Pricing Reform

On May 19, 2011, the Commission issued the Transmission NOI. Promoting Transmission Investment Through Pricing Reform, Notice of Inquiry, 135 FERC ¶ 61,146 (2011). Through 74 questions, the Transmission NOI seeks to examine every aspect of the Commission's transmission incentive policy. The sets of questions posed by the Commission regarding its transmission incentives make it immediately clear that the Commission is contemplating a major change in its implementation of the transmission incentive policy. Specifically, the Commission's questions reveal that it is considering applying a criteria-based approach to analyzing requests for transmission incentives, as opposed to the purely case-by-case approach that currently exists. Comments are due September 12, 2011.

In the Transmission NOI, the Commission states that in Order No. 679,9 "[t]he Commission stated that it would not establish such criteria 'at [that] time,' on the grounds that to do so 'now would limit the flexibility of the Rule.' Instead, ... the Commission required that each applicant satisfy the statutory threshold set forth in section 219(a) [of the Federal Power Act ("FPA")], 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 made." Transmission NOI at P 5 (quoting Order No. 679 at P 43).

The Commission does not propose or appear to be considering eliminating these principles; however, it is interested in refining them. FERC Commissioner John Norris wrote that while he believed that the Commission after Order No. 679 "got the train headed down the right track...it has been five years since Order No. 679 was issued and the Commission began implementing FPA section 219.... This NOI gives us a chance to assess our successes and perhaps mistakes and request input on how we may be able to improve our policies..."10 Commissioner Norris went on to highlight some areas that he was particularly interested in, including: (a) his expectation that costs for transmission will go up and that transmission is needed; (b) the relationship between increases in transmission costs and the share of increases represented by incentive rates and cost overruns; (c) incentive adders for RTO and independent transmission company status (implying his uncertainty as to the current need for those incentives); and (d) what level of difficulty is needed to justify incentives.

These sets of issues demonstrate that the Commission is taking a hard look at whether it should reform implementation of its transmission incentive policy and how. It also shows FERC's evaluation of whether to switch to a more criteria-based approach to making rate determinations, which Platts journalist Esther Whieldon stated that the Commission views as "more art than science" and quoted Chairman Wellinghoff as characterizing as "a very difficult and continually moving target."11

Overview of the Transmission NOI's 74 Questions

The Transmission NOI's 74 questions can be split into 15 general categories (although there is some overlap).

1. Overarching questions regarding FERC's Transmission incentive policy including its effectiveness and how to deal with barriers to construction that fall outside of FERC's jurisdiction. (Questions 1- 9). Transmission NOI at P 15.

2. Questions regarding the section 219(c) statutory threshold, including the current rebuttable presumption that states that a proposed project meets the statutory threshold if the project either results from a fair and open regional planning process that considers reliability and/or congestion, or has received construction approval from a state commission or siting authority. (Questions 10- 14). Id. at PP 16-17.

3. Requests for comments on whether the Commission is meeting all of the goals in section 219 of the FPA and how it can accomplish those goals. The Commission indicates that it believes that the goals for "improvement, maintenance, and operations of transmission facilities or on increasing their capacity or efficiency" may have been neglected and need further attention. (Questions 15- 18). Id. at PP 18-20.

4. Questions on the nexus test. Here FERC notes that it has previously not used criteria to evaluate the nexus test and requests comments on whether and what types of criteria FERC should use. FERC also appears to be questioning whether the nexus test is always appropriate. (Questions 19-26). Id. at PP 21-25. FERC also stated it was considering a change to its evaluation of contractual commitments and mandatory projects. FERC stated that in Order No. 679-A, it found that while such contractual commitments or mandatory projects did not disqualify a request for incentive based treatment, they might have a bearing on nexus test evaluation. Id. at P 25, Question 25 (citing Order No. 679-A at P 122). Then, FERC asked whether the existence of contractual commitments is relevant.

5. Questions regarding evaluating the interrelationship between incentives. For example, asking "[a]re there specific criteria the Commission should use: evaluating whether and how to adjust certain incentives to account for the impacts of other incentives?" and whether granting certain incentives obviates the need for others. (Questions 27-28). Id. at P 26.

6. A request for comments on whether cost estimates for projects should be factored into evaluation of incentives. This would be a significant change if pursued, because as FERC noted, "[t]he Commission has generally denied proposals to limit incentives to budgeted amounts." Id. at P 27. (Questions 29-32). Id. at PP 27-28.

7. Questions on whether the Commission should make specific incentives, namely construction work in progress ("CWIP") and recovery of abandoned plant costs the subject of specific rate making policies, thereby removing them from the current case-by-case analysis. The Commission also requested comments on whether it should apply specific eligibility criteria for particular incentives. (Questions 33-34). Id. at P 29.

