-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, DzZrmFPP1QS7mRgfnVOBshwiV2YtcsSNDwwohOsVaFcRGeADet2doyRdfTA7OArj YK9e7rzTV2NBHH0BVDH4Bg== 0001160661-02-000004.txt : 20021009 0001160661-02-000004.hdr.sgml : 20021009 20021009153323 ACCESSION NUMBER: 0001160661-02-000004 CONFORMED SUBMISSION TYPE: 424B3 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 20021009 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHERN POWER CO CENTRAL INDEX KEY: 0001160661 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 582598670 FILING VALUES: FORM TYPE: 424B3 SEC ACT: 1933 Act SEC FILE NUMBER: 333-98553 FILM NUMBER: 02785099 BUSINESS ADDRESS: STREET 1: 600 N 18TH ST. CITY: BIRMINGHAM STATE: AL ZIP: 35291 BUSINESS PHONE: 4045067146 MAIL ADDRESS: STREET 1: 241 RALPH MCGILL BLVD STREET 2: NE BIN 10116 CITY: ATLANTA STATE: GA ZIP: 30308 424B3 1 sopower424final.txt Filed Pursuant to Rule 424(b)3 Registration No. 333-98553 $575,000,000 SOUTHERN POWER COMPANY A SUBSIDIARY OF (SOUTHERN COMPANY LOGO) OFFER TO EXCHANGE ALL OUTSTANDING 6.25% SENIOR NOTES, SERIES A DUE JULY 15, 2012 FOR 6.25% SENIOR NOTES, SERIES B DUE JULY 15, 2012 (REGISTERED UNDER THE SECURITIES ACT OF 1933) THE EXCHANGE OFFER WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON NOVEMBER 6, 2002, UNLESS EXTENDED We are offering you the opportunity to exchange your 6.25% Senior Notes, Series A due July 15, 2012 that are not registered under the Securities Act of 1933 for our new 6.25% Senior Notes, Series B due July 15, 2012 that are registered under the Securities Act of 1933 in the Exchange Offer. Material terms of the Exchange Offer are: - - EXPIRATION. The Exchange Offer will expire at 5:00 p.m., New York City time, on November 6, 2002, unless we extend it. - - EXCHANGE. We will exchange all outstanding Original Senior Notes that are validly tendered and not validly withdrawn before the Exchange Offer expires. - - TERMS OF THE NOTES. The terms of the Exchange Senior Notes are substantially identical to the Original Senior Notes, except that the Exchange Senior Notes are registered under the Securities Act of 1933. Certain transfer restrictions and registration rights relating to the Original Senior Notes do not apply to the Exchange Senior Notes. - - REPRESENTATION OF HOLDERS. You will be required to make various representations including that (1) any Exchange Senior Notes received by you will be acquired in the ordinary course of business, (2) you are not participating in the distribution of the Exchange Senior Notes, (3) you are not an affiliate of Southern Power Company and (4) you are not a broker-dealer, and if you are a broker-dealer, that you will receive the Exchange Senior Notes for your own account, you will deliver a prospectus on resale of your Exchange Senior Notes and that you acquired your Original Senior Notes as a result of market making activities or other trading activities. - - WITHDRAWAL RIGHTS. You may withdraw tenders of Original Senior Notes at any time before the Exchange Offer expires. - - CONDITIONS. The Exchange Offer is subject to customary conditions, including the condition that the Exchange Offer not violate applicable law or any applicable interpretation of the staff of the Securities and Exchange Commission. - - TAX CONSEQUENCES. We believe that the Exchange Offer will not be a taxable event for U.S. federal income tax purposes, but you should see "Material U.S. Federal Income Tax Considerations" on page 74 for more information. - - USE OF PROCEEDS. We will not receive any proceeds from the Exchange Offer. - - TRADING. There is no existing market for the Exchange Senior Notes and we will not apply to list them on any securities exchange. SEE "RISK FACTORS" BEGINNING ON PAGE 11 FOR A DISCUSSION OF CERTAIN RISKS THAT YOU SHOULD CONSIDER IF YOU TENDER YOUR ORIGINAL SENIOR NOTES IN CONNECTION WITH THIS EXCHANGE OFFER. These securities have not been approved or disapproved by the Securities and Exchange Commission or any state securities commission nor has the Securities and Exchange Commission or any state securities commission passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense. The date of this prospectus is October 1, 2002 You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with different information. This prospectus is an offer only of the Exchange Senior Notes to be issued in exchange for the Original Senior Notes but only under circumstances and in jurisdictions where it is lawful to do so. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this prospectus. Each broker-dealer that receives Exchange Senior Notes for its own account pursuant to the Exchange Offer must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Senior Notes. The Letter of Transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act of 1933, as amended (the "Securities Act"). This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Senior Notes received in exchange for Original Senior Notes where the Original Senior Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, during the 270-day period following the consummation of the Exchange Offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See "PLAN OF DISTRIBUTION." Whenever we refer to the outstanding 6.25% Senior Notes, Series A due July 15, 2012 issued in a private offering on June 18, 2002, we will refer to them collectively as the "Original Senior Notes" and each individually as an "Original Senior Note." Whenever we refer to the 6.25% Senior Notes, Series B due July 15, 2012 registered under the Securities Act and issued in exchange for the Original Senior Notes, we will refer to them collectively as the "Exchange Senior Notes" and each individually as an "Exchange Senior Note." The Original Senior Notes and the Exchange Senior Notes are collectively referred to as the "Notes." i TABLE OF CONTENTS
PAGE ---- Where to Find More Information.............................. ii Forward-Looking Statements.................................. iii Summary..................................................... 1 Risk Factors................................................ 11 Use of Proceeds............................................. 18 Capitalization.............................................. 18 Selected Historical Financial Data.......................... 19 Pro Forma Financial Data.................................... 20 Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 21 Our Business................................................ 32 Our Management.............................................. 49 Executive Compensation...................................... 50 Stock Ownership Table....................................... 54 The Operating Companies..................................... 54 Certain Relationships and Related Transactions.............. 56 The Exchange Offer.......................................... 58 Description of The Exchange Senior Notes and The Indenture................................................. 67 Material U.S. Federal Income Tax Considerations............. 78 Ratings..................................................... 79 Plan of Distribution........................................ 79 Experts..................................................... 79 Independent Engineer........................................ 80 Independent Market Expert................................... 80 Legal Matters............................................... 80 Index to Financial Statements............................... F-1 Annex A -- Independent Engineer's Report.................... A-1 Annex B -- Independent Market Expert's Report............... B-1
------------------------------------------------------ WHERE TO FIND MORE INFORMATION In connection with the Exchange Offer, we have filed with the Securities and Exchange Commission ("SEC") a Registration Statement on Form S-4 under the Securities Act, to register the Exchange Senior Notes offered hereby in exchange for the Original Senior Notes. As permitted by SEC rules, this prospectus omits information included in the Registration Statement. For a more complete understanding of this Exchange Offer, you should refer to the Registration Statement, including its exhibits. ii WE ARE NOT CURRENTLY SUBJECT TO THE INFORMATIONAL REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED (THE "EXCHANGE ACT"). UPON THE EFFECTIVENESS OF THE REGISTRATION STATEMENT WE WILL BECOME SUBJECT TO THOSE PERIODIC REPORTING REQUIREMENTS. OUR PARENT COMPANY, THE SOUTHERN COMPANY ("SOUTHERN"), IS SUBJECT TO THE INFORMATIONAL REQUIREMENTS OF THE EXCHANGE ACT AND, IN ACCORDANCE WITH THAT ACT, FILES REPORTS, PROXY STATEMENTS AND OTHER INFORMATION WITH THE SEC. THE PUBLIC MAY READ AND COPY THESE REPORTS OR OTHER INFORMATION THAT IS FILED WITH THE SEC AT THE SEC'S PUBLIC REFERENCE ROOM, ROOM 1024 AT JUDICIARY PLAZA, 450 FIFTH STREET, N.W., WASHINGTON, D.C. 20549, OR AT THE SEC'S REGIONAL OFFICES LOCATED AT 233 BROADWAY, NEW YORK, NEW YORK 10279, AND SUITE 1400, 500 WEST MADISON STREET, CHICAGO, ILLINOIS 60661. THE PUBLIC MAY OBTAIN INFORMATION ON THE OPERATION OF THE PUBLIC REFERENCE ROOM BY CALLING THE SEC AT 1-800-SEC-0330. THESE DOCUMENTS ARE ALSO AVAILABLE TO THE PUBLIC FROM COMMERCIAL DOCUMENT RETRIEVAL SERVICES AND AT THE WEB SITE MAINTAINED BY THE SEC AT HTTP://WWW.SEC.GOV. YOU MAY ALSO OBTAIN A COPY OF THE REGISTRATION STATEMENT AT NO COST BY WRITING US AT THE FOLLOWING ADDRESS: SOUTHERN POWER COMPANY ATTN: CHIEF FINANCIAL OFFICER 270 PEACHTREE STREET, N.W. ATLANTA, GEORGIA 30303 To obtain timely delivery, you must request this information no later than five business days before you must make your investment decision, or no later than October 30, 2002, which is five business days before the expiration of the Exchange Offer. FORWARD-LOOKING STATEMENTS This prospectus includes forward-looking statements. All statements, other than statements of historical facts, included in this prospectus that address activities, events or developments that we expect or anticipate will or may occur in the future, including such matters as projections, future capital expenditures, business strategy, competitive strengths, goals, development or operation of generation assets, market and industry developments and the growth of our businesses and operations, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "projects," "potential," or "contemplate" or the negative of these terms or other comparable terminology. These statements are based on assumptions and analyses made in light of experience and other historical trends, current conditions and expected future developments, as well as various factors we believe are appropriate under the circumstances. However, actual results and developments may differ materially from our expectations and predictions due to a number of risks and uncertainties, many of which are beyond our control. These risks and uncertainties include: - significant considerations and risks discussed in this prospectus; - political, legal, regulatory and economic conditions and developments in the United States; - the effect of and changes in economic conditions in the areas in which we operate; - fluctuations in demand for energy, capacity and ancillary services in the markets in which we operate; - the effect, extent and timing of the entry of additional competition in the markets in which our company operates; - acquisition and development opportunities (or lack thereof) that may be presented to and pursued by us; - impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and also changes in environmental and other laws and regulations to which our company is subject, as well as changes in application of existing laws and regulations; iii - environmental constraints on construction and operations; - rapidly changing markets for energy products; - financial market conditions and the results of financing efforts; - the direct or indirect impact on our company's business resulting from the terrorist incidents on September 11, 2001, or any similar incidents or responses to such incidents; - weather and other natural phenomena; or - current and future litigation. Consequently, all of the forward-looking statements made in this prospectus are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by us or the projections will be realized or, even if realized, will have the expected consequences to or effects on us or our business, financial condition or results of operations. You should not place undue reliance on these forward-looking statements in making your investment decision. