SEC Division of Investment Management staff letter: Duke Energy Control Area Services, LLC

RESPONSE OF THE OFFICE OF Our Ref. No. 03-3-OPUR PUBLIC UTILITY REGULATION Duke Energy Control Area Services, LLC DIVISION OF INVESTMENT MANAGEMENT File No. 132-3 Based on the facts and representations in your letter of July 9, 2003, we would not recommend any enforcement action to the Commission under section 2(a)(3) of the Public Utility Holding Company Act of 1935 against Duke Energy Control Area Services, LLC ("DECA") if DECA provides the control area services described in your letter in the manner and under the circumstances described in your letter. You should note that facts or conditions different from those presented in your letter might require a different conclusion. Further, this response expresses only the Division's position on enforcement action. It does not purport to express any legal conclusion on the questions presented. avid G. LaRoche Special Counsel July 9, 2003

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549 orwcc or
DLlC UTILITY RSOULATION
July 9, 2003
Laura J. V. Szabo, Esquire
Dickstein, Shapiro, Morin & Oshinsky, LLP
2101 L Street, N.W.
Washington, D.C. 20037
Re: Duke Energy Control Area Services, LLC
File No. 132-3
Dear Ms. Szabo:
Enclosed is our response to your letter of July 9, 2003. By incorporating our answer in the enclosed copy of your letter, we avoid having to recite or summarize the facts involved. Very truly yours, David G. LaRoche Special Counsel Enclosure

DICKSTEIN SHAPIRO MORIN OSHINSKY LLP
2101 L Street NW Washington, DC 20037-1526
Tel (202) 785-9700 Fax (202) 887-0689
Writer's Direct Dial: (202) 775-4710
E-Mail Address: SzabvL@dsmv.com
July 9,2003
Associate Director
Office of Public Utility Regulation
Division of Investment Management
Securities and Exchange Commission
450 5'h Street, N.W.
Washmgton, D.C. 20549
Dear Mr. Smith:
We represent Duke Energy Control Area Services, LLC ("DECA"). On behalf of DECA, we hereby request that the Staff of the Securities and Exchange Commission (the "Commission") concur in our opinion that, for the reasons set forth below, DECA wdl not be deemed an "electric utility company" as defined in Section 2(a)(3) of the Public Udity Holdmg Company Act of 1935, as amended (the "Act" or "PUHCA") by reason of engaging in the control area services activities described below because such activities do not constitute the ownershp or operation of fachties used for the generation, transmission or distribution of electric energy for sale withm the meaning of Section 2(a)(3).
I. Background
A. DECA
DECA is a Delaware limited liability company. Duke Energy North America, LLC ("DENA"), a Delaware limited liabihty company, owns all of the DECA membershp interests. Through its subsidiaries, DENA is engaged in the development of merchant power plant companies throughout the United States. DENA's subsidaries develop, own and operate electric generation facilities for the sale of energy at wholesale as exempt wholesale generators pursuant to Section 32 of the Act ("EWGs"). DENA is an indirect, wholly owned subsidary of Duke Energy Corporation ("Duke Energy"), a North Carolina corporation. Duke Energy is an electric util~ty company that generates, transmits, distributes and sells energy in parts of North Carolina 11 77 Avenue of the Americas 41st Floor New York, New York 10036-2714 Tel (212) 835-1400 Fax (212) 997-9880 149937s v6: WIXBOGI.DOC www.legalinnovators.com

July 9,2003 and South Carolina where it has franchised service territories.' Subsidiaries of Duke Energy engage in energy related activities in North America and throughout the world, including developing, owning and operating electric generation facilities as EWGs under the Act, qualieing facilities under the Public Utility Regulatory Policies Act of 1978 ("QFs"), and foreign utility companies under the Act; marketing energy and gas at retail and wholesale; owning and operating gas pipelines and engaging in other gas related activities; and providing operation and maintenance services for generating facilities.' B. DECA Operations DECA intends to market services as a control area operator for generator company-only control areas (ea.,EWGs) as well as control areas for load-serving entities that are interconnected with, and transmission-dependent upon, another utihty ("LSEs"). To implement this plan, DECA will negotiate, on a case-by-case basis, a contract governing the control area services ("Services Agreement") to be provided to the generation company or LSE (the "~ustomer").~ Consistent with the North American Electric Reliabhty Council's ("NERC") control area standards and rules ("NERC standard^"),^ a Customer's control area will consist of the electrical system bounded by the metering and telemetry located at the point(s) at which the control area's electric facilities meet the electric facilities of the interconnecting transmission u~hty.~ In order to provide control area services to the Customer under a Service Agreement (as described below), DECA will obtain certification ' Duke Energy operates its franchised utility business as Duke Power and its electric transmission business as Duke Electric Transmission. Duke Energy does not own, either directly or indirectly, any public utility companies located in the United States. As a result of Duke Energy's acquisition of Westcoast, Duke Energy indirectly owns interests in several public utility companies located outside of the United States ("Non-US Utilities"). However, Duke Energy obtained from the Commission, by an order issued on March 8,2002, foreign subsidiary company exemptions for the Non-US Utilities under Section 3(b) of PUHCA and Duke Energy claims exempt PUHCA holding company status under Rule 10 of the Commission's PUHCA regulations. See Duke Energy Corporation, Holding Company Act Rel. No. 27496. Customers will either be non-affiliates of DECA or affiliated EWGs or QFs. DECA will not provide control area services to Duke Energy. For purposes of this letter, references herein to NERC Standards shall also include, as applicable, the standards and procedures of the applicable regional reliability council. Currently, NERC's definition of a control area is an electrical system bounded by interconnection (tie-line) metering and telemetry which controls generation to maintain its interchange schedule with other control areas and contributes to the frequency of the interconnection. NERC
Operating Manual, 1-3.

