FERC Issues Seven Orders and Notice of Inquiry on Transmission Investment Incentives

On May 19 and 20, 2011, the Federal Energy Regulatory Commission (“FERC”) issued seven orders addressing requests for transmission investment incentives and a Notice of Inquiry seeking comment on the scope and implementation of its transmission incentives and regulations.  Below is a brief summary of each issuance.  

Notice of Inquiry, Promoting Transmission Investment Through Pricing Reform, Docket No. RM11-26-000: FERC has requested comment on the scope and implementation of its transmission incentive regulations and policies under Order No. 679.  In the nearly five years since FERC issued Order No. 679, it has received over 75 applications seeking a variety of different transmission incentives, and providing varied demonstrations supporting those requests.  FERC notes that the electricity industry has experienced significant changes in this time, and it has issued corresponding regulations, policy statements, and case-by-case determinations regarding incentive rate treatment.

Pursuant to Order Nos. 679, et al., FERC grants incentives for transmission projects if an applicant can show that:  (a) the project satisfies the statutory threshold in Section 219(a) of the Federal Power Act (“FPA”) by either ensuring reliability or reducing the cost of delivered power by reducing congestion; and (b) there is a nexus between the incentive sought and the investment being made.  Possible incentives under Order No. 679 include, but are not limited to, incentive adders to a base return on equity (“ROE”), recovery of costs if a project is abandoned due to factors beyond the applicant’s control, inclusion of 100% of CWIP in rate base, hypothetical capital structures, accelerated depreciation for rate recovery, and recovery of prudently incurred pre-commercial operations costs.  

Through the NOI, FERC is seeking input from stakeholders on the scope and implementation of its transmission incentives policies, and on what steps FERC should take in evaluating future requests for incentives to ensure that its incentives policies appropriately encourage the development of transmission infrastructure in a manner consistent with its other statutory responsibilities.  The NOI includes a number of overarching questions about its incentive policies under Order No. 679, as well as more specific questions regarding the FPA Section 219(a) statutory threshold, the additional goals of Section 219, the Order No. 679 nexus test, the interrelationship of incentives, the appropriate role of cost estimates in limiting incentives, and the individual incentives available under Order No. 679.  Comments on the NOI are due 60 days after publication in the Federal Register.

Comments on this NOI are very important.  In his press release, FERC Commissioner Moeller emphasized the great need to get more transmission built and he requested comments on possible improvements to the Commission's transmission incentives policy to facilitate this effort.  In their press releases, FERC Commissioners Norris and Spitzer indicated that they have no predetermined views on the NOI.  Also, Commissioner Norris posited the following question and comments: "...what level of difficulty is needed to justify incentives for risk reducers and risk return adders?  Let’s face it, every transmission line is hard to build.  If "hard" is a key factor, or even the key factor, then everything would get a risk incentive.  How do we assess and implement a policy based on level of difficulty in today’s environment for building transmission?"  Please contact us if we may assist you in drafting comments.

Central Maine Power Co., Docket No. EL08-74-001: FERC denied rehearing of its October 2008 order authorizing transmission rate incentives for Central Maine Power Company’s Maine Power Reliability Program Project.  The project involves construction of approximately 255 miles of new and rebuilt 345 kV transmission line and approximately 229 miles of new and rebuilt 115 kV line at a cost of approximately $1.4 billion.  In the October 2008 Order, FERC conditionally authorized a 125 basis point ROE adder, 100% of CWIP in rate base, and abandonment authority.  The approval was conditioned on approval of the project as a Reliability Transmission Upgrade in ISO-NE’s Regional System Plan.  