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to these forward-looking statements to reflect events or circumstances that occur or arise or are anticipated to occur or arise after the date hereof. In making a decision regarding the tender of your Original Senior Notes in connection with this Exchange Offer, we are not making, and you should not infer, any representation about the likely existence of any particular future set of facts or circumstances. iv SUMMARY The following summary contains basic information about Southern Power Company and the Exchange Offer. It may not contain all of the information that may be important to you in making a decision to tender your Original Senior Notes in connection with the Exchange Offer. You should read the entire prospectus, and the documents to which we refer, before making an investment decision. Unless the context otherwise indicates, all references to the "Company," "Southern Power," "we," "us" or "our" in this prospectus refer to Southern Power Company. SOUTHERN POWER COMPANY We are a wholly owned subsidiary of The Southern Company ("Southern"). Our principal executive offices are located at 270 Peachtree Street, N.W., Atlanta, Georgia 30303, and the telephone number is (404) 506-5000. We were formed to own, construct and acquire Southern's new competitive contract-based wholesale generation assets. Consequently, our business activities should not be subject to traditional state regulation, but are subject to regulation by the Federal Energy Regulatory Commission (the "FERC"). We will be the primary vehicle to develop Southern's position in the energy markets in the Southeastern United States. It is contemplated that substantially all of our generating capacity will be committed under long-term, fixed-price power purchase agreements ("PPAs"), primarily with our affiliates. We are an electric utility company as defined under the Public Utility Holding Company Act of 1935, as amended (the "Holding Company Act"). We are subject to regulation under the Holding Company Act because we are a wholly owned subsidiary of Southern, a registered public utility holding company under the Holding Company Act. The following is a chart of Southern's electric operating companies, its service company and us: (SOUTHERN CO. FLOW CHART) As a separate subsidiary in the Southern system, we provide the means by which Southern can own, construct and acquire new generation assets outside of the traditional rate-based state regulated generation structure. Substantially all of our operating or under construction generating facilities were acquired from affiliates within the Southern system. We intend to own and finance all of the new competitive contract-based wholesale generation assets to be built in the Southern system. Southern believes that this structure is most effective for pursuing generation opportunities in the competitive wholesale markets. This structure ensures a consistent approach to developing new wholesale generation and improves efficiency. We intend to own, construct and acquire generating facilities in the "Super Southeast" region (as described below) of the United States and to sell the output of our generating facilities under long-term, fixed-price capacity contracts to wholesale customers in this region. The Super Southeast includes the states in Southern's traditional service territory -- Alabama, Florida, Georgia and Mississippi. Our customers in these states are expected to be predominantly Southern's operating utilities, namely Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company and Savannah Electric and Power Company (collectively, the "Operating Companies"), but will include unaffiliated third parties as well. The Super Southeast also consists of the surrounding states of Kentucky, Louisiana, North 1 Carolina, South Carolina, Tennessee, and Virginia. Although we will focus on the Super Southeast, we may also acquire or construct generating facilities outside of the Super Southeast or sell the output of our generating facilities to customers outside of the Super Southeast. As of June 30, 2002, we had 4,777 megawatts ("MW") of generating capacity in commercial operation or under construction. By the end of 2005, we expect to have approximately 6,600 MW of generating capacity in commercial operation. Currently, substantially all of our existing, under construction and planned generating capacity is committed under long-term PPAs, mostly with the Operating Companies, but also with municipalities and certain unaffiliated third parties (collectively, the "PPA Counterparties"). All of the PPA Counterparties are strong entities from either a credit or financial security perspective. Along with the Operating Companies, we are a member of and share in the benefits and obligations of the Southern system power pool (the "Southern Pool"). As a member of the Southern Pool, our generating facilities located within Southern's service territory will be economically dispatched with the generating facilities of the Operating Companies to serve the members' aggregate load requirements. A member of the Southern Pool has the first call on its own generating resources, but if lower cost generation resources are available on the Southern system, a Southern Pool member has the right to purchase that lower variable cost energy to satisfy its obligations. As a member of the Southern Pool, we will also benefit from economies of scale, share geographic load diversity and maintain lower reserve levels than would be required on a stand- alone basis. The Southern Pool includes approximately 37,000 MW of generating capacity. For each of our generating facilities located in the service territory of an Operating Company, there will be an interconnection agreement to govern the interconnected operations of that facility with the transmission facilities of the appropriate Operating Company. Each Operating Company is interconnected to the transmission facilities of the other Operating Companies by means of high-voltage lines. Additionally, the Operating Companies have long-standing contracts with the principal neighboring utility systems relating to capacity exchanges, capacity purchases and sales, transfers of economy energy and other similar transactions. For the most part, such interchange transactions are now conducted under market-based tariff arrangements. We expect that each generating facility located outside of the Operating Companies' service territory will have an interconnection agreement with the applicable transmission provider. In order to optimize efficiencies, we will utilize employees currently in the Southern system for our day-to-day operations at our generation facilities. For each of our generating facilities in an Operating Company's service territory, we intend for such Operating Company to provide operation and maintenance services at cost (in accordance with the Holding Company Act). There are or will be operation and maintenance contracts between us and the appropriate Operating Company for the facilities located in such Operating Company's service territory. Because Stanton A is located outside of the Operating Companies' service territory, Southern Company Services, Inc. ("SCS"), a subsidiary of Southern, will be responsible for the operation and maintenance of Stanton A. Additionally, under the terms of a services agreement, SCS will perform overall project management of the construction process of our generating facilities. 2 BUSINESS STRATEGY Our strategy is to develop, construct and acquire additional generating facilities to compete for and serve the demand in the Super Southeast market. To implement this strategy, we plan to: - Derive at least 80% of operating cash flow under long-term, fixed-price PPAs. - Utilize the expertise of Southern affiliates in planning, designing, constructing, marketing, operating and maintaining generating facilities. - Mitigate market price, fuel supply, fuel transportation and electric transmission risk. - Focus on the Super Southeast for additional generation and wholesale marketing opportunities. - Expand our asset base to at least 6,600 MW in commercial operation by year-end 2005, with potential for further capacity additions thereafter. For a more detailed explanation of our business strategy, see "OUR BUSINESS -- Business Strategy." COMPETITIVE STRENGTHS We believe that we are well positioned to implement our business strategy because of the following competitive strengths: - Stable revenues under long-term, fixed-price PPAs. - Mitigation of market price, fuel supply, fuel transportation and electric transmission risk. - Relationship with Southern. - Efficiencies relating to new generating facilities. - Stable regulatory environment. - Absence of electric restructuring legislation in Southern's service territory. - Stable regional demand. For a more detailed explanation of our competitive strengths, see "OUR BUSINESS -- Competitive Strengths." 3 SUMMARY FINANCIAL INFORMATION Southern Power commenced operations effective January 8, 2001. The following table sets forth our summary historical financial information as of December 31, 2001 and for the period from January 8, 2001 through December 31, 2001 and our summary historical financial information as of June 30, 2002 and for the six months ended June 30, 2002. This summary financial information has been derived from financial statements prepared by us and included elsewhere in this prospectus. You should read the information set forth below in conjunction with "SELECTED HISTORICAL FINANCIAL DATA" and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" and our consolidated and condensed consolidated financial statements and the accompanying notes appearing elsewhere in this prospectus. As more fully described under "PRO FORMA FINANCIAL DATA", the summary unaudited pro forma information for the period from inception (January 8, 2001) to December 31, 2001 reflects the acquisition of Plant Dahlberg as if it occurred on January 8, 2001.