July 9,2003 by the appropriate NERC regional reliability council as a control area operator for the Customer's particular control area.6 Control area certification is obtained on a case-by-case basis and based on criteria to ensure electric system reliability. To obtain and maintain control area status, the control areas must comply with certain NERC Standards includmg the following: (i) balancing actual and scheduled energy transfers that cross control area boundaries; (ii)regulating and stabilizing interconnection frequency; and (iii) tie-line bias control which allows the control area to control its generation to match its net actual interchange to its net scheduled interchange, contribute to frequency regulation, and allow generator governors to adjust generation to respond to large frequency deviations. A control area operator must meet the following criteria in order to obtain and maintain certification as a control area operator: (a) demonstrate the abllity to comply with NERC Standards and reporting requirements; (b) have adequate and reliable communication fachties; (c) have NERC￾certified operators around the clock; (d) provide tagging services (i.e., approving tags of an energy supplier's energy schedules that comply with NERC standard^);^ (e) maintain a control center and back-up control center; and (f) coordinate with other systems and the Security Coordmator8 with respect to maintenance and protective relaying that may affect reliabihty with other systems. Pursuant to a Service Agreement negotiated with a Customer, DECA will provide the Customer with some or all of the control area services described below ("Services") for such Customer's control area. The Services essentially require DECA to monitor the Customer's operation of its electric facilities and provide recommendations on how the Customer should mod@ its operations in order to comply with control area NERC Standards. NERC requires that every LSE, generator and transmission operator that is not itself a control area operator must associate itself with a control area. See NERC Policy 1. In the past, most control area operators were vertically integrated utilities that owned and operated generation, transmission and distribution facilities. However, as the electric industry restructures and services are unbundled, generator-only companies or LSEs may benefit from establishing their own control areas. Although such entities can choose to obtain control area operator certification themselves and manage control area compliance, they can choose to outsource such services to contractors such as DECA if it is cost effective. Tags identify the source and designation of energy transactions so that control area operators can follow the path of such energy for NERC reliability purposes. For NERC purposes, a security coordinator, sometimes also referred to as a reliability coordinator (collectively referred to herein as "Security Coordinator"), is an independent entity that provides the
security assessment and emergency operations coordination for a group of control areas. Security Coordinators are not permitted to participate in wholesale or retail merchant functions. DECA is not, and will not be, a Security Coordinator. DICKSTEIN SHAPIRO MORlN OSHINSKY LLP

July 9,2003

1. Energy -. scheduling - communication services. DECA will receive the
   schedules and tags prepared by the Customer for the energy the Customer proposes to interchange (ie., move in and out of its control area) and be responsible for coordinating such schedules with the operator of the control area(s) interconnected to the Customer's control area ("Neighboring Control Area"). In such role as a
   schedule communications coordmator, DECA will act be the primary
   contact point and act as intermedary between the Customer and the Neighboring Control Area with respect to communications on such interchange schedules includmg schedule change modifications implemented by the Customer and schedule curtailments drected by the Security Coordnator. Specifically, DECA's coordmating responsibihties entail the following: (i) the Customer will transmit to DECA the Customer's proposed schedule and tags prepared by the Customer of the energy resources to be moved in and out of its control area; (ii) upon obtaining the information, DECA will be responsible for reviewing the data to determine whether the Customer's proposed schedule and tags comply with NERC Standards (ie., objective standards promulgated by NERC) and if such tags comply with NERC Standards, approving schedule tags in accordance with such NERC Standards; (iii)if the tag and proposed schedule comply with NERC Standards, DECA dtransmit the schedule to the Neighboring Control Area; (iv) if, however, DECA identifies problems with the Customer's proposed schedule or tags whlch would result in a violation of NERC Standards, DECA will notify the Customer of such problems and recommend modfications that would be required in the proposed schedule or tags to maintain compliance; (v) the Customer shall be responsible for decidmg whether to make, and then make, any appropriate changes recommended by DECA in order to comply with NERC Standards before DECA dtransmit the proposed schedules or tags to the Neighboring Control Area and if the Customer chooses not to implement necessary changes, the schedules or tags will not be submitted; and (vi) if the Neighboring Control Area has any issues with the Customer's proposed schedule or tags, it wd contact DECA who will in turn communicate such information to the Customer and if changes are required to the Customer's schedule or tags based on the Neighboring Control Area's communications, the Customer will make the appropriate revisions to its schedules and provide revised schedules or tags to DECA and DECA will follow the steps outlined in (i) through (v) above. Likewise, DECA will act as the primary point of contact between the Customer and any relevant transmission provider or other control areas in accordance with NERC Standards for interchange scheduling involving the Customer. In such role, DECA dl act as a conduit of information between the Customer and the relevant transmission provider as to the Customer's proposed tags and schedules with respect to the volume and quality of service that the Customer has