In the May 19, 2011 order, FERC denied requests for rehearing of its refusal to hold the petition in abeyance pending the Maine Public Utilities Commission’s evaluation of a CPCN application for the project.  FERC explained that it evaluates petitions for incentives under different criteria than the MPUC evaluates CPCN applications.  FERC also rejected arguments that the project is ineligible for incentives because Central Maine has a contractual obligation to build it.  In rejecting a request for rehearing based on arguments that Central Maine could have avoided or mitigated certain risks, FERC explained that it found the project to be non-routine because of special risks and challenges, and that FERC’s standard does not discount or ignore risks that may be self-inflicted.  In addition, FERC denied rehearing based on arguments that the CWIP and ROE incentives address the same risks, and arguments that incentives are unnecessary when an applicant has formula rates.  FERC also denied requests for rehearing asserting that FERC should have re-evaluated Central Maine’s base ROE, explaining that the base ROE established in a prior FERC order is not open for review in this case, but would instead be subject to review only in a separate proceeding initiated under Sections 205 or 206 of the FPA.  Finally, FERC rejected an argument that it should have considered the impact on consumers of a 125 basis point ROE adder when determining if it was just and reasonable.  

New England Conference of Public Utilities Commissioners, Inc. v. Bangor Hydro-Electric Co., Docket No. EL08-69-001: FERC denied a request for rehearing of a September 25, 2008 order denying NECPUC’s complaint against the New England transmission owners (“TOs”).  The complaint sought to enjoin the TOs from applying an incentive ROE approved in Opinion No. 489 to project costs in excess of those estimated at the time of the Opinion.  In Opinion No. 489, FERC had approved in perpetuity a 100 basis point incentive ROE adder for all ISO-NE RTEP projects.  On rehearing, FERC limited the ROE incentive granted in that Opinion to only those projects completed and placed into service by December 31, 2008.  

In June 2008, NECPUC filed a complaint arguing that the application of the ROE incentive to project costs in excess of those costs estimated at the time FERC authorized the incentive was unjust and unreasonable.  In its September 25, 2008 order, FERC denied the complaint, explaining that it had not granted the incentive based on a cost-benefit analysis that generated roughly equal results, but rather based on their RTEP status and the general benefits expected to result from the RTEP projects. Further, it found that NECPUC’s complaint was a collateral attack on Opinion No. 489, that the incentive applies only to prudently incurred costs, and that NECPUC had not shown the challenged costs to be imprudent.

In the May 19, 2011 order, FERC denied rehearing of its September 25, 2008 Order.  First, it found the Complaint to be a collateral attack on Opinion No. 489, because the crux of NECPUC’s argument is that project-specific costs should have been taken into account in granting the ROE incentive adder.  It also found that NECPUC has not identified a changed circumstance that now shows that the incentive adder as applied to the transmission projects produces and unjust and unreasonable result, noting that initial project cost estimates are based on imperfect knowledge and are subject to change.  In addition, FERC found that NECPUC had not presented compelling evidence demonstrating that the RTEP process has been compromised in light of various project increases.  Finally, FERC found that the TOs expected the adder to be applied to all prudently incurred costs, and NECPUC’s preferred outcome would have sent the wrong message to investors by creating uncertainty about whether the approved incentive could be collected on costs that are unavoidable but prudently incurred.  

Green Power Express LP, Docket No. ER09-681-000: FERC denied requests for clarification and rehearing of its April 10, 2009 order conditionally authorizing transmission rate incentives for a proposed 3,000-mile, 765 KV transmission project to interconnection 12,000 MW of new wind generation.  The order also approves a settlement agreement regarding Green Power’s proposed formula rate.  The April 10, 2009 order approved a 160 basis point ROE adder, abandonment authority, deferred recovery of pre-commercial costs, 100% CWIP in rate base, and a hypothetical capital structure.  The April 10 order also set Green Power’s proposed formula rate for hearing and settlement.  