PRO FORMA (UNAUDITED) PERIOD FROM FOR THE PERIOD SIX MONTHS INCEPTION FROM INCEPTION ENDED (JANUARY 8, 2001) TO (JANUARY 8, 2001) TO JUNE 30, 2002 DECEMBER 31, 2001 DECEMBER 31, 2001 -------------- -------------------- -------------------- ($ IN THOUSANDS) INCOME STATEMENT DATA Operating Revenues................................ $77,076 $29,301 $70,454 Operating Expenses................................ 52,942 18,814 40,034 ------- ------- ------- Operating Income.................................. 24,134 10,487 30,420 Other Income...................................... (1,220) 658 658 ------- ------- ------- Earnings Before Interest and Income Taxes......... 22,914 11,145 31,078 Total Interest Expense, net....................... 1,195 427 4,331 Income Taxes...................................... 8,406 2,511 8,923 ------- ------- ------- Net Income........................................ $13,313 $ 8,207 $17,824 ======= ======= ======= OTHER FINANCIAL DATA Ratio of Earnings to Fixed Charges (1)............ 1.58x 3.36x
(UNAUDITED) AS OF AS OF JUNE 30, 2002 DECEMBER 31, 2001 -------------- ----------------- ($ IN THOUSANDS) BALANCE SHEET DATA Total Current Assets........................................ $ 60,581 $ 27,639 Plant in Service, net....................................... 877,464 261,862 Construction Work in Progress............................... 729,841 500,358 Other Assets and Deferred Charges........................... 45,866 32,998 ---------- -------- Total Assets................................................ $1,713,752 $822,857 ========== ======== Current Liabilities, excluding Subordinated Note Payable to Parent.................................................... $ 41,785 $ 31,693 Deferred Credits and Other Liabilities...................... 45,300 30,016 Long-Term Debt.............................................. 732,401 293,205 Subordinated Note Payable to Parent......................... 186,342 950 Common Stockholder's Equity................................. 707,924 466,993 ---------- -------- Total Liabilities and Stockholder's Equity.................. $1,713,752 $822,857 ========== ========
- --------------- (1) Ratio of earnings to fixed charges represents, on a pre-tax basis, the number of times earnings cover fixed charges. Earnings consist of net income plus interest expense and income taxes. Fixed charges consist of interest expense plus capitalized interest. 4 INDEPENDENT CONSULTANTS' REPORTS R. W. Beck ("Beck" or the "Independent Engineer") has prepared the Independent Engineer's Report (the "Independent Engineer's Report"), included as Annex A to this prospectus. Beck is an international engineering and consulting firm with substantial experience in the electric power industry. The Independent Engineer's Report includes a technical review of our generation facilities and projections of our financial performance through 2022. You should read the entire Independent Engineer's Report. We advise you that the Independent Engineer's Report is dated June 13, 2002, and information contained in that report may only be accurate as of that date. We have not requested, nor do we intend to request, that Beck update the information in the Independent Engineer's Report. PA Consulting Services, Inc. ("PA Consulting" or the "Independent Market Expert") has prepared the Independent Market Expert's Report (the "Independent Market Expert's Report"), included as Annex B to this prospectus. The Independent Market Expert's Report includes an analysis of the principal market regions in which we operate and price forecasts for our energy and capacity. You should read the entire Independent Market Expert's Report. We advise you that the Independent Market Expert's Report is dated June 5, 2002, and information contained in that report may only be accurate as of that date. We have not requested, nor do we intend to request, that PA Consulting update the information in its report. SUMMARY PROJECTED FINANCIAL INFORMATION We do not as a matter of course make public projections as to future sales, earnings or other results. However, the Independent Engineer, at our request, has prepared the Independent Engineer's Report from which the financial information set forth below has been derived. The projected financial information was not prepared with a view toward public disclosure or with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of our management's knowledge and belief, the expected course of action and the expected future financial performance of our company. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and you are cautioned not to place undue reliance on the projected financial information. Neither our independent auditors, nor any other independent accountants, have compiled, examined, or performed any procedures with respect to the projected financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the projected financial information. The projections presented below are subject to the qualifications, limitations and exclusions set forth in the Independent Engineer's Report. Franklin 3, McIntosh 10 and McIntosh 11 are currently in advanced stages of development and have not been incorporated into these projections. See "OUR BUSINESS -- Our Planned Electric Generating Facilities." The following information reflects the base case assumptions set forth in the Independent Engineer's Report.
YEAR ENDING DECEMBER 31, ----------------------------------------------------------------------- 2002 (1) 2003 2004 2005 2006 2012 2017 2022 -------- ------ ------ ------ ------ ------ ------ ------ ($ IN MILLIONS) SELECTED PROJECTED FINANCIAL DATA Total Revenues..................... $144.9 $319.5 $406.6 $394.2 $407.4 $836.0 $847.0 $953.1 Fuel Expenses.................... $ 7.7 $ 40.3 $ 19.6 $ 0.0 $ 1.7 $344.1 $355.0 $409.2 Non-Fuel Expenses................ $ 31.3 $ 60.8 $ 88.2 $101.6 $114.5 $118.9 $113.2 $116.9 Total Expenses..................... $ 39.0 $101.1 $107.8 $101.6 $116.2 $463.0 $468.2 $526.1 Cash Flow Available for Debt Service (CFADS).................. $105.9 $218.4 $298.8 $292.6 $291.1 $373.0 $378.7 $427.0 CFADS Interest Coverage Ratio...... 5.05x 3.30x 3.40x 3.33x 3.31x 4.24x 4.31x 4.86x 2002-2012 Average.................. 3.61x 2002-2022 Average.................. 4.05x
YEAR ENDING DECEMBER 31, ---------------------------------------- AVERAGE AVERAGE 2002 (1) 2003 2004 2005 2006 2002-2006 2002-2012 -------- ----- ----- ----- ----- --------- --------- Percent of Cash Flow under Contract........... 96.8 96.8 99.6 97.7 97.3 97.7 80.6(2)
- --------------- (1) For purposes of the above data, the year 2002 commenced in June 2002 and accordingly only includes seven months. (2) The 80.6% assumes no renewals or extensions of the existing PPAs. We plan to renew the existing PPAs or enter into new PPAs when the existing PPAs expire. 5 SUMMARY OF THE EXCHANGE OFFER THE EXCHANGE OFFER............ We are offering to exchange up to $575,000,000 aggregate principal amount of our 6.25% Senior Notes, Series B due July 15, 2012, or Exchange Senior Notes, which have been registered under the Securities Act, for a like amount of our outstanding 6.25% Senior Notes, Series A due July 15, 2012, or Original Senior Notes, which we issued on June 18, 2002 in a private offering. To exchange your Original Senior Notes, you must properly tender them by following the procedures described under the heading "THE EXCHANGE OFFER" and we must accept them. EXPIRATION DATE............... The Exchange Offer expires at 5:00 p.m., New York City time, on November 6, 2002, unless we extend it. WITHDRAWAL RIGHTS............. You may withdraw the tender of your Original Senior Notes at any time before 5:00 p.m., New York City time, on the Expiration Date. If we decide for any reason not to accept any Original Senior Notes for exchange, we will return your Original Senior Notes without expense to you promptly after the expiration or termination of the Exchange Offer. CONDITIONS TO THE EXCHANGE OFFER......................... The Exchange Offer is subject to customary conditions, some of which we may waive. We reserve the right to terminate and amend the Exchange Offer at any time if any such condition occurs before the Expiration Date. INTEREST PAYMENTS............. Interest on the Exchange Senior Notes will accrue from the last interest payment date on which interest was paid on the Original Senior Notes surrendered for exchange. If no interest has been paid on the Original Senior Notes at the time of issuance of the Exchange Senior Notes, interest on the Exchange Senior Notes will accrue from June 18, 2002, the date of original issuance of the Original Senior Notes. PROCEDURES FOR TENDERING ORIGINAL SENIOR NOTES......... If you are a holder of Original Senior Notes who wishes to accept the Exchange Offer for Exchange Senior Notes: - you must complete, sign and date the accompanying Letter of Transmittal, or a facsimile thereof and mail or otherwise deliver it, together with your Original Senior Notes, to the Exchange Agent at the address set forth under "THE EXCHANGE OFFER -- Exchange Agent;" or - arrange for The Depository Trust Company, or DTC, to transmit certain required information to the Exchange Agent in connection with a book-entry transfer. Do not send Letters of Transmittal and certificates representing Original Senior Notes to us. By tendering your Original Senior Notes in this manner, you will be representing, among other things, that: - the Exchange Senior Notes you acquire pursuant to the Exchange Offer are being acquired in the ordinary course of your business; 6 - you are not participating, do not intend to participate, and have no arrangement or understanding with any person to participate, in the distribution of the Exchange Senior Notes issued to you in the Exchange Offer; - you are not an "affiliate" of our company, or if you are an affiliate, you will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable; and - you are not a broker-dealer; and if you are a broker-dealer, that you will receive the Exchange Senior Notes for your own account, you will deliver a prospectus on resale of your Exchange Senior Notes and that you acquired your Original Senior Notes as a result of market making activities or other trading activities. SPECIAL PROCEDURES FOR BENEFICIAL OWNERS............. If you are a beneficial owner whose Original Senior Notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and wish to tender your Original Senior Notes in the Exchange Offer, please contact the registered owner as soon as possible and instruct it to tender on your behalf. If you wish to tender on your own behalf, you must, prior to completing and executing the Letter of Transmittal and delivering your Original Senior Notes, either arrange to have your Original Senior Notes registered in your name or obtain a properly completed bond power from the registered owner. The transfer of registered ownership may take considerable time. GUARANTEED DELIVERY PROCEDURES.................... If you wish to tender your Original Senior Notes and time will not permit your required documents to reach the Exchange Agent by the Expiration Date, or the procedure for book-entry transfer cannot be completed on time, you may tender your Original Senior Notes according to the guaranteed delivery procedures set forth in "THE EXCHANGE OFFER -- Procedures for Tendering." APPRAISAL OR DISSENTERS' RIGHTS........................ Owners of Original Senior Notes do not have any appraisal or dissenters' rights in the Exchange Offer. CONSEQUENCES OF NOT EXCHANGING ORIGINAL SENIOR NOTES......... If you do not tender your Original Senior Notes or we reject your tender, you will not be entitled to any further registration rights or exchange rights, except under limited circumstances, and your Original Senior Notes will continue to be subject to restrictions on transfer. Therefore, if you do not exchange your Original Senior Notes, you will not be able to reoffer, resell or otherwise dispose of your Original Senior Notes unless (i) you comply with the registration and prospectus delivery requirements of the Securities Act, or (ii) you qualify for an exemption from those Securities Act requirements. Such conditions may adversely affect the market price of your Original Senior Notes. However, your Original Senior Notes will remain outstanding and entitled to the benefits of the indenture governing the Exchange Senior Notes. 7 RESALES....................... We believe that you can offer for resale, resell or otherwise transfer the Exchange Senior Notes without complying with further registration and prospectus delivery requirements of the Securities Act if you make the representations described above under "Procedures for Tendering Original Senior Notes." We base our belief on interpretations by the SEC staff in no-action letters issued to other issuers in Exchange Offers like ours. We cannot guarantee that the SEC would make a similar decision about our Exchange Offer. If our belief is wrong, you could incur liabilities under the Securities Act. We will not protect you against any loss incurred as a result of this liability under the Securities Act. If you are unable to make any of such representations and you transfer any Exchange Senior Notes without delivering a proper prospectus or without qualifying for a registration exemption, you may incur liability under the Securities Act and applicable state securities laws. We will not assume or indemnify you against such liability. FEDERAL TAX CONSEQUENCES...... Your exchange of Original Senior Notes for Exchange Senior Notes pursuant to the Exchange Offer generally will not result in any gain or loss to you for United States federal income tax purposes. For more information, see "MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS." USE OF PROCEEDS............... We will receive no proceeds from the Exchange Offer. We will pay all of our expenses related to the Exchange Offer. EXCHANGE AGENT................ The Bank of New York has been appointed as Exchange Agent of the Exchange Offer. Questions and requests for assistance, requests for additional copies of this prospectus or of the Letter of Transmittal and requests for Notices of Guaranteed Delivery should be directed to the Exchange Agent addressed as follows: By hand delivery, registered or certified mail or overnight delivery: The Bank of New York Corporate Trust Operations Reorganization Unit 101 Barclay Street - 7E New York, New York 10286 Attn: Ms. Carolle Montreuil By facsimile: (212) 298-1915 For information or confirmation by telephone: (212) 815-5920 8 SUMMARY OF TERMS OF THE EXCHANGE SENIOR NOTES The Exchange Offer relates to the exchange of up to $575,000,000 aggregate principal amount of the Original Senior Notes for an equal aggregate principal amount of Exchange Senior Notes. The form and terms of the Exchange Senior Notes will be the same as the form and terms of the Original Senior Notes, except that the Exchange Senior Notes will be registered under the Securities Act and, therefore, the registration rights and the transfer restrictions applicable to the Original Senior Notes are not applicable to the Exchange Senior Notes. The Exchange Senior Notes will evidence the same debt as the Original Senior Notes. The Exchange Senior Notes and the Original Senior Notes will be governed by the same indenture. See "DESCRIPTION OF THE EXCHANGE SENIOR NOTES AND INDENTURE" for a more complete description of the Exchange Senior Notes. ISSUER........................ Southern Power Company EXCHANGE SENIOR NOTES......... We will offer $575,000,000 aggregate principal amount of 6.25% Senior Notes, Series B due July 15, 2012. INTEREST...................... Interest will accrue on the Exchange Senior Notes from the date of delivery at a rate of 6.25% per year and will be payable semiannually in arrears on January 15 and July 15 of each year, commencing January 15, 2003. FINAL MATURITY................ July 15, 2012 RANKING....................... The Exchange Senior Notes will be senior unsecured obligations and will rank equally in right of payment with all of our other present and future senior unsecured debt. The Exchange Senior Notes will rank senior in right of payment to all of our present and future subordinated debt. RATINGS....................... The Exchange Senior Notes have been rated "Baa1" by Moody's Investors Service, Inc. ("Moody's"), "BBB+" by Standard and Poor's Ratings Services ("S&P") and BBB+ by Fitch Ratings ("Fitch"). See "RATINGS." OPTIONAL REDEMPTION........... We may redeem the Exchange Senior Notes, in whole or in part, at any time at a redemption price equal to 100% of the principal amount of the Exchange Senior Notes to be redeemed plus accrued interest, if any, plus a make-whole premium, calculated using a discount rate equal to the interest rate on comparable U.S. treasury securities plus 25 basis points. FORM AND DENOMINATION......... The Exchange Senior Notes will be issued in book entry form through the facilities of DTC without coupons in denominations of $1,000 and integral multiples thereof and represented by a Global Note. Beneficial interests in the Global Note will be shown on, and transfers thereof will be effected only through, the book-entry records maintained by DTC and its direct and indirect participants. CERTAIN COVENANTS............. The Indenture limits: - our ability to consolidate or merge or sell all or substantially all of our assets - the ability of our company and our subsidiaries to sell assets - the ability of our company and our subsidiaries to create certain liens - the ability of certain of our subsidiaries to issue indebtedness 9 In addition, in order to be permitted to declare and pay dividends or make payments on our subordinated loans from our affiliates, we are required either to (i) maintain long-term, fixed-price capacity power purchase agreements which generate at least 80% of our operating cash flow, or (ii) maintain a recourse indebtedness to total capitalization ratio of 60% or less. These limitations are subject to a number of important qualifications and exceptions. See "DESCRIPTION OF THE EXCHANGE SENIOR NOTES AND THE INDENTURE -- Certain Covenants." RISK FACTORS.................. An investment in the Exchange Senior Notes involves certain risks, including the competitive markets in which we operate, the future operating costs and performance of our electric generating facilities and our need to comply with present and future environmental laws and regulations. You should carefully consider each of the factors described in the section titled "RISK FACTORS" before participating in the Exchange Offer. TRUSTEE....................... The Bank of New York GOVERNING LAW................. The Exchange Senior Notes and the Indenture are governed by the laws of the State of New York. 10 RISK FACTORS Your investment in the Exchange Senior Notes involves risks. In deciding whether to participate in the Exchange Offer, you should carefully consider the following risk factors in addition to the other information contained in this prospectus. Each of the following factors could have a material adverse effect on our business and could result in a loss or a decrease in the value of your investment. RISKS RELATING TO THE EXCHANGE OFFER YOU ARE RESPONSIBLE FOR COMPLIANCE WITH THE EXCHANGE OFFER PROCEDURES. YOU WILL NOT RECEIVE NOTICE FROM THE EXCHANGE AGENT OR US OF DEFECTS OR IRREGULARITIES IN YOUR TENDER OF YOUR ORIGINAL SENIOR NOTES. Issuance of the Exchange Senior Notes in exchange for your Original Senior Notes pursuant to this Exchange Offer will be made only after a timely receipt by the Exchange Agent of your Original Senior Notes, a properly completed and signed Letter of Transmittal and all other required documents. Therefore, if you desire to tender your Original Senior Notes in exchange for Exchange Senior Notes you should allow sufficient time to ensure timely delivery. Neither we nor the Exchange Agent is under any duty to give notification of defects or irregularities in the tender of your Original Senior Notes for exchange. Original Senior Notes that are not tendered or are tendered but not accepted for exchange will, following the completion of this Exchange Offer, continue to be subject to the existing restrictions on transfer of the Original Senior Notes, and upon completion of this Exchange Offer, our obligation to register your Original Senior Notes will terminate. RISKS RELATING TO OUR BUSINESS OUR FINANCIAL PERFORMANCE DEPENDS ON THE OPERATION OF OUR ELECTRIC GENERATING FACILITIES. Operating electric generating facilities involves many risks, including: - operator error and breakdown or failure of equipment or processes; - operating limitations that may be imposed by environmental or other regulatory requirements; - labor disputes; - fuel supply interruptions; and - catastrophic events such as fires, earthquakes, explosions, floods or other similar occurrences. A decrease or elimination of revenues generated by our facilities or an increase in the costs of operating our facilities could decrease or eliminate funds available to us to make payments on the Exchange Senior Notes or other obligations. OUR ACTUAL FUTURE PERFORMANCE MAY NOT MEET PROJECTIONS. The projections contained in the Independent Engineer's Report prepared by Beck attempt to present our future operating performance. Beck has reviewed the performance and the technical operating parameters of our generating facilities (except for Franklin 3, McIntosh 10 and McIntosh 11 which generating facilities are not included in the projected financial information) and our operating and maintenance budgets and has made forecasts based on a review of certain technical, environmental, economic and licensing aspects. The projections are based on certain assumptions and forecasts of our generation capacity, generation revenues, the market prices for energy, capacity and ancillary services and the costs associated with our operations. The assumptions made about future market prices for energy and capacity are based on a market analysis prepared by PA Consulting. The Independent Market Expert's Report contains qualifications about the information in the report prepared by PA Consulting and the circumstances under which PA Consulting performed its analysis. These assumptions and the other assumptions upon which the projections are based 11 are inherently subject to significant uncertainties. No inference should be made about the likely existence of any particular future set of facts or circumstances. Potential investors should carefully review the Independent Engineer's Report and the Independent Market Expert's Report, as well as the qualifications in those reports. The projections are not necessarily indicative of our future performance or the performance of any individual generation facility. We do not intend to provide investors with any revised