July 9,2003 contracted for with the transmission provider to move the Customer's energy. Although DECA will coordinate the Customer's schedules and tags with the Neighboring Control Area or transmission providers, as described above, DECA will not do any of the following, all of which will be the Customer's responsibility: develop schedules or tags; buy energy, capacity or ancillary services from the Customer; sell any transmission, energy, capacity or ancillary services to the Customer; or, make any economic decisions with respect to the Customer's operations or energy resources. In sum, as an energy
schedule coordinator as described above, DECA wdl be acting as a
conduit of information flow between the Customer and the Neighboring Control Areas or transmission providers.
2. Reactive supply and voltage control monitoring services. DECA will
notify the Customer of any voltage requirements for its fachties as such requirements are determined by the entity responsible for operating the facihties to which the Customer's fachties are interconnected and communicated to DECA.9 The Customer dbe responsible for complying with such voltage requirements.
3. Regulation - and frequencv response monitoring services. DECA d
calculate the frequency bias settings for the Customer's facilities in accordance with good udity practice and NERC Standards as well as the capacity and variable frequency bias that the Customer is required to provide pursuant to the NERC Standards, and notify the Customer of such requirements. Subject to the Customer's approval, DECA will move the Customer's frequency within the applicable bandwidth established by DECA pursuant to NERC Standards.
4. Inadvertent energy account monitoring service. NERC Standards
establish procedures for determining a control area's bandwidth of permissible inadvertent energy flows. NERC Standards address the permissible bandwidths for inadvertent energy flows. (Inadvertent energy is the dfference between the Customer's net scheduled energy and its net actual energy.) In accordance with NERC Standards, DECA will calculate the permissible bandwidth for the Customer's control area and notify the Customer of the parameters. DECA will monitor the Customer's control area inadvertent energy account and recommend to the Customer actions it should take in the operation of its electric facilities to minimize the inadvertent energy flows to avoid violating NERC Standards and the imposition of any applicable penalties or sanctions by third parties. Subject to the direction of the Customer, either on a case-by-case basis or through specific procedures approved by the Customer, DECA may take certain DECA will not own or operate the electric facilities interconnecting with the Customer's facilities. D~cxsrr~~ I.LI 1499375 b6; W4XBO61.DOC SHAIIRO MORIN 6 OSHINSX~

July 9,2003
5. actions to offset or reconcile inadvertent energy flows in order to minimize the amount of inadvertent energy in the Customer's account (ed., send signals to the Customer's automatic generation control ("AGC") equipment to modlfjr the energy flow). If the Customer does not take corrective action to avoid exceedmg its permitted inadvertent energy bandwidth whch could result in penalties or other sanctions, DECA will provide prior notice to the Customer with recommended corrective action. If the Customer fails to take action wih a specified time period consistent with the notice, then, consistent with NERC Standards, the Customer will be deemed to have authorized DECA, on behalf of the Customer, to take such actions within its authority as operator of the control area (ed., approving or disapproving tags), and to the extent such action was proposed by DECA in a notice, to restore inadvertent energy with the applicable bandwidth and avoid the imposition of such penalties or other sanctions though DECA will have no obligation to take such action. The Customer will be responsible for all penalties or sanctions imposed as a result of impermissible inadvertent energy imbalances. Operating - reserves coordmatina services. NERC Standards require each control area to have a specified amount of operating reserves. The operating reserves coordmating services that DECA may provide to a Customer pursuant to a Services Agreement would consist of all or some of the following. Each day DECA wdJ calculate the Customer's reserve requirement in accordance with NERC Standards and notifjr the Customer of the requirements necessitated by such NERC standards. After receiving such information from DECA, the Customer wd make the decision whether to self-supply the reserve requirements or satisfjr the reserve requirement from other sources and the Customer will be solely responsible for obtaining or maintaining the operating reserves required by the NERC Standards. Once the Customer makes its decision regarding how it wdl satisfjr its reserve requirements, the Customer wdl provide DECA with those detds, includmg the Customer's transmission arrangements, for DECA's informational purposes to assist it in monitoring the Customer's compliance with NERC Standards. In regions where there is an established reserve sharing group -ie., a group whose members consist of two or more control areas that collectively maintain, allocate, and supply the operating reserves required for each member control area -DECA may, at the Customer's request, assist the Customer in managing its reserve requirement by participating in the reserve sharing group as the agent for the Customer's control area. As the Customer's agent, DECA will advise the Customer of its reserve requirements as established by the reserve sharing group agreements and protocols and coordinate communications (ie., DECA will act as the conduit of information between the Customer

