NERC

On November 9, 1965 a blackout put 30 million people across the Northeastern United States and Ontario, Canada in the dark. In an effort to prevent this type of blackout from ever happening again, electric utilities formed the North American Electric Reliability Council (NERC) in 1968 to promote the reliability of the electricity supply for North America. This mission is accomplished by working with all segments of the electric industry as well as customers. NERC reviews the past for lessons learned, monitors the present for compliance with policies, standards, principles, and guides, and assesses the future reliability of the bulk electric systems.

The membership of NERC is unique. As a not-for-profit corporation, NERC's owners are ten Regional Councils. The members of these Regional Councils come from all segments of the electric industry - investor-owned, federal, rural electric cooperatives, state/municipal and provincial utilities, independent power producers, power marketers, and electricity customers. These entities account for virtually all the electricity supplied in the United States, Canada, and a portion of Baja California Norte, Mexico.

SERC

The Southeastern Electric Reliability Council (SERC) is the regional organization for the coordination of the operation and planning of the bulk power electric systems in the southeastern United States. The purpose of this coordination is to assure that the planning and operation of individual electric systems does not adversely affect other systems and that opportunities for improved system performance are identified.

SERC is one of the ten regional reliability councils constituting the North American Electric Reliability Council (NERC). NERC came into being with an agreement dated June 1, 1968, signed by 12 regional and area organizations which included from the southeast the CARVA Pool, the Tennessee Valley Authority (TVA), The Southern Company, and the Florida Electric Power Coordinating Group.

In 1969, discussions among representatives of these 4 entities indicated that the interest of reliability of the bulk power system in the southeast would be better served by the creation of a regional reliability council with broader membership. This was particularly true for the smaller systems who were not represented directly in the 4 organizations from the area which had signed the NERC agreement. This led to the signing of the SERC Agreement on January 14, 1970, by 22 electric systems.

Because of the geographic size of the region and the diversity among its parts, the region was divided into subregions for data reporting purposes. These were the VACAR subregion (Virginia and the Carolinas), the TVA subregion, and the Southern subregion (Georgia, Alabama, and part of Mississippi and panhandle of Florida), and the Florida Peninsula.

In September of 1996, the Florida peninsula became a separate NERC Region (FRCC).

Effective January 1, 1998, the Operating Companies of Entergy became official members of SERC. This added a fourth sub-region to SERC. Also joining SERC were Associated Electric Cooperative and CAJUN Electric Power Cooperative.

SERC membership is comprised of investor-owned, municipal, cooperative, state and federal systems, independent power producers, and power marketers. SERC currently has 39 member systems and 32 associate members. The Region, represented by the Council, is located in 13 states in the Southeastern United States and covers an area of approximately 464,000 square miles. The membership is comprised of investor-owned, municipal, cooperative, state and federal systems, independent power producers, and power marketers.

VACAR

The Virginia-Carolinas (VACAR) Reliability Group was formed in 1970 as a result of reliability agreements signed between Carolina Power and Light Company, Duke Power Company, South Carolina Electric and Gas Company, South Carolina Public Service Authority, and Virginia Electric and Power Company.

Duke Energy

1. Commercially viable results:

   Duke Energy’s determination of Total Transfer Capability (TTC) recognizes constraints and limitations both internal and external to the Duke Transmission System. The ATC values that Duke calculates and posts are based on the TTC values. Duke Energy’s goal in the posting of ATC is to maximize the utilization of the transmission grid while minimizing congestion on all transmission paths. Duke Energy’s calculation of the ATC Commercial Viability Indices showed that over 95 percent of the valid requests of transmission service on Duke Energy’s System were accepted and an even higher percentage of the confirmed requests were continued to completion (i.e., not curtailed).

2. Recognize time-variant conditions:

   Joint Transmission Studies performed in the VACAR-AEP-Southern-TVA-Entergy (VAST) Study Group recognize the effects of all firm and some expected transfers. In addition, Duke Energy performs sensitivity studies that evaluate the impact of simultaneous transfers on transmission constraints. The combination of these studies coupled with the real-time monitoring of the transmission system enables the Duke Transmission Provider to adjust ATC to accommodate current and expected system conditions.

3. Impact of Source/Sink:

   Both VAST Studies and internal Duke Energy Studies model system transfers based on their Control Area Source and Sink. In addition, Duke will not accept or evaluate any transmission service request unless the Control Area Source and Sink are identified in the request.

4. Wide area coordination:

   TTC values and ATC information are coordinated throughout the SERC region. The majority of this coordination is performed through the VAST Study Group using the OASIS Support Studies. The study effort provides a forum for Transmission Providers to exchange outage, load, generation, reservation, margin and other information on a scheduled basis. Duke Energy also participates in the seasonal VEM (VACAR-ECAR-MAAC) studies where similar information is exchanged.

