Stoel Rives Energy Regulation Report

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FERC Clarifies Qualifying Facility Restrictions in Sale/Resale Transactions
On May 19, the Federal Energy Regulatory Commission ("FERC") issued an order in Idaho Wind Partners I, LLC, a docket in which wind farm owners in Idaho petitioned FERC for approval of a unique transaction that would both provide eligible Renewable Energy Credits ("RECs") to a utility in California and leave the wind farm owners in a position to make a Qualifying Facility ("QF") "put" sale at avoided cost rates on the interconnecting utility. The transaction made use of an "inside-the-fence" sale of QF power and RECs to a third party, an instantaneous buy-back of the power component (but not the RECs, which had to be sold as a bundled product per California's then-current Renewable Portfolio Standard ("RPS")), and then the subsequent QF put sale to Idaho Power Company. In December 2010, the Idaho wind farms sought a declaration from FERC that, among other things, the power component remains QF power after the "inside-the-fence" transaction with the third party, and therefore the Idaho wind farms would retain the ability to put the power on the interconnecting utility. In March 2011, FERC cited precedent that allows a QF to purchase and then subsequently resell at avoided cost rates the power that was produced by another QF. Thus, if the sale and buy-back transaction is with another QF, and there is no co-mingling with non-QF power, the power would remain QF power and thus could be sold to an electric utility at avoided cost rates. The Idaho wind farms sought clarification, asking whether (i) the size, affiliation, or relative location of the third-party QF affected FERC's conclusion, and (ii) it is irrelevant if the initial third party power purchaser is a QF. On clarification, FERC confirmed that so long as the third party is a QF, the size, affiliation, or relative physical location of the third party has no effect on the QF status of the power being sold and repurchased. Consequently, any power that the Idaho wind farms sell to a QF and then buy back may subsequently be sold to an electric utility at avoided cost rates. However, FERC restated its refusal to answer the question about whether the third party's QF status is relevant. Accordingly, the Idaho wind farms' proposal to sell a bundled product for purposes of meeting California's then-current RPS is assured of working only if the wind farms can find a third-party QF offtaker. Please contact one of the attorneys listed below if you have questions about the Idaho Wind Partners order or about negotiating power purchase agreements and/or REC transactions. Idaho Wind Partners I, LLC, 135 FERC ¶ 61,154 (2011).

SunZia Transmission Obtains Approval of Ownership Structure, Anchor Tenant Proposal
On May 20, FERC granted SunZia Transmission's ("SunZia") petition for FERC's approval of the ownership structure and transmission service plans for the SunZia Southwest Transmission Project (the "Project"). SunZia had requested that each of its investor-owners be allocated ownership rights representing 100 percent of its respective pro rata investment in the Project, and that certain of the investor-owners be able to allocate up to 50 percent of their pro rata shares of transmission capacity to anchor tenants through long-term negotiated transmission contracts. In May 2010, FERC rejected SunZia's request to allocate 100 percent of the Project's transmission capacity (as opposed to ownership rights) among the owners according to their pro rata investment in the Project's capacity and ruled that the owners do not have exclusive rights to the Project's capacity equal to their share of investment in the Project. FERC approved the revised petition, stating that each owner is a transmission owner/provider of Project capacity in proportion to its investment in the Project. Consequently, SunZia's owners have ownership shares in the Project in proportion to their pro rata investment, but the owners do not have the equivalent exclusive right to capacity rights. Rather, FERC's open access policies will govern the extent to which investment in a transmission project grants a party transmission service rights. FERC also approved SunZia's proposal to allocate no more than 50 percent of certain owners' capacity to anchor tenants and to make the remaining initial capacity available through an open season process. FERC's conclusion with respect to the share allocated to an anchor tenant was consistent with the maximum allocation approved to date. In addition, FERC stated that although an owner may not allocate any of its presubscribed shares to an affiliate, certain of the owners themselves are unaffiliated with other owners, and unaffiliated owners may contract with each other as anchor tenants. FERC determined that the risks of preferential treatment among co-owners is reduced because open season participants also must be offered anchor tenant terms. Please contact one of the attorneys listed below if you have questions about the recent SunZia order or FERC's merchant transmission policies and precedent. SunZia Transmission, LLC, 135 FERC ¶ 61,169 (2011).