projections or analysis of the differences between the projections and actual operating results. OUR REVENUES DEPEND ON SALES UNDER POWER PURCHASE AGREEMENTS. We have agreed to sell a substantial amount of our capacity to the PPA Counterparties under PPAs having initial terms of five to 25 years. Our revenues are dependent on the continued performance by the PPA Counterparties of their obligations under the PPAs. Even though we have a rigorous credit evaluation, the failure of one of the PPA Counterparties to perform its obligations could have a material adverse effect on our results of operations or financial condition. Although our credit evaluations take into account the possibility of default by a PPA Counterparty, our actual exposure to a default by a PPA Counterparty may be greater than our credit evaluation predicts. Further, while the PPAs are currently a substantial portion of our business, we cannot predict whether they will be renewed at the end of their respective terms or on what terms any renewals may be made. If a PPA is not renewed, we cannot predict whether it will be replaced. OUR GENERATING FACILITIES WILL REQUIRE ONGOING CAPITAL EXPENDITURES. As our generating facilities come into commercial operation, we will require ongoing capital expenditures to maintain reliable levels of operation. Furthermore, we intend to develop and construct additional generating facilities in the future. To do so, we will need to make substantial expenditures to construct and maintain the performance of these generating facilities. We intend to finance these costs from equity contributions and subordinated loans from Southern, borrowings under our credit facility (which expires in November 2004) and other funding sources, including internally generated cash flow from operations and the proceeds from potential issuances of additional debt. We cannot assure you that we will be successful in obtaining the funds to provide for the ongoing maintenance or future construction of our generating facilities. OUR REVENUES AND RESULTS OF OPERATIONS WILL DEPEND IN PART ON MARKET AND OTHER FORCES BEYOND OUR CONTROL. We are currently subject to fuel supply and market risk for the portion of our capacity that is not committed under PPAs. Furthermore, the PPAs are for limited terms and if we cannot renew the PPAs or replace them with new PPAs, we could have a substantial portion of our business that is subject to risks relating to fuel supply, fuel transportation, electric transmission and market price in the future. To the extent that our capacity is not committed under PPAs, our revenues and results of operations will depend on the prices that we can obtain for energy and capacity. Among the factors that could influence such prices (all of which factors are beyond our control to a significant degree) are: - fuel supply and price: Historically, natural gas markets have exhibited price volatility. Supply and demand imbalances can create this market volatility. In addition, transportation capacity constraints can also influence the market prices for natural gas. - competition: Market conditions can encourage new participants to enter the market and build new generation. Wholesale market energy prices are heavily dependent upon the balance of supply and demand. - pricing and market development: The regulatory and pricing structures for the Super Southeast market are continuing to develop. The exact path of this development is unknown and can influence the regional market for energy and capacity outside of bilateral contracts. 12 - transmission: Regulatory changes and the establishment of regional transmission organizations can influence the price and availability of transmission in the future. The exact course these changes will take is unknown. These regulatory changes as well as export transmission constraints could limit our ability to sell to markets adjacent to the Super Southeast. - demand: The rate of growth of electric energy usage is influenced by many factors. Some of these factors include: population changes, regional economic conditions, and the implementation of conservation programs. Generating facilities for future demand are based on estimates of these factors. - weather: Weather is a critical component to the consumption of electricity in the Super Southeast. Among other factors, variations in climate conditions can influence market conditions in the Super Southeast, fuel availability, transmission and demand for energy. All of these factors could have an adverse impact on our revenues and results of operations. UNAVAILABILITY OF POWER TRANSMISSION FACILITIES MAY IMPACT OUR ABILITY TO DELIVER OUR OUTPUT TO CUSTOMERS. We depend on transmission facilities owned and operated by others to deliver the electricity we generate and sell. If transmission is interrupted, or if transmission capacity is inadequate, our ability to sell and deliver our electric energy products may be adversely impacted. If the underlying transmission infrastructure is or becomes inadequate, our ability to generate revenues may be limited. WE ARE SUBJECT TO SUBSTANTIAL ENVIRONMENTAL REGULATION. We are subject to federal, state and local environmental requirements which, among other things, regulate air emissions, water discharges and the management of hazardous and solid waste in order to adequately protect the environment. Compliance with these legal requirements requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emissions fees and permits at all our facilities. These expenditures are significant and we expect that they will increase in the future. We will install, operate and maintain continuous emission monitoring systems as required by federal, state or local authorities, and we will require our vendors to meet specifications and offer warranties that meet or exceed regulatory requirements. We believe that we have obtained all material environmental approvals to operate our electric generating facilities or such approvals have been applied for and will be received in a timely manner. Failure to comply with such requirements could result in the complete shutdown of individual facilities not in compliance as well as the imposition of civil and criminal penalties. OUR BUSINESS MAY BE ADVERSELY AFFECTED BY REGULATORY CHANGES IN THE ELECTRIC POWER INDUSTRY. We currently have general authorization from the FERC to sell generation from our facilities to non-affiliates at market-based prices. We have to obtain specific approval from the FERC to sell power under a PPA with an affiliate. The FERC retains the authority to modify or withdraw our market-based rate authority if it determines that the markets in which we sell generation are not workably competitive, that we possess unmitigated market power or that we are not otherwise charging just and reasonable rates. In that event, we would need to obtain FERC approval of rates based on "cost of service" principles. Those rates may be lower than the market-based rates we could negotiate with purchasers. In addition, the loss of market-based rate authority would subject us to the accounting, record-keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules. The FERC has recently announced that it may revise its analysis regarding the determination of market power. Such a revision or similar developments that result in a reduction by the FERC of the rate we may receive or any unfavorable regulation of our business by state regulators could materially adversely affect our results of operations. In November 2001, the FERC expressed concern that entities that have been granted market-based rate authorization might, under certain circumstances, exercise market power or engage in anticompetitive behavior that could result in unjust and unreasonable rates. Accordingly, it has proposed to require all market-based sellers' tariffs to include the following provision: "As a condition of obtaining and retaining market-based rate authority, the seller is prohibited from engaging in anticompetitive behavior or the exercise of market power. The seller's market-based rate authority is subject to refunds or other remedies as may be appropriate 13 to address any anticompetitive behavior or exercise of market power." Industry participants have submitted comments addressing the proposed tariff provision. The FERC has not yet issued an order adopting the provision. If such a provision is added, it will subject all sellers at market-based rates, including us, to possible refund liability which could be retroactive. The FERC has implemented a new screening mechanism to assess whether a seller seeking to sell (or continuing to sell) power at market-based rates possesses generation market power in the relevant market. The FERC has recently applied that new test to Southern and its affiliates with market-based rate authorization, which includes us. As a result, FERC imposed spot market mitigation measures for purchases and sales within the Southern control area, but that requirement is currently being held in abeyance. If later imposed, those measures may adversely impact the rate we may receive from such transactions. This development, as well as any unfavorable regulation of our business by state regulators, could materially adversely affect our results of operations. On July 31, 2002, the FERC issued a notice of proposed rulemaking entitled "Remedying Undue Discrimination Through Open Access Transmission Service and Standard Electricity Market Design." The FERC has indicated that the proposal, if adopted, would (among other things): (i) require transmission assets of jurisdictional utilities to be operated by an independent entity; (ii) establish a standard market design; (iii) establish a single type of transmission service that applies to all customers; (iv) assert jurisdiction over the transmission component of bundled retail service; (v) establish a generation reserve margin; (vi) establish bid caps for day-ahead and spot energy markets; and (vii) revise the FERC policy on the pricing of transmission expansions. Comments on the proposal are due 75 days after its issuance. Any impact of this proposal on Southern Power will depend on the form in which final rules may be ultimately adopted. OUR BUSINESS IS SUBJECT TO SUBSTANTIAL ENERGY REGULATORY REQUIREMENTS. The electric power generation business is subject to substantial regulation and permitting requirements from federal, state and local authorities. We are required to comply with numerous laws and regulations and to obtain numerous governmental permits in order to construct and operate our generating facilities. Additionally, various state public service commissions ("PSCs") have broad powers of supervision and regulation over the Operating Companies and, therefore, can oversee aspects of transactions between the Operating Companies and us. Our business could be materially and adversely affected as a result of legislative or regulatory changes or judicial or administrative interpretations of existing energy regulatory laws, regulations or licenses that impose more comprehensive or stringent requirements on us. We believe that we have obtained all material energy-related approvals required as of the date hereof to operate or construct our electric generating facilities. We may be required to obtain additional regulatory approvals, including, without limitation, licenses, renewals, extensions, transfers, assignments, reissuances or similar actions. We cannot assure you that we will be able to: - obtain all required regulatory approvals that we do not yet have or that we may be required to obtain in the future, - obtain any necessary modifications to existing regulatory approvals, or - maintain all required regulatory approvals. Delay in obtaining or failure to obtain and maintain in full force and effect any such regulatory approvals, or delay or failure to satisfy any applicable regulatory requirements, could prevent operation of our electric generating facilities, or the sale of electricity from those facilities, or could result in potential civil or criminal liability or additional costs to us. We can give no assurance that regulations will not be revised or reinterpreted, that new laws and regulations will not be adopted or become applicable to us or any of our generating facilities or that future changes in laws and regulations will not have a detrimental effect on our business. 