8. Questions on application of return on equity ("ROE") adders, including an evaluation of risk and balancing other incentives against ROE. (Questions 35-41). Id. at PP 30-31.

9. FERC also followed up with questions on ROE adders for specific activities, including creation of transmission only companies. (Questions 42-44). Id. at PP 32-33.

10. And for joining RTOs and independent system operators. (Questions 45-48). Id. at PP 34-35.

11. Questions on recovery of abandonment costs. FERC notes that the policy originally allowed recovery of 50% of prudently incurred costs of abandoned facilities and later allowed 100% recovery. FERC asks how this incentive impacts risks, when it should apply, for measures to reduce risk of abandonment, and whether partial abandonment should be permitted. (Questions 49-56). Id. at P 36.

12. Requests for comments on permitting inclusion of 100% prudently incurred transmission-related CWIP in rate base. This includes questions on how to evaluate requests for CWIP, the impact of CWIP, whether it should apply to suspended projects, and if the Commission should apply a phasing in of rate treatments. The Commission also asks for comment on the interaction between CWIP and ROE incentives. (Questions 57-62). Id. at P 37.

13. Questions on the hypothetical capital structure including whether there is a point in time when the actual capital structure should be required to match the hypothetical. (Questions 63-64). Id. at P 38.

14. Questions on the incentive permitting applicants to expense pre-commercial costs and to recover them in current rates (rather than as part of CWIP) and sometimes defer their recovery. FERC asks how it can better prevent CWIP costs being recorded as pre-commercial costs, the relationship between pre-commercial costs and abandonment costs, and the impact of allowing carrying charges on deferred recovery of pre-commercial costs at the overall cost of capital impact risk. (Questions 65-67). Id. at P 39.

15. Finally, FERC asked a series of questions on accelerated depreciation and advanced technology. FERC noted that use of advanced technologies is relevant to nexus analysis, risk analysis, and to achieving the goals of section 219. FERC's set of questions includes asking whether experience with a technology should matter in determining whether that technology is advanced and whether FERC should establish generic standards for advanced technology incentives. This reveals that FERC is placing specific emphasis on Advanced Technology incentives, such as ROE adders, accelerated depreciation or others, and evaluating how to apply incentives. (Questions 68-74). Id. at PP 40-44.

Through the Transmission NOI, FERC is seeking information on how it may refine implementation of its transmission incentive policy. The most significant potential change is the Commission's consideration of the use of specific criteria and generic standards in implementation of transmission incentives, as opposed to the case-by-case approach that currently exists. As FERC Commissioner Marc Spitzer stated "[t]he NOI is designed to seek input from all interested stakeholders on how [FERC] may more effectively implement our incentive program. Those who think we have been too generous, as well as those who think we have not granted adequate levels of incentives to encourage transmission investment, should take advantage of this opportunity to inform us of their positions and what next steps they think we should take on incentives."12

Comments are due on the Transmission NOI on September 12, 2011.

Footnotes

1 See Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh'g, Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007), order on reh'g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh'g, Order No. 890-C, 126 FERC ¶ 61,228 (2009), order on clarification, Order No. 890- D, 129 FERC ¶ 61,126 (2009).

2 For more information, please see the FERC website on Transmission Planning and Cost Allocation, http://www.ferc.gov/industries/electric/indus-act/trans-plan.asp (last visited Aug. 8, 2011).

3 Statement of Chairman Jon Wellinghoff on Transmission Planning and Cost Allocation, Docket No. RM10-23-000 (July 21, 2011).

4 Public utility transmission providers mean public utilities, subject to the Commission's jurisdiction, that own, operate or control facilities used for the transmission of electric energy in interstate commerce. See e.g. 18 CFR 385.3(k) (defining Transmission Provider in the context of standards of conduct for transmission providers).

5 Statement of Commissioner Cheryl A. LaFleur, Docket No. RM10-23-000 (July 12, 2011). See also e.g., Order No. 1000 at P 29.

6 Transcript of Interview with FERC Chairman Jon Wellinghoff, Bloomberg Television's "Taking Stock"(July 21, 2011).

7 Merchant Transmission Projects are defined as "those for which the costs of constructing the proposed transmission facilities will be recovered through negotiated rates instead of cost-based rates." Id. at P 119.

8 FERC Special Presentation on Order No. 1000, Docket No. RM10-23-000, Slide 4 (Jul. 22, 2011).

9 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).

10 Statement of Commissioner John R. Norris, Docket No. RM11-26-000 (May 19, 2011).

11 Esther Whieldon, After five years, FERC transmission incentive policy to receive thorough review, Inside Platts, May 23, 2001, at 12-13.

12 Statement of Commissioner Marc Spitzer, Docket No. RM11-26-000 (May 19, 2011).

The content of this article does not constitute legal advice and should not be relied on in that way. Specific advice should be sought about your specific circumstances.