In its May 19, 2011 order, FERC denied requests for rehearing based on arguments that FERC’s approval of incentives prior to the project’s being vetted through a regional planning or state commission process was premature.  FERC explained that it will not require participation in a regional planning process as a precondition for obtaining incentives.  The project still needs to be vetted in a regional transmission planning process and by state regulatory commissions, and the April 10 order did not modify or otherwise controvert these reviews.  If the project is modified as a result of planning or state approval processes in a way that renders invalid the basis for granting the incentives in the April 10 order, Green Power must seek approval of changes in a subsequent Section 205 filing.  FERC also rejected arguments that it had erred by not conducting a cost-benefit analysis for the project, as well as a request that the project must be approved by state regulatory processes before the proposed pro forma tariff sheets can take effect.  FERC also denied requests for rehearing based on arguments that the project did not meet the requirements of FPA Section 219, and that the applicant did not show the required nexus between the project and the requested incentives.  In rejecting requests for rehearing of FERC’s upfront ROE and ROE adder determinations, the Commission explained that mere allegations of disputed facts are insufficient to mandate a hearing; petitioners must make an adequate proffer of evidence to support them.  FERC also rejected arguments that it had not adequately considered the total package of incentives.  FERC went on to reject challenges to the approved abandonment and regulatory asset incentives.  Finally, FERC approved a settlement including Green Power’s proposed formula rate.

Ameren Services Co., Docket No. EL10-80-000: FERC granted transmission investment incentives for two of four new transmission projects, conditioned upon inclusion of the projects in Midwest ISO’s MTEP.  However, FERC denied, without prejudice, transmission investment incentives for two additional projects.  FERC found that Ameren Services had not demonstrated that its four projects are parts of a single overall project or share other characteristics that warrant reviewing the projects as a single project.  Accordingly, FERC addressed each project separately.

Projects with Approved Incentives: FERC approved incentives for the Illinois Rivers Project, consisting of a 331 mile 345 kV line with a cost of $739 million, and the Big Muddy River Project, consisting of a 185 mile 345 kV line with a cost of $383 million.  The approved incentives include:  (1) inclusion of 100% of CWIP in rate base; (2) abandonment authority; (3) hypothetical capital structure; and (4) current recovery of pre-commercial operations expenses.  FERC found that the scope and effect of these projects are significant, making them non-routine.  Each project will span multiple states and have crossings across the Mississippi River.  The river crossings will implicate major Mississippi River shipping channels, creating unusual construction risk.  These projects represent approximately 93% and 48%, respectively, of Ameren Services’ current net transmission plant of $800 million.  In addition, the Illinois Rivers Project is expected to provide congestion relief, mitigate NERC contingencies, improve reliability, integrate new renewable generation, and enhance transfer capabilities.  Similarly, the Big Muddy River Project is expected to provide congestion relief, increase north-south transfer capability, mitigate NERC contingencies, and improve reliability.  

Projects with Denied Incentives: FERC denied incentives for the Spoon River Project, consisting of a 70 mile 345 kV line with a cost of $146 million, and the Wabash River Project, consisting of a 52 mile 345 kV line with a cost of $110 million.  FERC found that these projects have not been shown to face risks and challenges comparable to the other two projects.  For example, the Spoon River Project is in a single state and represents only 18% of Ameren Services’ current net transmission plant.  The Wabash River Project represents only 14% of Ameren Services’ current net transmission plant, and does not face atypical siting, construction or financing challenges.  Further, Ameren Services has not shown that its investment in these projects will hinder its ability to maintain cash flows, thereby putting downward pressure on its finances, its credit metrics or ratings.  Because Ameren Services submitted its incentives application before FERC clarified that it will evaluate each project separately, FERC denied the incentives without prejudice to Ameren Services filing a new application with additional information on those projects.

FERC denied without prejudice Ameren Services’ request to use a 30-year depreciable life for the projects, but approved Ameren Services’ request for its transmission-owning affiliates to use the same 12.38% ROE that is available to all transmission-owner members of Midwest ISO.  FERC made no finding as to the justness and reasonableness of a formula rate that may be proposed in a future section 205 filing, but it approved Ameren Services’ request for authority to assign the CWIP and abandonment incentives to an affiliate.