14 WE RELY UPON AFFILIATES AND THIRD PARTIES TO CONDUCT IMPORTANT PARTS OF OUR BUSINESS. All of our business is operated by affiliates with the participation of our management. In particular, SCS markets our energy and capacity, is responsible for our fuel supply, provides support services to us and will complete construction of our facilities. The Operating Companies will operate and maintain most of our generating facilities for us under long-term contracts. Additionally, unaffiliated third parties participate in the construction and maintenance of our facilities and we depend on other unaffiliated third parties for transmission of our electricity outside of the Operating Companies' service territory. We would require substantial additional resources to perform any of these important functions ourselves if that were to become necessary or desirable due to changes in law or regulation, any substandard performance by one or more of these affiliates or unaffiliated third parties, or other factors. CONFLICTS OF INTEREST MAY ARISE BETWEEN US AND OUR AFFILIATES. We rely on certain of our affiliates for important parts of our business and sales. Despite the fact that we and our affiliates are wholly owned by Southern, conflicts of interest may arise if we need to enforce the terms of agreements between us and any of our affiliates. Because of these affiliate relationships, it is possible that decisions concerning the interpretation or operation of these agreements could be made from perspectives other than the interests solely of our company or our creditors. Although it is Southern's intention that we will own and finance all of the new competitive contract-based wholesale generation assets to be built in the Southern system, it is possible that other subsidiaries of Southern could acquire or participate in the ownership of such facilities. WE ARE SUBJECT TO CONTROL BY SOUTHERN. We are a wholly owned subsidiary of Southern and, therefore, Southern ultimately controls the decision of all matters submitted for shareholder approval. In circumstances involving a conflict of interest between Southern, on the one hand, and our creditors, on the other, Southern could exercise this power in a manner that would benefit Southern to the detriment of our creditors, including the holders of the Exchange Senior Notes. WE HAVE A LIMITED OPERATING HISTORY AS A STAND-ALONE POWER GENERATOR. We have operated as a separate, stand-alone entity since January 8, 2001. We depend on Southern for some of our liquidity, capital resources and credit support needs, and on our affiliates for important parts of our business and sales. The process of constructing and integrating the generation facilities and operations acquired from the Operating Companies is still ongoing. Additionally, we may not be able to successfully integrate our acquisitions or developments with our existing business. WE ARE SUBJECT TO REGULATION BY THE SEC UNDER THE HOLDING COMPANY ACT. We are an "electric utility company" as defined in Section 2(a)(3) of the Holding Company Act. We are subject to regulation by the SEC under the Holding Company Act because we are a wholly owned subsidiary of Southern, a registered public utility holding company under the Holding Company Act. Under the Holding Company Act, we cannot issue debt or equity securities or guaranties without the SEC's approval. Under the Holding Company Act, generally, we can invest only in the traditional electric and gas utility business and related businesses. The acquisition of the voting stock of other gas or electric utilities is subject to prior SEC approval. The Holding Company Act also imposes restrictions on transactions among affiliates. The limitations imposed on us by the Holding Company Act may limit our ability to pursue acquisition or development opportunities. 15 BECAUSE POWER PLANT CONSTRUCTION IS COSTLY AND SUBJECT TO NUMEROUS RISKS, WE MAY INCUR ADDITIONAL COSTS OR DELAYS AND MAY NOT BE ABLE TO RECOVER OUR INVESTMENT. We have announced construction plans for a number of generating facilities and we intend to continue our strategy of developing and constructing other new facilities and expanding existing facilities. Our completion of these facilities without delays or cost overruns is subject to substantial risks, including: - shortages and inconsistent quality of equipment, materials and labor; - work stoppages; - permits, approvals and other regulatory matters; - adverse weather conditions; - unforeseen engineering problems; - environmental and geological conditions; - delays or increased costs to interconnect our facilities to transmission grids; - unanticipated cost increases; and - our attention to other projects. If we are unable to complete the development or construction of a facility, we may not be able to recover our investment in it. In addition, construction delays and contractor performance shortfalls can result in the loss of revenues and may, in turn, adversely affect our results of operations and financial position. Furthermore, if construction projects are not completed according to specifications, we may incur liabilities and suffer reduced plant efficiency, higher operating costs and reduced earnings. RISK ASSOCIATED WITH A CHANGING ECONOMIC ENVIRONMENT. In response to the September 11, 2001 terrorist attacks on the United States and the ongoing war against terrorism by the United States, the financial markets have been disrupted in general. Additionally, the availability and cost of capital for our business and that of our competitors has been adversely affected by the bankruptcy of Enron Corporation and events related to the California electric market crisis. These events could constrain the capital available to our industry and could adversely affect our access to funding for our operations, the demand for and pricing of our products and the financial stability of our customers and counterparties in transactions. WE MAY NOT BE ABLE TO RESPOND EFFECTIVELY TO COMPETITION OR NEW TECHNOLOGIES. We may not be able to respond in a timely or effective manner to the many changes in the electric power industry that may occur as a result of regulatory initiatives to increase competition. As a result, additional competitors in our industry may be created, and we may not be able to maintain our revenues and earnings levels or pursue our growth strategy. In addition, new technologies may be developed that impact the competitiveness of our generation facilities. To the extent that competition increases, our profit margins may be negatively affected. The introduction of new participants with better technologies in our regional market could increase competition, which could lower prices and have a material adverse effect on our results of operations or financial condition. These risks are particularly significant when the existing PPAs expire and the associated capacity must be re-marketed. 16 THERE IS NO EXISTING MARKET FOR THE EXCHANGE SENIOR NOTES, AND WE CANNOT ASSURE YOU THAT AN ACTIVE TRADING MARKET WILL DEVELOP. The Exchange Senior Notes are new securities and there is no existing market for the Exchange Senior Notes and we do not intend to apply for listing of the Exchange Senior Notes on any securities exchange. There can be no assurance as to the liquidity of any market that may develop for the Exchange Senior Notes, the ability of the holders to sell their Exchange Senior Notes or the price at which the holders will be able to sell their Exchange Senior Notes. Future trading prices of the Exchange Senior Notes will depend on many factors including, among others, prevailing interest rates, our operating results and the market for similar securities. 17 USE OF PROCEEDS We will not receive any cash proceeds from the issuance of the Exchange Senior Notes offered hereby. In consideration for issuing the Exchange Senior Notes as contemplated in this prospectus, we will receive in exchange Original Senior Notes in like principal amount, the forms and terms of which are identical, in all material respects, to the Exchange Senior Notes. The Original Senior Notes surrendered in exchange for the Exchange Senior Notes will be retired and canceled and cannot be reissued. Accordingly, the issuance of the Exchange Senior Notes will not result in any increase or decrease in our indebtedness. We received net proceeds of $570 million from the sale of the Exchange Senior Notes after deducting discounts to the initial purchasers and estimated fees and expenses. We used the net proceeds to reduce the outstanding indebtedness under our $850 million revolving credit facility, dated as of November 15, 2001, with Citibank N.A., as administrative agent, and the lenders thereto (the "Credit Facility") and to reduce our subordinated loans from Southern. CAPITALIZATION The following table sets forth our capitalization as of June 30, 2002. You should read the information set forth below in conjunction with "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" and our consolidated and condensed consolidated financial statements and the accompanying notes appearing elsewhere in this prospectus.
AS OF JUNE 30, 2002 ------------- (UNAUDITED) ------------- ($ THOUSANDS) Long-Term Debt: Obligation under Credit Facility............................ $ 158,205 Senior Notes................................................ 575,000 Unamortized Discount........................................ (804) ---------- Total Long-Term Debt.............................. 732,401 Subordinated Note Payable to Parent......................... 186,342 Common Stockholder's Equity................................. 707,924 ---------- Total Capitalization........................................ $1,626,667 ==========
18 SELECTED HISTORICAL FINANCIAL DATA Southern Power commenced operations effective January 8, 2001. The following table sets forth our selected historical financial data. The selected historical financial data for the year ended December 31, 2001 have been derived from our audited financial statements included elsewhere in this prospectus. The selected historical financial data for the six months ended June 30, 2002 have been derived from our unaudited condensed consolidated financial statements included elsewhere in this prospectus. You should read the information set forth below in conjunction with "PRO FORMA FINANCIAL DATA" and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" and our financial statements and the accompanying notes appearing elsewhere in this prospectus.
