The Federal Energy Regulatory Commission (FERC or “Commission”) has issued its first two orders on Order No. 1000 compliance filings. Order No. 1000 established major new transmission planning and cost allocation requirements for electric utilities regulated by FERC, with a goal of removing barriers to the development of needed transmission facilities. The order left significant implementation details to be addressed in utility compliance filings. Proposals to comply with the regional planning and cost allocation elements of Order No. 1000 were due in late 2012. FERC’s recent orders suggest that the Commission’s rulings on the regional compliance filings will provide far greater detail on FERC’s requirements for complying with Order No. 1000 and that compliance filings may be rejected based on this new detail even where the requirements in Order No. 1000 itself were unclear. These orders suggest that there will be a second wave of compliance filings needed once FERC provides this greater detail in its compliance orders.
Transmission Planning Regions & Regional Scope Requirements
In its first ruling in response to an Order No. 1000 compliance filing, FERC clarified previously unclear requirements concerning the geographic scope of a transmission planning region needed to satisfy Order No. 1000’s regional transmission planning requirements.1 Order No. 1000 requires each public utility transmission provider to participate in a regional transmission planning process that complies with the transmission planning principles of Order No. 890 (a 2007 FERC rule addressing regional planning issues) and results in the development of a regional transmission plan. Order No. 1000 specifies that a transmission planning region is one in which public utility transmission providers, in consultation with stakeholders and affected states, have agreed to participate for purposes of regional transmission planning and development of a single transmission plan and that its scope should be governed by the integrated nature of the regional power grid and the particular reliability and resource issues facing individual regions.
In furtherance of the transmission planning principles mandated by FERC’s Order No. 890, Duke Energy Carolinas, LLC (“Duke”) and Carolina Power and Light Company, d/b/a Progress Energy Carolinas (“Progress”), formed the singlestate North Carolina Transmission Planning Collaborative (NCTPC) in 2005. Duke and Progress owned and operated all of the bulk transmission system in the NCTPC. In 2008, FERC found that the NCTPC was a planning region that complies with Order No. 890. On June 8, 2012, the Commission conditionally approved a merger between Duke and Progress. The merger, consummated in July 2012, resulted in Progress becoming a wholly owned subsidiary of Duke Energy Corporation. On October 11, 2012, Duke and Progress (collectively post-merger “Duke-Progress”) and Alcoa Power Generating, Inc. (“Yadkin”) submitted a filing that identified the NCTPC as a transmission planning region to comply with the regional transmission planning and cost allocation requirements of Order No. 1000. Yadkin, a public utility transmission provider that owns and operates 21 miles of transmission facilities to service its hydroelectric generating facilities, stated that it intended to join the NCTPC.
In an order issued on February 21, 2013, the Commission held that the Duke-Progress and Yadkin compliance filings do not comply with Order No. 1000 because Duke-Progress and Yadkin have failed to identify a compliant transmission planning region. The Commission found that the merger of Duke and Progress changed the circumstances under which the Commission had examined NCTPC for compliance under Order No. 890 and that the scope of the transmission planning region specified in the Duke-Progress compliance filing and the Yadkin compliance filing does not comply with the requirements of Order No. 1000 because (1) Duke and Progress are not separate transmission providers; and (2) the addition of Yadkin does not cure that deficiency because Yadkin owns limited transmission facilities that serve only its own hydroelectric plant.
Order No. 1000 provided that an individual public utility transmission provider cannot, by itself, satisfy the regional transmission planning requirements of the order. In its February 21 order, FERC held that the notion that a compliant transmission planning region can be comprised of two “transmission providers” that report to the same senior management, board of directors and shareholders runs counter to Order No. 1000’s requirement that transmission planning occur on a regional rather than on an individual utility level. While Duke and Progress may be regulated as separate entities by the North Carolina Utilities Commission, FERC held that this fact is not dispositive as to whether Duke and Progress are separate transmission providers for purposes of Order No. 1000. The Commission found that the merger changed the way in which facilities in NCTPC are used and how they will be planned for in the future, such that the Duke-Progress transmission system is in many respects planned as if the two operating companies were a single entity.