Desert Southwest Power, LLC, Docket No. EL10-54-000: FERC granted transmission investment incentives for a 118 mile single-circuit 500 kV transmission line intended to transport location-constrained renewable resources from eastern California to load pocket areas in southern California by providing 1,200 to 1,500 MW of new transfer capability.  The approved incentives include: (1) 100% CWIP in rate base; (2) recovery of abandonment costs; (3) a combined 150 basis point ROE adder (reflecting incentives for future RTO participation, status as a transco, and the risks and challenges faced by the project, including those associated with the use of advanced technology); and (4) a hypothetical capital structure.  FERC rejected arguments that the filing was premature because the project has not yet been approved under CAISO’s transmission planning process.  In doing so, FERC found that Desert Southwest satisfied FPA Section 219’s requirement by demonstrating in an Economic Benefit Analysis that the project will ensure reliability or reduce the cost of delivered power by reducing congestion.  FERC found that the project is not routine, and that the applicant demonstrated that the total package of incentives is tailored to the risks and challenges faced by the applicant.  The project has significant scope, requires siting approval from several agencies, and will face significant development challenges.  It has a long lead-time, and has required significant up-front investment that exposes the project’s developers to the risk of being unable to obtain financing in a credit-constrained environment.  In addition, the project will provide access to remote, location-constrained renewable resources and is thus not routine.  It will also provide numerous regional benefits.  FERC denied without prejudice Desert Southwest’s request for the rate incentives to apply to a potential future second circuit of the project because the applicant had not adequately supported the request.

Atlantic Grid Operations A LLC, Docket No. EL11-13-000: FERC conditionally granted in part and denied in part Atlantic Grid’s request for incentive rate treatment for a 250-mile project using four 320 kV DC cables (two circuits of 1,000 MW each) to interconnect 6,000 MW of offshore wind to PJM at a cost of at least $5 billion.  The approved incentives include:  (1) an overall ROE of 12.59%, which includes 250 basis points in ROE adders (reflecting ROE incentives for RTO participation, Transco status, advanced technologies, and risks and challenges); (2) inclusion of 100% of CWIP in rate base; (3) recovery of abandonment costs; (4) a hypothetical capital structure; and (5) regulatory asset treatment.  The incentives are conditioned upon the project being included in PJM’s RTEP.  In applying the nexus test, FERC found that the project is not routine.  Specifically, FERC found that it will be constructed underwater, extend along the Mid-Atlantic coast for 250 miles, and will interconnect with the land-based transmission system in four states.  The project will cost an estimated $5 billion, involve the use of multiple advanced technologies, and require various regulatory approvals.  FERC denied Atlantic Grid’s request for approval of the use of a cost of service formula rate structure because Atlantic Grid did not provide tariff sheets or any demonstration that the formula rate will be just and reasonable.

Central Transmission, LLC, Docket No. EL11-21-000: FERC granted in part and denied in part Central Transmission’s application for transmission rate incentives for a 30 to 50-mile, single circuit 345 kV transmission line at a cost of $60 million to $125 million.  The approved incentives include:  (1) recovery of pre-commercial costs through a regulatory asset; (2) recovery of abandonment costs; (3) a 50 basis point ROE adder for RTO participation, and (4) a 30-year depreciable life.  The incentives are conditioned upon inclusion of the project as an economic enhancement in PJM’s RTEP.  In applying the nexus test, FERC found that Central Valley demonstrated that its project is non-routine, based on the project’s scope, effects, risks, and challenges.  The project is projected to reduce congestion and eliminate infeasibility issues in the ComEd area, and it is expected to meet PJM’s cost/benefit requirements for economic enhancements.  FERC found that the project faces significant risks, including those posed by potentially being the first transmission line approved as an economic enhancement through PJM’s RTEP process.  Central Transmission faces risks at the federal, state, and local level associated with creating a new public utility, and the project faces risks associated with obtaining a variety of permitting and regulatory approvals.  FERC rejected Central Transmission’s request to use a forward-looking formula rate subject to true-up, without prejudice to Central Transmission providing additional justification for such a rate in a future proceeding.

For more information, please contact Toni Frost at This e-mail address is being protected from spambots. You need JavaScript enabled to view it or 202-296-1500 or Linda Kizuka at This e-mail address is being protected from spambots. You need JavaScript enabled to view it or 202-296-1500.