(UNAUDITED) PERIOD FROM INCEPTION SIX MONTHS ENDED (JANUARY 8, 2001) TO JUNE 30, 2002 DECEMBER 31, 2001 ------------------ --------------------- ($ IN THOUSANDS) INCOME STATEMENT DATA Operating Revenues.......................................... $77,076 $29,301 Operating Expenses.......................................... 52,942 18,814 ------- ------- Operating Income............................................ 24,134 10,487 Other Income................................................ (1,220) 658 ------- ------- Earnings Before Interest and Income Taxes................... 22,914 11,145 Total Interest Expense, net................................. 1,195 427 Income Taxes................................................ 8,406 2,511 ------- ------- Net Income.................................................. $13,313 $ 8,207 ======= ======= OTHER FINANCIAL DATA Ratio of Earnings to Fixed Charges (1)...................... 1.58x 3.36x
(UNAUDITED) AS OF AS OF JUNE 30, 2002 DECEMBER 31, 2001 -------------- ----------------- ($ IN THOUSANDS) BALANCE SHEET DATA Total Current Assets........................................ $ 60,581 $ 27,639 Plant in Service, net....................................... 877,464 261,862 Construction Work in Progress............................... 729,841 500,358 Other Assets and Deferred Charges........................... 45,866 32,998 ---------- --------- Total Assets................................................ $1,713,752 $ 822,857 ========== ========= Current Liabilities, excluding Subordinated Note Payable to Parent.................................................... $ 41,785 $ 31,693 Deferred Credits and Other Liabilities...................... 45,300 30,016 Long-Term Debt.............................................. 732,401 293,205 Subordinated Note Payable to Parent......................... 186,342 950 Common Stockholder's Equity................................. 707,924 466,993 ---------- --------- Total Liabilities and Stockholder's Equity.................. $1,713,752 $ 822,857 ========== =========
- --------------- (1) Ratio of earnings to fixed charges represents, on a pre-tax basis, the number of times earnings cover fixed charges. Earnings consist of net income plus interest expense and income taxes. Fixed charges consist of interest expense plus capitalized interest. 19 PRO FORMA FINANCIAL DATA UNAUDITED PRO FORMA STATEMENTS OF INCOME YEAR ENDED DECEMBER 31, 2001 We acquired Plant Dahlberg from Georgia Power Company, our sister company, on July 31, 2001. The acquisition was made at Georgia Power Company's carrying value, in accordance with SEC regulations under the Holding Company Act and our application on Form U-1 (Release No. 35-27322). This transaction has been reflected in our 2001 consolidated financial statements as an asset purchase (see Note 2 to the Consolidated Financial Statements herein) in accordance with the guidance contained in Emerging Issues Task Force Issue No. 98-3, "Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business." However, for purposes of Rule 11-01(d) of Regulation S-X, this transaction may be considered a business acquisition. Accordingly, the following unaudited pro forma income statement information reflects the transaction as if it occurred on January 8, 2001. No pro forma balance sheet information is required, since the transaction is fully reflected in our December 31, 2001 balance sheet. In addition, carve-out financial statements for Plant Dahlberg have been included herein. The unaudited pro forma financial data are provided for informational purposes only and are not necessarily indicative of the results of operations of the Company had the transaction assumed therein occurred, nor are they necessarily indicative of the results of operations which may be expected to occur in the future. The unaudited pro forma financial data are based on assumptions that we believe are reasonable and should be read in conjunction with the financial statements and the accompanying notes thereto included elsewhere in this prospectus.
SOUTHERN POWER PRO FORMA FOR THE FOR THE PERIOD FROM PERIOD FROM INCEPTION INCEPTION (JANUARY 8, PLANT DAHLBERG FOR (JANUARY 8, 2001) TO THE SEVEN MONTHS ADJUSTMENTS 2001) TO DECEMBER 31, ENDED AND DECEMBER 31, 2001 JULY 31, 2001 ELIMINATIONS 2001 -------------- ------------------ ------------ ------------ (IN THOUSANDS) Operating revenues.................... $29,301 $41,153 $70,454 Operating expenses.................... 18,814 21,220 40,034 ------- ------- -------- ------- Operating income...................... 10,487 19,933 30,420 Other income.......................... 658 0 658 Interest expense, net................. 427 3,904 4,331 ------- ------- -------- ------- Income before income taxes............ 10,718 16,029 26,747 ------- ------- -------- ------- Income taxes.......................... 2,511 6,412 8,923 ------- ------- -------- ------- Net income............................ $ 8,207 $ 9,617 $17,824 ======= ======= ======== =======
20 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL We were formed in January 2001 as a new wholly owned subsidiary of Southern. We own, construct and acquire a substantial portion of Southern's new competitive contract-based wholesale generation assets which operate outside of traditional state regulation. We will be the primary vehicle to develop Southern's position in the competitive contract-based wholesale generation market. At June 30, 2002, 2,515 MW were in commercial operation and 2,262 MW of capacity were under construction. By the end of 2003, we plan to have 4,777 MW of generating capacity in commercial operation. In June 2001, Alabama Power Company transferred the Harris plant site and assigned the related vendor contracts to us. Alabama Power Company also transferred its interest in the Goat Rock site (which was subsequently renamed the Franklin site) to us at that time. In July 2001, Georgia Power Company transferred Dahlberg to us and assigned us three related PPAs with non-affiliated entities. In November 2001, Georgia Power Company transferred to us its interests in the Franklin site, including land and construction work in progress and assigned us the related vendor contracts. In January 2002, Georgia Power Company transferred the construction work in progress for Wansley 6 and 7 to us. See Notes B and I to our condensed consolidated financial statements and Note 2 to our consolidated financial statements herein for additional information related to these asset transfers. During 2001 and through May 2002, Dahlberg was our only electric generating facility in commercial operation. Franklin 1, Wansley 6 and Wansley 7 were placed into commercial operation in June 2002. We expect Franklin 2, Harris 1, Harris 2 and Stanton A to be in commercial operation in 2003 and Franklin 3, McIntosh 10 and McIntosh 11 in 2005. We intend for an Operating Company to operate each facility under the terms of an Operating Agreement if located within Southern's service territory. Because Stanton A is located outside of the Operating Companies' service territory, Stanton A will be operated by SCS. We have entered into PPAs for the sale of substantially all of our existing, under construction and planned generating capacity. The PPAs are structured to provide for capacity revenues sufficient to cover fixed costs and generate profit as long as our facilities meet specified availability standards or we are able to meet our obligations with alternate resources at a reasonable cost. The payment schedules under our PPAs generally reflect a summer surcharge for capacity. However, the related revenues are recognized on a levelized basis. RESULTS OF OPERATIONS We have a limited operating history. Our company was formed in January 2001 and began significant operations with the transfer of Dahlberg to us in July 2001. The following discussion and analysis should be read in conjunction with "RISK FACTORS" and "SELECTED HISTORICAL FINANCIAL DATA" and our condensed consolidated and consolidated financial statements and the accompanying notes appearing herein. Six Months Ended June 30, 2002 as Compared to Six Months Ended June 30, 2001 Operating Revenues. For the six months ended June 30, 2002, operating revenues were $77.1 million. Through May 2002, operating revenues were derived solely from the operations of Dahlberg. Wansley 6, Wansley 7 and Franklin 1 were placed in commercial operation on June 1, 2002. Of the total operating revenues, $42.8 million were derived from capacity and energy sales to non-affiliated companies under PPAs. The remainder ($34.1 million) was derived from sales to affiliated companies through the Southern Pool primarily under the PPAs for Wansley 6, Wansley 7 and Franklin 1. Revenues from sales to affiliated companies through the Southern Pool that are not covered by PPAs will vary depending on demand and the availability and cost of generating resources at each company within the Southern Pool. These transactions do not have a significant impact on earnings, since the energy is generally sold at variable cost. Our company earned no revenue during the six months ended June 30, 2001. 21 Operating Expenses. For the six months ended June 30, 2002, total operating expenses were $52.9 million. These expenses consist primarily of fuel ($21.2 million), purchased power ($15.5 million), general and administrative ($7.5 million), other operation and maintenance ($1.8 million), and depreciation ($5.5 million). For the six months ended June 30, 2001, our total operating expenses consisted of $1.7 million in general and administrative expenses related to the startup of our company. All of our generation is fueled by natural gas. The average price of natural gas for the six months ended June 30, 2002 was $3.87/mmBtu. This represents a 20% increase from the average price for the year ended December 31, 2001. We incurred no fuel expense for the six months ended June 30, 2001, since we had no plants in operation during that period. See "-- Future Earnings Potential" for discussion of our limited exposure to fuel risk under our existing PPAs. Expenses from purchased power transactions will vary depending on demand and the availability and cost of generating resources accessible through the Southern Pool. Load requirements are submitted to the Southern Pool on an hourly basis and are fulfilled with the lowest cost alternative available, whether that is Southern Power-owned generation, affiliate-owned generation or external purchases. See "OUR BUSINESS" herein for further discussion of the operations of the Southern Pool. Effective June 1, 2002, we changed Dahlberg's estimated useful life from 35 to 40 years, resulting in a $79,000 monthly decrease in depreciation expense. In addition, the general and administrative expenses include the writeoff in May 2002 of $2.9 million for previously deferred site investigation and site development costs associated with potential new plant sites that, after management review, are no longer considered probable of future development. Other, Net. For the six months ended June 30, 2002, other, net consisted primarily of the unrealized losses on derivative energy contracts. See "-- Market Price Risk" below for further information related to these contracts. Interest Expense, Net. Interest expense, net of amounts capitalized, totaled approximately $1.2 million for the six months ended June 30, 2002. After the commercial operation of Wansley 6, Wansley 7 and Franklin 1, on June 1, 2002, the construction base used to calculate the capitalization of interest decreased significantly. Net Income. For the six months ended June 30, 2002, net income was $13.3 million. Net income was derived primarily from the sale of wholesale capacity and energy to affiliated and non-affiliated companies. A significant portion of this income, $8.8 million, was earned in the second quarter of 2002 as a result of the commercial operations of Wansley 6, Wansley 7 and Franklin 1 on June 1, 2002 and the initiation of PPAs for those units with our affiliates, Georgia Power Company and Savannah Electric and Power Company. The remaining income was primarily derived from the PPAs with non-affiliates related to Dahlberg. For the six months ended June 30, 2001, we incurred a net loss of $1.0 million related to startup and organizational expenses. Year Ended December 31, 2001 Operating Revenues. Operating revenues for the period from January 8, 2001 through December 31, 2001 were $29.3 million. Operating revenues were derived solely from the operations of Dahlberg. The majority of the revenues ($26.4 million) were derived from capacity and energy sales to non-affiliated companies under PPAs. The remainder ($2.9 million) was derived from sales to affiliated