July 9,2003
6.
7. and the counterparties with respect to the reserve sharing agreements and act only in a communicator role to the Customer with regard to the steps that the Customer will need to take to comply with such arrangements). However, the Customer, and not DECA, will be responsible for procuring and/or selling operating reserves and compliance decisions with regard to the Customer's rights and obligations with respect to operating reserves or reserve sharing requirements imposed by NERC Standards or the Customer's operating reserve agreements; DECA's role is in the capacity of a communications conduit for information flow between the Customer and third parties with regard to the Customer's decisions or obligations regardmg its operating reserves. Automatic generation control technical services. DECA wdl calculate AGC operating parameters for the generating fachty (if the Customer is a generation-only company) or for all of the Customer's generation facilities or resources (if the Customer is an LSE) for the purpose of maintaining the Customer's interchange schedules and frequency regulation as described in items 1and 3 above. DECA dcalculate AGC operating parameters consistent with the NERC Standards and the operating limits of the Customer's facilities. The Customer will have the right to switch off the AGC and take any other action it deems appropriate if it determines that its fachties are in danger of damage. Control area emergency - services. Pursuant to a Service Agreement, protocols will be established and approved by the Customer whlch, inter aha, wdl provide DECA the right to take certain actions in an emergency or to avoid or mitigate an emergency (collectively, "Emergency") declared by a Security Coordinator pursuant to emergency procedures consistent with NERC Standards. DECA will coordmate such plans with the Security Coordinator. DECA dl advise the Customer of all Emergency orders and requirements of any person having authority under the NERC Standards during Emergency conditions and the Customer wdl agree pursuant to the protocols to comply with such orders and requirements. In the event of an Emergency, DECA and the Customer will agree to take such action as may be reasonable and necessary to prevent, avoid, or mitigate injury and danger to, or loss of, life or property as a result of such Emergency. During any Emergency, DECA dl be entitled to request, consistent with good utility practice, that the Customer make operational changes at its facilities, including raising or lowering voltage or electric power levels isolating the Customer's fachties, in order to eliminate, mitigate, or control such Emergency, however, the Customer will only be required to comply with the request for so long as it is reasonably necessary under good utdity practice or as drected by the Security Coordinator or the appropriate NERC regional

July 9,2003 reliability council. In Emergency conditions, DECA may also have the right to redlspatch the Customer's facility or cut facility schedules if directed by the Security Coordinator although the Customer will not have to comply with such directives to the extent they require operation of its facilities outside of safe operating limits.
8. Reporting services. DECA will perform all reporting, and provide all
reports and survey responses, that may be necessary or appropriate with respect to the Customer's control area under and in accordance with NERC Standards, and the Customer will provide DECA with such information and data as DECA may require to satisfy such reporting requirements.
9. Record keeping - and retention services. DECA dprovide all data
management, storage, retrieval, collection and organizational services as are necessary and appropriate to satisfy the requirements of the NERC Standards. DECA dhave access to the Customer's distributed control system reasonably necessary and appropriate in order for DECA to satisfy its record keeping obligations.
10. Blackstart Coordinating Services. DECA may also provide blackstart
or system restoration coordmation services as described below. By way of background, in the event of a system blackout, the Customer's control area may be required to cooperate with the Neighboring Control Area to assist in system restoration by bringing a generating unit on he at the request of Neighboring Control Area (i.e., providmg blackstart or system restoration services.'' Blackstart or system restoration procedures are a part of every control area certification. Accordingly, DECA wdl act as a coordinator between the Security Coordmator or a transmission provider (the entities that would make decisions regarding whether system restoration or blackstart service is necessary) and the Customer with respect to any blackstart or system restoration obligations the Customer may have for control area purposes. Specifically, the coordinating services DECA may provide are simply that of a communications intermediary between the Customer and the Neighboring Control Area or neighboring utilities as follows: (a) if the Customer's facilities have blackstart capability and the Customer is required by law, contract or other obligations to provide, or has otherwise decided to provide, blackstart services to restore the system, the Customer will notify DECA and provide relevant operational information; (b) DECA would communicate that information to the Security Coordinator and neighboring utilities; (c) if the Security Coordmator or neighboring 'O Blackstart or system restoration services can only be provided by hard physical assets such as generation facilities.

July 9,2003 utilities called upon the Customer to start running for black start or system restoration purposes, they will notifjr DECA and DECA, in turn, would transmit that information to the Customer (which could include operating instructions provided by the Security Coordmator or neighboring utilities) so that the Customer can make decisions on running its plant in accordance with such blackstart requirements. If the Customer has no blackstart capability, DECA would still act as a communications coordinator between the Customer and the Security Coordmator or neighboring utilities and inform the Customer when it can/should start running per the blackstart procedures transmitted to DECA by such entities or agreed to by the Customer. DECA itself would not provide black start or system restoration services since it wdl not own or control generation or transmission fachties; it will simply act as a conduit of information flow between the Customer and relevant thlrd parties with respect to the Customer's blackstart or system restoration responsibhties. Moreover, DECA wdl have no authority to impose blackstart or system restoration services on the Customer or otherwise compel the Customer to operate in accordance with any procedures applicable to the Customer; the Customer wdl make all decisions with respect to its participation in, or compliance with, blackstart or system restoration procedures. DECA expects to charge fixed fees for its Services plus fees or reimbursement for certain costs that DECA might incur to perform the Services Agreement (ea., charges for obtaining control area service certification and fees to maintain DECA's equipment used to provide Services). Other possible fee structures might be negotiated with a Customer (ea., cost plus profit, fee with incentive payments or any combination of the foregoing). However, DECA's fees wdl not be tied to the income or revenue from the Customer's electricity revenues generated from its facilities. DECA's Customers will own and operate their respective generation, transmission and/or interconnection facilities. The Customers will retain all responsibility and control for economic, business, contract administration, capital improvement, he1 procurement, operation and maintenance, and energy sale decisions and operations with respect to their fachties. DECA will have none of these responsibilities except that it may, pursuant to the Services described above, have limited authority, pursuant to the Customer's direction or procedures and standards approved by the Customer, to direct or recommend certain operations of the Customer facilities to comply with NERC Standards. As further described below, DECA personnel will not be located at the Customer's facilities nor will DECA have any "hands on" physical contact with, or responsibility for the operation or maintenance, such facilities; DECA personnel will be located at locations remote from the Customer's facilities (i.e., DECA personnel will be
stationed at DECA's