   In addition to the VAST and VEM studies, Duke Energy is a participant in the VST studies. The VST Study Group, under the direction of the VST Steering Committee, is responsible for preparing future year base cases for a variety of purposes. These cases can be used by the Duke Energy and other VST Transmission Providers to perform transfer studies from which TTC and ATC values can be derived for this horizon. Each year or as commissioned by the VST Steering Committee, the VST Study performs a future year study.

   Duke Energy is populating and/or retrieving information to enhance the calculation of ATC through the following NERC Mechanisms:

   The Interregional Security Network (ISN),

   The System Data Exchange (SDX),

   Security Coordinator Information System (SCIS),

   Interchange Distribution Calculator (IDC),

   Transfer Distribution Factor (TDF) Viewer, and

   The Base Cases of the Multi-regional Modeling Working Group (MMWG).

   Finally, as longer-term (generally greater than a month) transmission service is requested, Duke Energy is communicating and coordinating information with neighboring providers prior to accepting and confirming the reservation.

5. Conformity to regional policies:

   Duke Energy’s ATC calculations conform to and/or are compliant with the following:

   NERC ATC Definitions and Determination Document;

   The SERC ATC Coordination Procedures;

   The NERC Transmission Capability Margins ATCWG Position Paper;

   The SERC Guidelines for Transmission Capability Margins;

   The VST, VEM, and VAST procedural manuals;

   The VACAR operating manual; and

   NERC and SERC policies, principles, guidelines and standards.

6. Accommodating uncertainties:

   Duke Energy accounts for uncertainties in actual system conditions when determining ATC and ensuring the integrity of the transmission system and generation supply.

CBM

The Capacity Benefit Margin (CBM) utilized within SERC is defined as:

Duke Energy has not defined a need for CBM on any of its interfaces in the Operating, Operational Planning, or Planning Horizons. The importing and exporting CBM on all interfaces is set to zero. The reasoning is as follows:

• Duke Control Area uses 12-hour line ratings in its calculation of TTC. When operating the system, Duke uses short-term or one-hour line ratings where available. This affords an operating margin for unexpected conditions or inaccuracies in data used in the TTC calculations.
• Duke Control Area uses the single worst transmission contingency when calculating all TTCs. These transmission contingencies may be either inside Duke Power’s Control Area or outside its boundaries. External contingency limits to TTC are verified with the owning Control Area before they are posted. Duke Energy uses adverse generation participation when calculating import TTC. This methodology is consistent with Duke Energy’s planning criteria, and it allows Duke to operate the system consistent with NERC operating guidelines. Adhering to the criteria reduces the need to maintain additional margins on Duke’s interconnections.
• In general, there are few limits to transfer that have been identified within the Duke Control Area. This fact further reduces the need for Duke to include CBM in its calculation of ATC.

Duke Energy has posted its CBM amounts (values) for each path that it posts ATC and where Duke Energy is either the source or the sink for the reservation. When Duke is requested to transmit power across its transmission system on a "through path," the lesser of the ATCs at the Point of Delivery (POD) and at the Point of Receipt (POR) is used to post ATC and evaluate whether or not the request can be accommodated. The ATC’s for the POD and POR have the declaration of CBM embedded in the calculation based on the methodology found in the NERC "Available Transfer Capability Definitions and Determination" reference document.

Duke Energy does not address generation reliability assessments through the utilization of CBM so this document does not contain the methodology and assumptions that Duke Energy uses for generation reliability requirements.

Duke Energy does not make CBM available for use on a firm basis by market entities including Duke Energy’s affiliated marketer; however, any CBM that Duke has posted would be offered on the Duke Energy OASIS node as non-firm (recallable) ATC.

TRM

The Transmission Reliability Margin (TRM) utilized within the SERC Region is defined as:

For Duke Energy, TRM is dependent upon the direction of the transfer capability across an interface. For imports, each VACAR interface is set equal to the opposing control area’s share of the VACAR reserve requirement. The importing TRM on interfaces with non-VACAR control areas is set to zero until such time as contingency reserves are identified and contracted for on those interfaces. The TRM for exports on each interface is set equal to Duke’s contractual obligation to meet the opposing Control Area’s TRM requirement.

Duke Energy’s position is that in order to declare TRM there should be a contractual obligation for reserves. When Duke has a contractual transmission reservation obligation to supply and/or receive capacity other than reserves, then Duke will show this amount as a discrete transmission reservation as opposed to TRM. For that reason, existing and new declared network resources are not counted under TRM.

The basis for the selection of paths for which Duke Energy has set aside TRM is a contractual obligation to supply and receive operating reserves to and from the members of Virginia-Carolinas Reliability Group. The contractual requirements for reserve sharing are reviewed and updated on an annual basis.

An emergency within the Virginia-Carolinas Reliability Group is the loss of a resource including the loss of a generation unit or plant or purchase (capacity). In the event of such an emergency loss, each system will make available to the other, up to the total available Contingency Reserve capacity on its system and, upon request, will attempt to obtain capacity and/or energy from a third party system.