Midwest ISO Releases Group 5 Re-Study System Impact Study
On May 19, the Midwest ISO released the long-anticipated Minnesota Group 5 Re-Study Generator Interconnection System Impact Study, which Re-Study was ordered by FERC as the result of a cost allocation dispute between a wind developer (Community Wind) and the Midwest ISO with respect to the Brookings County-Twin Cities transmission line. In May 2010, FERC ruled that the Midwest ISO had not supported the percentage of costs for the Brookings line allocated to Community Wind in violation of the "but for" standard of cost allocation and ordered the Midwest ISO to restudy Community Wind's cost responsibility for Brookings (as well as the costs assigned to other Queue Group 5 projects). The Brookings dispute, and the underlying cost allocation drama that has been playing out in the Midwest ISO region for years, led, in part, to the new Multi-Value Project ("MVP") approach to cost allocation in the Midwest ISO. The costs of MVP projects are allocated broadly across the Midwest ISO's system rather than charged to interconnection customers. The Re-Study concludes that Group 5's total cost exposure to mitigate reliability violations without the inclusion of Brookings and another MVP-candidate transmission line (Lacrosse-Cardinal) amounts to $632.98 million, or about $300,000/MW on average. With Brookings and Lacrosse built, the group's costs rise to over $1.4 billion, $1.1 billion of which may or may not ultimately be largely allocated to interconnection customers, depending on the Midwest ISO board's decision to classify Brookings and Lacrosse as MVP projects. It is expected that the Midwest ISO will soon file the Re-Study with FERC, and then proceed to begin amending Group 5 interconnection agreements to update cost responsibilities and construction timelines, as needed. If you have questions about the Group 5 Re-Study, or would like assistance with negotiating a generator interconnection agreement, please contact one of the attorneys listed below.

A Big Day for Transmission Rate Incentives: Multiple Applications Approved, and FERC Seeks Comments on Its Policies
FERC's May 19 open meeting turned out to be positive for transmission developers, as FERC approved transmission rate incentives (or related settlements) for five transmission projects located from the Atlantic coast to the desert Southwest. The following projects were granted rate incentives under Section 219 of the Federal Power Act ("FPA"):

  • The Atlantic Wind Connection, which is planned as a 250-mile underwater DC system that will run parallel to the Mid-Atlantic coast and gather up to 6,000 MW of offshore wind for injection into the PJM Interconnection.
  • A pair of 345 kV projects under development by Ameren Services Co. that will increase transfer capability between Missouri and Illinois in the Midwest ISO region.
  • Desert Southwest Power's 188-mile, single circuit 500 kV transmission project that will provide 1,200–1,500 MW of new transfer capability from eastern Riverside County, California to southern California load.
  • Central Transmission's (an LS Power member) single circuit 345 kV Valley Project that will reduce congestion within the ComEd area of PJM Interconnection.
  • FERC also approved a settlement regarding Green Power Express's formula rate for its proposed 3,000-mile, 765 kV transmission project in the Midwest. Green Power Express was granted transmission rate incentives in 2009.

In addition, FERC issued a Notice of Inquiry in which FERC is seeking comments on the scope and implementation of transmission incentives regulations and policies under Order No. 679. Since FERC issued Order No. 679 to implement Section 219 of the FPA nearly five years ago, FERC has received over 75 applications seeking transmission rate incentives for investments in over $50 billion in transmission infrastructure. To date, the vast majority of applications filed under Section 219 have proposed new transmission expansion rather than the improvement of existing infrastructure (the latter of which is also eligible for incentives). In this Notice of Inquiry, FERC is seeking comments on its implementation of Section 219 in the following areas:

  • The rebuttable presumption for satisfying Section 219. Is it appropriate, and what other criteria should FERC adopt for applicants making this showing? What type of information should FERC consider in evaluating applications under Section 219 for applicants who cannot obtain the rebuttable presumption, and should there be established procedures for that type of applicant?
  • What steps should FERC take to promote the other goals of Section 219, such as improvement, maintenance, and operations of transmission facilities?
  • In an application under Section 219, a transmission developer must establish a nexus between the incentives sought and the risks and challenges of a project. What are the risks and challenges that transmission developers face today, and should FERC consider other criteria?
  • The interrelationship of incentives, i.e., how FERC should consider the effects of certain incentives in evaluating whether to grant other incentives, as well as on the individual incentives that are currently available to applicants. Should certain incentives have eligibility requirements, and should FERC consider creating incentives through its general ratemaking process rather than on a case-by-case basis?
  • What incentives will encourage the deployment of advanced technologies, and how should FERC determine if a technology is "advanced"?

Promoting Transmission Investment Through Pricing Reform, Docket No. RM11-26-000 (2011).

The list above is not exhaustive, and participants are encouraged to submit additional information or comments on FERC's transmission investment policies. If you are interested in responding to the Notice of Inquiry and have comments on steps FERC should take to promote additional transmission investment, please contact a key contributor.

Key Contributors

Brian J. Nese
Jason Johns
Jennifer H. Martin
Seth D. Hilton
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