July 9,2003 offices in Houston) and communicate with the Customer or its facilities through computer or telecommunication equipment. DECA will not sell energy, capacity or ancillary services to Customers nor will it own or operate fachties that produce, transmit or distribute electric energy. DECA will own and operate certain computer, communication and telemetry equipment and software programs ("DECA Equipment") needed to perform the Services (i.e., to monitor the Customer's electric fachties, analyze its operations, and communicate to the Customer any changes in generation or electric operations that the Customer should make in order to maintain compliance with NERC Standards). Specifically, DECA will operate a control center staffed around-the-clock and equipped with computers and overhead screens and related equipment necessary to monitor information and perform the Services." DECA's software programs compile and &splay data received from external sources such as the Customer and Neighboring Control Areas and evaluate the data to ascertain compliance with control area requirements on a projected and real-time basis. DECA may install certain DECA Equipment on a Customer's facilities that is necessary to interface with, and provide information to, DECA's control centers.12 For example, in accordance with standards or protocols approved by the Customer, if the Customer has switched on its AGC equipment for its electric facllities, DECA Equipment will transmit the setpoint that wdl enable the Customer to operate in a manner that ensures that power flows over the tie line adhere to NERC Standards. Otherwise, DECA would notify the Customer by telephonic or other means of such setpoint for input by the Customer d~rectl~.'~
11. Legal Analysis
Section 2(a)(3) of the Act defines an "electric uthty company" as "any company
which owns or operates facllities for the generation, transmission, or dstribution of electric energy for sale . . . ." ("Jurisdictional Facilities"). The question presented, therefore, is whether DECA, by reason of provihng the Services to Customers as described herein, d "DECA's control center and back-up control center will not be located at any of its Customer's electric facility sites. l2 DECA will not own or operate any metering equipment. DECA may own DECA Equipment comprised of telemetry facilities required for performance of the Services, but the Customer will be responsible for maintaining any software, hardware, or technology that may be required to receive from, or transmit to, DECA to perform the Services. DECA may purchase and install the equipment the Customer will need to interface with DENA's Equipment, however, the Customer will own and operate such equipment once it is installed. l3 DECA has not yet entered into any Service Agreements with Customers but expects to begin doing so shortly. We note, however, that DECA currently provides certain of the Services as described herein to several of its affiliates under informal arrangements. DICKSTEIN SHAPlRO MORlN 61 OSHIWSKY LL?

July 9,2003 be an "electric utility company" under the Act. For the reasons stated below, we believe that DECA will not be an electric utility company for purposes of the Act. A. DECA Wdl Not Own JurisQctional Facilities As described above, the DECA Equipment is essentially technology facilities. The DECA Equipment does not produce or transmit electricity; it simply monitors the Customer's electric facilities and provides communications and data that the Customer utihzes in determining its operations. Accordingly, since DECA does not sell energy and the DECA Equipment does not function to generate, transmit or distribute electricity for sale, the DECA Equipment does not constitute Jurisdictional Facilities.14 B. DECA Wdl Not Be The "Operator" of Customer Fachties

1. Led Standard
   We have found no SEC precedent or no-action letters whch directly address the factual situation of whether a company providmg the types of services to owners of electric fachties Like those provided by DECA would be considered an "operator" within the meaning of Section 2(a)(3) of the Act. Although DECA will not be providmg mechanical operation and maintenance services hke the operation and maintenance service companies in the Ebasco line of no-action letters and Alliant case (each of whch is dscussed further below), these cases interpret the term "operates" under Section 2(a)(3) of the Act and, thus, provide guidance in determining that DECA should not be considered an electric utility company under the Act. The core legal principles for interpreting the meaning of the term "operates" as it is used in the Section 2(a)(3) definition of an electric uulity company were articulated by the Staff in Ebasco Services, Inc., SEC No-Action Letter (August 12, 1982) ("Ebasco"). In the Ebasco letter, the Staff stated that, when a company has "no investment interest in an electric utility company or its facilities, does not assume full operating responsibility [for such facilities], by contract or under a lease, or is not paid a fee related to the utility's revenues or income" such company is not deemed to be an electric utility company wih the meaning of Section 2(a)(3) of the Act. The entity in Ebasco was, through a contract, responsible for the day-to-day mechanical operation, maintenance and repair of an electrical generating facility and the provision of administrative services for a cost plus fixed fee or per diem payment arrangement. However, the Ebasco entity dd not own the facility and had no responsibdity for scheduling the facility's electrical output, bihng and collections or l4 See, eg., Sun Power Marketing, LLC, SEC No-Action Letter (July 24, 1997) (metering facilities owned by a power marketer were not considered Jurisdictional Facilities because they were not used or necessary to the power delivery function).