FERC went on to find that the presence of Yadkin in the NCTPC does not satisfy the requirement of Order No. 1000 that there be more than one public utility transmission provider. Yadkin owns and operates approximately 21 miles of 13.8 kV and 100 kV transmission lines that interconnect its hydroelectric facility with Duke-Progress. Yadkin’s load consists of its own production facility, with a typical peak demand of less than 5 MW. FERC held that a public utility transmission provider cannot satisfy Order No. 1000’s regional scope requirement simply by adding to its proposed transmission planning region an entity such as Yadkin, which has very limited transmission facilities that serve its own hydroelectric facility.
FERC was not swayed by Duke-Progress’s contentions that Duke-Progress has made a commitment to municipal entities to retain the NCTPC region and that the NCTPC region provides these load-serving entities with more authority then they would have in neighboring transmission planning regions. In response to information that NCTPC has a geographic and electric scope that is similar to or greater than that of other regions, such as ISO-New England or the New York ISO, the Commission noted that those regions consist of multiple public utility transmission providers. The Commission held that Duke-Progress is not prevented from maintaining NCTPC as part of its local transmission loading planning process and that the issue with NCTPC is not that it is too small geographically or that it does not serve enough load to comply with the regional requirements of Order No. 1000.
FERC directed Duke-Progress and Yadkin to submit new compliance filings within 90 days of the date of its order (May 22, 2013).
Maine Public Service Company, a Uniquely Situated Public Utility
In FERC’s second February 21, 2013, order on Order No. 1000 compliance, the Commission granted a requested waiver of the regional transmission planning requirements for Maine Public Service Company (MPS), citing a unique geographic and electric situation that makes it impossible for MPS to meet the regional scope requirement.2
MPS is not directly interconnected to the rest of the U.S. transmission grid. Additionally MPS has a small load of 125 MW, and mostly transmission facilities of 69 kV or below. The Northern Maine Independent System Administrator (NMISA) is responsible for the administration of the northern Maine transmission system, including the MPS transmission facilities. In its compliance filing, MPS indicated that it had found it difficult to find a planning partner subject to the Order No. 1000 requirements because it is the only FERC-jurisdictional transmission provider in northern Maine. To the extent that FERC did find the NMISA regional transmission planning process satisfies the regional requirements of Order No. 1000, MPS requested waiver of those requirements.
FERC found that MPS’s unique geographic and electrical situation makes it impossible for it to join a transmission planning region that would be consistent with Order No. 1000’s regional scope requirement. The Commission stated that because MPS is not interconnected with any other public utility transmission provider, it must rely on neighboring nonpublic utility transmission providers to voluntarily comply with Order No. 1000’s requirements if it is to belong to a transmission planning region that is governed by the integrated nature of the regional power grid.
FERC went on to state that MPS was not precluded from complying with those Order No. 1000 requirements that do not depend on it being a part of a compliant transmission planning region—e.g., the requirement to consider transmission needs driven by Public Policy Requirements in its local planning process—and found that MPS’s filing did not fully comply with the applicable requirements. The Commission stated that MPS did not include a definition of Public Policy Requirements in its tariff. Additionally, MPS simply referred to state and federal Public Policy Requirements when discussing what it is required to consider in its local plan. FERC directed MPS to file a further compliance filing that includes a definition of Public Policy Requirements that is consistent with Order No. 1000, within 90 days of the date of issuance of its order (May 22, 2013). FERC indicated that this compliance filing should describe (1) the process by which MPS will select transmission needs driven by Public Policy Requirements for further evaluation and (2) the procedures in its tariff to evaluate at the local level potential solutions to identified transmission needs driven by Public Policy Requirements.