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In your use of the Website and/or Services you shall: comply with all applicable laws, regulations, directives and legislations which apply to your Use of the Website and/or Services in whatever country you are physically located including without limitation any and all consumer law, export control laws and regulations; provide to us true, correct and accurate information and promptly inform us in the event that any information that you have provided to us changes or becomes inaccurate; notify Mondaq immediately of any circumstances where you have reason to believe that any Intellectual Property Rights or any other rights of any third party may have been infringed; co-operate with reasonable security or other checks or requests for information made by Mondaq from time to time; and at all times be fully liable for the breach of any of these Terms by a third party using your login details to access the Website and/or Services

however, you shall not: do anything likely to impair, interfere with or damage or cause harm or distress to any persons, or the network; do anything that will infringe any Intellectual Property Rights or other rights of Mondaq or any third party; or use the Website, Services and/or Content otherwise than in accordance with these Terms; use any trade marks or service marks of Mondaq or the Contributors, or do anything which may be seen to take unfair advantage of the reputation and goodwill of Mondaq or the Contributors, or the Website, Services and/or Content.

Mondaq reserves the right, in its sole discretion, to take any action that it deems necessary and appropriate in the event it considers that there is a breach or threatened breach of the Terms.

Mondaq’s Rights and Obligations

Unless otherwise expressly set out to the contrary, nothing in these Terms shall serve to transfer from Mondaq to you, any Intellectual Property Rights owned by and/or licensed to Mondaq and all rights, title and interest in and to such Intellectual Property Rights will remain exclusively with Mondaq and/or its licensors.

Mondaq shall use its reasonable endeavours to make the Website and Services available to you at all times, but we cannot guarantee an uninterrupted and fault free service.

Mondaq reserves the right to make changes to the services and/or the Website or part thereof, from time to time, and we may add, remove, modify and/or vary any elements of features and functionalities of the Website or the services.

Mondaq also reserves the right from time to time to monitor your Use of the Website and/or services.

Disclaimer

The Content is general information only. It is not intended to constitute legal advice or seek to be the complete and comprehensive statement of the law, nor is it intended to address your specific requirements or provide advice on which reliance should be placed. Mondaq and/or its Contributors and other suppliers make no representations about the suitability of the information contained in the Content for any purpose. All Content provided "as is" without warranty of any kind. Mondaq and/or its Contributors and other suppliers hereby exclude and disclaim all representations, warranties or guarantees with regard to the Content, including all implied warranties and conditions of merchantability, fitness for a particular purpose, title and non-infringement. To the maximum extent permitted by law, Mondaq expressly excludes all representations, warranties, obligations, and liabilities arising out of or in connection with all Content. In no event shall Mondaq and/or its respective suppliers be liable for any special, indirect or consequential damages or any damages whatsoever resulting from loss of use, data or profits, whether in an action of contract, negligence or other tortious action, arising out of or in connection with the use of the Content or performance of Mondaq’s Services.

General

Mondaq may alter or amend these Terms by amending them on the Website. By continuing to Use the Services and/or the Website after such amendment, you will be deemed to have accepted any amendment to these Terms.

These Terms shall be governed by and construed in accordance with the laws of England and Wales and you irrevocably submit to the exclusive jurisdiction of the courts of England and Wales to settle any dispute which may arise out of or in connection with these Terms. If you live outside the United Kingdom, English law shall apply only to the extent that English law shall not deprive you of any legal protection accorded in accordance with the law of the place where you are habitually resident ("Local Law"). In the event English law deprives you of any legal protection which is accorded to you under Local Law, then these terms shall be governed by Local Law and any dispute or claim arising out of or in connection with these Terms shall be subject to the non-exclusive jurisdiction of the courts where you are habitually resident.

You may print and keep a copy of these Terms, which form the entire agreement between you and Mondaq and supersede any other communications or advertising in respect of the Service and/or the Website.

No delay in exercising or non-exercise by you and/or Mondaq of any of its rights under or in connection with these Terms shall operate as a waiver or release of each of your or Mondaq’s right. Rather, any such waiver or release must be specifically granted in writing signed by the party granting it.

If any part of these Terms is held unenforceable, that part shall be enforced to the maximum extent permissible so as to give effect to the intent of the parties, and the Terms shall continue in full force and effect.

Mondaq shall not incur any liability to you on account of any loss or damage resulting from any delay or failure to perform all or any part of these Terms if such delay or failure is caused, in whole or in part, by events, occurrences, or causes beyond the control of Mondaq. Such events, occurrences or causes will include, without limitation, acts of God, strikes, lockouts, server and network failure, riots, acts of war, earthquakes, fire and explosions.

By clicking Register you state you have read and agree to our Terms and Conditions