July 9,2003 procuring fuel supplies. Relying on the Ebasco test, the Staff has issued numerous no-action letters to service providers responsible for additional operating and maintenance services (including mechanical dspatching) because the owners of the electric facilities exercised ultimate management control over such facilities through mechanisms including pre￾approved budgets, procedures and/or standards.15 Moreover, in Colstrip and Bechtel, the operator's fee under its service agreement contained an incentive arrangement (i.e., bonus and penalties) which was based on the performance of the facilities but not revenues or income of the facility. Likewise, in Wolf Creek Operating Corp., SEC No-Action Letter (June 28, 1995) (" WolfCreekJJ), the Staff agreed not to recommend enforcement in a situation where the company providing operation and maintenance service to the Wolf Creek Nuclear Generating Station ("Station") was an affiliate of the Station owners.'' In WolfCreek, Kansas City Gas & Electric Company and Kansas City Power & Light Company each owned a 47%voting interest in both the Station and the OW Provider. The OW Provider demonstrated its lack of operating control based on the following: it did not own any interest in the Station; its fees consisted of reimbursement of its costs in proportion to l5 See, eg., Metro Energy, LLC, SEC No-Action Letter (Jan. 11,2000) (operation and maintenance provider ("O&M Provider") for generation facilities did not have an equity interest and lacked full operational responsibility for the facility because its discretion over its operating responsibilities was limited to the standards set out in the agreement which included day-to-day responsibility for the mechanical operation and maintenance of the facilities; providing personnel, materials, supplies and technical services; maintaining, servicing, and replacing equipment; procuring hel; preparing budgets; maintaining books, records and accounts; and maintaining adequate insurance coverage; fee was not tied to the facility's revenues because it consisted of a fixed component and a variable component based on a fixed charge per energy unit made available to the owner); Ogden Martin Systems of Clark Limited Partnership, SEC No-Action Letter (Dec. 6,
1993) (O&M Provider's responsibilities for generation facility included day-to-day O&M Services and
administrative service in accordance with an operating plan approved by the owner while owner, inter alia, arranged and administered the sale, scheduling, delivery and billing of electricity produced by the generating equipment and all contracts relating thereto, and obtaining and maintaining all governmental approvals); Wesmaco Corporation, SEC No-Action Letter (Aug. 26, 1996) (operator's responsibilities consisted of day-to￾day mechanical operation and maintenance of a generation facility subject to annual operating plans, budgets and procedures approved by owner, and dispatch control over the facility); Thermo Electron Corp., SEC No￾Action Letter (Nov. 3, 1993) (operator's responsibilities included day-to-day operation of the facility, certain administrative functions and partial responsibility for billing and collecting revenues); Colstrip Energy Limited Partnership, SEC No-Action Letter (Dec. 7, 1989) ("ColstripD) (operator's responsibilities included day-to￾day operation of a generation facility including mechanical dispatch of the facility's output and its fee contained bonus and penalty provisions based on the performance of the facility); Bechtel Power Corporation, SEC No-Action Letter (May 22, 1991) ("Bechtelu) (operator and general partner of owner had nearly identical responsibilities to those of operator in Colstrip). l6 See also Cobb Energy Management Corp., SEC No-Action Letter (March 23, 1999) (a subsidiary of an electric cooperative which provided day-to-day operation and maintenance of the cooperative's electric distribution system was deemed not to be an electric utility company).

July 9,2003 the owner's interest in the Station; and subject to the dtrection of the owners, the O&M Provider would provide the day-to-day operation and maintenance of the Station and technical and administrative support. The Station owners' decisionmaking authority was exercised in accordance with the operating agreement and the committees established thereunder. The owners retained responsibility for the sale of the Station's output while the O&M Provider would implement the owner's energy dispatch instructions. The O&M Provider's expenditures for the Station's operation were based on budgets approved by the owners. In Alliant ~nerg~,'~ the Commission tacitly addressed the operator issue and permitted a service provider to have significant authority over the safety and reliability decisions of the electric fachty without findtng that the service provider was an electric uulity for Section 2(a)(3) purposes. In this case, Alliant's uulity subsidiary, IES Utilities, Inc. ("IES") sought SEC approval under the Act to enter into an operating agreement with an affiliate, the Nuclear Management Company, LLC ("NMC") pursuant to whlch NMC would provide operation and maintenance services for nuclear plants owned by IES.18 In Alliant Energy, the Commission approved the parties' request to enter into the operating agreement and also acknowledged the parties' representation that NMC would not become an electric udty company under PUHCA by reason of the performance of its duties and responsibilities under the operating agreement. In connection with this acknowledgement, the order describes the following elements of the operating agreement arrangement: NMC has authority to make all decisions relating to the public health, safety and security of the nuclear facilities; NMC will not own the nuclear plants; the plant owners are entitled to all of the capacity and energy of the plants and, subject to certain safety considerations, have the right to determine the electric output of the plants; NMC wd act as agent of the nuclear plant owners in connection with the operation, management and repair of the nuclear plants; subject to certain limitations, NMC, as the agent of the plant owners, will have the authority to execute, modify, amend or terminate any contracts, licenses, purchase orders or permits relating to the operations of, or capital improvements of the plants; and, NMC would be reimbursed by the plant owners based on the costs it incurs to perform its services. l7 Affiant Energy Corp., Holding Company Act Rel. NO. 27175 (2000). The Affiant Energy order was issued under delegated authority. l8 IES was a wholly owned subsidiary of Alliant. Alliant owned an indirect 25% ownership interest in NMC. See Affiant Energy, supra. Alliant is a registered holding company under PUHCA, therefore, as subsidiaries of a registered holding company, IES and NMC applied to the SEC for approval, as required under PUHCA's afiliate rules, to enter into the operating agreement.

July 9,2003
2. Application of the Operator Legal Standard to DECA
As described in Section 1I.B above, although DECA will provide certain Services to owners of electric facihties with respect to certain facility operations and not provide "hands on" mechanical operation and maintenance services like the companies in the Ebasco line of no-action letters and Alliant, these cases are nevertheless relevant to the analysis of whether DECA would be considered an "operator" for PUHCA utility purposes because they set forth the legal standard utilized by the SEC and its staff to interpret the term "operate" under Section 2(a)(3) of the Act. Accordmgly, as demonstrated below, in applying such standards to DECA's situation, DECA should not be deemed to "operate" the electric facilities of its Customers for purposes of Section 2(a)(3) of the Act because (i) DECA will not have any ownership interest in its Customers' facilities; (ii) DECA wdl not assume operating responsibility for its Customers' facllities; and (iii) DECA wdl not be paid a fee related to the revenues or income from electricity produced by the Customers' fachties. a. Lack of Ownershp or Investment Interest DECA dl not hold legal title or any investment interest in any of its Customers' facllities. Nor wdl DECA have an investment interest in its Customers. Although some of DECA's Customers will be fiated EWGs or QFs (because they are owned by DENA or other Duke Energy subsidaries), such affiliated Customers will not be subsidaries of DECA. Therefore, to the extent DECA provides the Services to affiliates, DECA will be &e the service providers in Alliant and WolfCreek whch were fiates of the owners of the electric fachties they were servicing, although unlike the O&M Providers in Alliant and WolfCreek, DECA wdl not be involved in the physical, mechanical operations of the Customer's electric facilities. Alliant and Wolf Creek demonstrate that corporate affiliation between electric fachty service providers and owners of electric facilities is not prohibited under the investment prong of the Ebasco operator test; the Services DECA provides to the Customer are even more limited than those in the Alliant and Wolf Creek cases because they consist of remote communications and monitoring services through computer and telecommunication equipment. b. Lack of Operating Responsibihty DECA dl not have operational responsibility for its Customers' facllities, but rather it will perform certain monitoring and communication services (as described in
Section 1.B above) to ensure that the Customer's operations comply with NERC
Standards. As described in Section 1.B above, pursuant to the terms of a Service Agreement entered into by a Customer, DECA will be responsible on a day-to-day basis for monitoring and analyzing the Customer's electric operations and energy schedules and advising the Customer of operational changes that are required by the NERC Standards

. - Mr. David B. Smith
July 9,2003 and/or procedures or protocols approved by the Customer. Moreover, as described in
Section 1.B above, the Customer will be responsible for making the ultimate decisions with
regard to whether to follow and implement DECA's recommendations or communications on control area issues except that the Customer may, through protocols or procedures approved by the Customer, delegate to DECA day-to-day authority to implement certain control area actions drectly within the parameters prescribed by the Customer. For example, as described above in the description of the Services in Sections I.B.l through 10 above, the Customer will authorize DECA to approve or cut schedule tags, calculate frequency settings and operating parameters and communicate the information drectly to the Customer's AGC equipment, calculate the Customer's operating reserve requirements, manage the Customer's inadvertent energy account and take corrective action and prepare control area reports and records. However, all of the foregoing activities will be performed by DECA in accordance with standards preapproved by the Customer (eg., the NERC Standards and/or Customer preapproved procedures or protocols) and DECA will have no authority under any of its delegated responsibility to make any business decisions on behalf of the Customer; DECA wdl simply implement decisions made by the Customer. Accordmgly, like in the cases of the O&M Providers in Ebasco, Colstrip, Wolf Creek and other similar no-action letters, the Customers and not DECA will have ultimate operating responsibility for the Customer's fachties and the Customer will remain responsible for the business decisions related to energy schedules, energy sales, fuel procurement, capital investments and all other business decisions, includmg dspatch of energy resources. Indeed, the services DECA provides to the Customer are even more limited than those in the Ebasco he of cases because DECA will not be physically located at the site of the Customer's electric fachties nor will it be engaged in "hands on" operations of such facihties. The O&M Providers in those cases had significant day-to-day responsibihties for all aspects of the mechanical operation of electric facilities. Here, DECA is providing very limited communications and monitoring services associated with safety and reliability issues necessary for the Customer to maintain its ability to have a NERC sanctioned control area. As described in Section I.B.7above, in Emergency situations DECA will have the abhty to take certain unilateral actions remotely through communications with respect to operations of the facility; it needs this ability in order to maintain NERC control area certification. However, DECA's discretion is very limited in Emergency conditions. The Security Coordinator and not DECA will be the entity that declares an Emergency and DECA wdl advise the Customer of all Emergency orders and requirements of any person having authority under the NERC Standards during Emergency conditions. The Customer will agree pursuant to the Service Agreement to comply with such orders and requirements includmg requests by DECA, that are reasonably
necessary under good utility practice or as directed by the Security Coordmator or the appropriate NERC regional reliability council, to make operational changes at its facilities to eliminate, mitigate, or control such Emergency. In Emergency conditions, DECA may also have the right to redspatch the

July 9,2003
Customer's facility or cut facility schedules if drected by the Security Coordinator. The O&M Provider in Alliant had unfettered authority to make all decisions relating to the public health, safety and security facilities that it operated. Like in the case of the O&M Provider in Alliant, DECA's ability to make certain dscretionary decisions during Emergencies to preserve safety and reliability will not confer it with operating control for purposes of Section 2(a)(3) of the Act. Indeed, DECA's authority in Emergencies is more limited than that permitted in Alliant since it can only use such authority in Emergencies and not for general safety and security matters, any decisions it makes in such circumstances are either dictated by the Security Coordmator or circumscribed by relevant NERC Standards, and unlike the O&M Provider in Alliant, DECA will not be physically located at the site of the Customer's electric facilities nor will it be engaged in "hands on" operations of such fachties.
c. Fees Unrelated to Fachty Revenues
Finally, although DECA will provide communications/monitoring services and not be a physical O&M Provider as in Ebasco, Colstrip and Bechtel, hke the fee principles discussed in those no-action letters, DECA will not receive a fee for its services that is based on revenues or net income of the Customers' electric facilities. The price structure DECA uthzes for its Customers will be negotiated by the parties; however, DECA expects that it dbe a fixed fee for its Services plus fees or reimbursement for certain costs that DECA might incur to perform the Services Agreement. Though other fee structures are possible (ed., cost plus profit, fee with incentive payments or any combination of the foregoing), DECA will not receive a fee that is tied to the revenue or net income of the Customer's electric facilities operations.
C. The Public Interest Is Not Harmed by DECA's Non-Utihty Status
DECA's operations are not matters the regulation of which would serve the purposes of the Act. Section 1of the Act states that the Act is designed to protect investors, consumers and the general public from potential abuses associated with utihty ownership and control. However, as described above, DECA does not and will not function as a utility. It will not be in the business of selling, producing, transmitting or dstributing electric energy nor will it have captive customers for its Services. DECA's Customers will be responsible for conducting their power sale and transmission transactions, retaining control over the operations of their electric facilities, and making all economic and business decisions with respect to their electric energy business and the use of their facilities. Some of the Customers to which DECA wdl provide services will be EWGs, QFs or government controlled LSEs19 all of which are not public utihty companies l9 Section 2(c) of the Act exempts federal or state entities from regulation under PUHCA. W4XBO61.WC DlCKSTklN SHAVIRO MORlN 0 OSHINSKY LL? 1499375 6;

.. Mr. David B. Smith
July 9,2003 under the Act. The Staff has consistently found that no purpose would be served under the Act by imposing utility status on service providers where the owners of the electric facilities are themselves exempt under the Act." DECA Customers that are uthties within the meaning of PUHCA are already subject to any applicable regulation under the Act; thus, again, no purpose would be served in deeming DECA a utility since appropriate PUHCA protections already exist for the activities of the Customers, whlch are the entities engaging in the utility activities.
111. Conclusion
We respectfully request confirmation from the Staff that it concurs with the opinion that DECA wdl not be an electric utility company wih the meaning of the Act and wdl not recommend to the Commission to take enforcement against DECA under the Act as a result of DECA's operations and participation in the transactions described herein. If you have any questions concerning this matter or require addtional information, please do not hesitate to contact me at (202) 775-4710. Sincerely, Laura * J.V. Szabo Counsel for Duke Energy Control Area Services, LLC 20 See Metro Energy, LLC, SEC No-Action Letter (Jan. 11,2000) (O&M Provider servicing electric facilities owned by a County (i.e., state political subdivision); Louis Dreyfus Electric Power, SEC No-Action Letter (April 18, 1996) (Energy manager of the City of Dover's electric facilities and power portfolio was deemed a non-utility because it provided services the City which was exempt under Section 2(c) of the Act); Dow Chemical Canada) Inc., SEC No-Action Letter (June 9, 1994) (operator of facilities owned by an EWG is not an electric utility company).