companies through the Southern Pool. Revenues from sales to affiliated companies through the Southern Pool that are not covered by PPAs will vary depending on demand and the availability and cost of generating resources at each company within the Southern Pool. These transactions do not have a significant impact on earnings, since the energy is generally sold at variable cost. Expenses. Operating expenses totaled $18.8 million for the period from January 8, 2001 through December 31, 2001. Operating expenses consist primarily of fuel ($3.8 million), purchased power ($4.7 million), general and administrative expenses related to start-up and corporate support ($5.6 million), 22 other operation and maintenance ($1.0 million), and depreciation ($3.2 million). All of our generation is fueled by natural gas. The average price of natural gas for Dahlberg for the months of August through December 2001 was $3.23/mmBtu. Expenses from purchased power transactions will vary depending on demand and the availability and cost of generating resources accessible through the Southern Pool. Load requirements are submitted to the Southern Pool on an hourly basis and are fulfilled with the lowest cost alternative available, whether that is Southern Power-owned generation, affiliate-owned generation or external purchases. See "OUR BUSINESS" herein for further discussion of the operations of the Southern Pool. Interest Expense, Net. Interest expense, net of amounts capitalized, totaled approximately $427,000 for the period from January 8, 2001 through December 31, 2001. Net Income. Net income for the period from January 8, 2001 through December 31, 2001 was $8.2 million and was derived primarily from the sales of wholesale capacity and energy to affiliated and non-affiliated companies. EFFECTS OF INFLATION We are subject to long-term contracts and income tax laws that are based on the recovery of historical costs. While the inflation rate has been relatively low in recent years, it still has an adverse effect on us because of our large investments in generating facilities with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations such as long-term debt. FUTURE EARNINGS POTENTIAL The results of operations for 2001 and the six months ended June 30, 2002 are not necessarily indicative of future earnings. The level of future earnings depends on numerous factors including regulatory matters, energy sales and completion of construction on new generating facilities and the total generating capacity available in the Super Southeast. In 2001 and through May 2002, Dahlberg was our only electric generating facility in commercial operation. Franklin 1, Wansley 6 and Wansley 7 were placed in commercial operation in June 2002. Also in June 2002, our PPAs with Georgia Power Company, Savannah Electric and Power Company and 11 electric municipal cooperatives went into effect. See "OUR BUSINESS -- Existing and Approved Power Purchase Agreements, -- Requirements Agreements". We expect Franklin 2, Harris 1, Harris 2 and Stanton A to be in commercial operation in 2003 and Franklin 3, McIntosh 10 and McIntosh 11 in 2005. We have sold substantially all of our generating capacity in operation, under construction or planned under PPAs to the PPA Counterparties. The Harris 2 PPA with Georgia Power Company begins in June 2004. Our PPAs with non-affiliated counterparties have a material adverse change clause that requires the posting of collateral or an acceptable substitute guarantee in the event that S&P or Moody's downgrades the credit ratings of such counterparty to below-investment grade. The PPAs are expected to provide us with a stable source of revenue during their respective terms. Reference is made to Note 7 to the consolidated financial statements, regarding Long-Term Power Sales Contracts. We have a PPA with a PPA Counterparty that is currently experiencing liquidity problems and has had its credit rating reduced below investment grade. Minimum capacity revenues under this PPA average approximately $13 million annually through May 2005. The PPA Counterparty has provided a letter of credit totaling $20 million which expires in February 2003. See Note C to the Condensed Consolidated Financial Statements herein for an additional PPA related to Franklin 3. The PPA Counterparty has also provided us letters of credit totaling $50 million which expires in April 2003 in connection with this new PPA. These letters of credit can be drawn if not replaced by acceptable security prior to expiration or if the PPA 23 Counterparty defaults under the PPA. In the event of such a default, and if we are unable to resell that capacity in the market, future earnings could be affected. The outcome cannot now be determined. As a general matter, our existing PPAs provide that the PPA Counterparties are responsible for substantially all of the cost of fuel relating to the energy delivered under such PPA. To the extent a particular generating facility does not meet certain operational thresholds in a PPA, however, we may be responsible for a portion of the related fuel costs. With respect to fuel transportation risk, most of our PPAs provide that the PPA Counterparties are responsible for procuring and transporting the fuel to the particular generating facility. Fixed and variable operation and maintenance ("O&M") costs will be covered either through capacity charges or other charges based on dollars per kilowatt year or dollars per megawatt hour. We have also entered into long-term service contracts with General Electric International, Inc. ("GE") to reduce our exposure to certain O&M costs relating to GE equipment. See Note 5 to the consolidated financial statements herein for additional information. Although under some of our PPAs we will be selling energy to the Operating Companies, our generating facilities will not be in their regulated rate bases, and we will not be able to seek recovery from the Operating Companies' ratepayers for construction, repair and maintenance costs of our generating facilities. It is expected that the capacity payments in the PPAs will produce sufficient cash flow to meet these costs, pay debt service and provide an equity return. However, our overall profit will depend on numerous factors, including efficient operation of our generating facilities. FERC MATTERS In December 1999, the FERC issued its final rule on Regional Transmission Organizations ("RTO"). The rule encouraged utilities subject to FERC jurisdiction and owning transmission systems to form RTOs on a voluntary basis. Southern has submitted a series of status reports informing the FERC that its operating companies, Entergy Corporation, Cleco Power, and a number of non-jurisdictional cooperative and public power entities are developing a for-profit RTO known as SeTrans. In January 2002, the sponsors of SeTrans held a public meeting to form a Stakeholder Advisory Committee, which will participate in the development of the RTO. On April 25, 2002, the Stakeholder Advisory Committee met and selected the candidates that will be considered for the SeTrans Independent System Administrator. On June 27, 2002, Southern and the other SeTrans sponsors submitted a Petition for Declaratory Order seeking the FERC's guidance on various issues. The petition asks for a response from the FERC by October 2002. The creation of SeTrans is not expected to have a material impact on our financial statements. In November 2001, the FERC announced a new interim screen to assess generation dominance (for purposes of market-based rate authority), together with several mitigation measures for entities that fail the interim screen. Some of these mitigation measures pertain to transmission activities while others involve the spot energy market (the "SMA Order"). In that particular proceeding, the FERC determined that American Electric Power Company, Inc. ("AEP"), Entergy and Southern failed the new screen inside their control areas. Thus, the FERC imposed these mitigation measures on AEP, Entergy and Southern together with Southern's affiliates with market-based rate authorization which included us. However, in December 2001, the FERC issued a notice announcing that it would convene a technical conference to discuss the issue of generation dominance and deferred for an indefinite period the effective date of spot energy market mitigation measures. On January 14, 2002, the FERC issued an order granting Motions for Rehearing for Southern, AEP and Entergy for purposes of "reconsidering" the SMA Order. This order tolls the statutory time period by which the FERC is required to act; however, the FERC has announced that it intends to convene a technical conference to address the market dominance issue in the future. On July 31, 2002, the FERC issued a notice of proposed rulemaking entitled "Remedying Undue Discrimination Through Open Access Transmission Service and Standard Electricity Market Design" ("SMD NOPR"). The FERC has indicated that the proposal, if adopted, would (among other things): (i) require transmission assets of jurisdictional utilities to be operated by an independent entity; (ii) establish a standard electric market design; (iii) establish a single type of transmission service that applies to all customers; (iv) assert jurisdiction over the transmission component of bundled retail service; (v) establish a generation 24 reserve margin; (vi) establish bid caps for day-ahead and spot energy markets; (vii) revise the FERC policy on the pricing of transmission expansions; (viii) establish market monitoring and market mitigation measures; and (ix) institute locational marginal pricing as a market-based solution to transmission congestion and Congestion Revenue Rights as the means to hedge against the associated financial effects. Comments on the proposal are due October 15, 2002. FERC anticipates issuing a final rule near the end of 2002. Any impact of this proposal on Southern Power will depend on the form in which the final rule may be ultimately adopted. On August 1, 2002, FERC issued a notice of proposed policy statement ("NOPPS") proposing to adopt a general policy regarding the standard of review that must be met to justify proposed changes to a market-based rate contract for wholesale sales of electric energy. Comments are due September 23, 2002. FERC proposes to require parties to a bilateral market-based contract to include precise language if they intend the standard of review for contract changes (which would include rate changes) to be the higher and more strict "public interest" standard. If the contract does not contain this precise and stricter language, FERC intends to apply the lower and less strict "just and reasonable" standard of review to proposed contract changes. FERC notes that the purpose of this policy statement is to promote contract certainty necessary to support competitive wholesale power markets. ENVIRONMENTAL MATTERS Federal and state environmental regulatory agencies are actively considering and developing additional control strategies for emission of air pollution from all major sources of air pollution, particularly including electric generating facilities. This includes the overall reduction of emission of nitrogen oxides (NO(x)) in the eastern United States, the reduction of NO(x) and particulate matter emissions to reduce regional haze and visibility impairment in sensitive areas, the development of appropriate control standards and technologies for emissions of mercury and the reduction of so-called "greenhouse gases" (such as carbon dioxide) to address concerns over global climate change. Development and implementation of final federal and state rules on these issues could require substantial further reductions in all air emissions associated with electricity generation. Additional compliance costs and capital expenditures resulting from the implementation of such rules and standards cannot be determined until the results of legal challenges are known and final rules have been adopted at both the federal and state level. The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: control strategies to reduce regional haze; limits on pollutant discharges to impaired waters; cooling water intake restrictions; and hazardous waste disposal requirements. The impact of any new standards will depend on the development and implementation of applicable regulations. Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of our company's operations. The full impact of any such changes cannot be determined at this time. Compliance with possible additional legislation related to global climate change and other environmental and health concerns could significantly affect our company. The impact of new legislation, if any, will depend on the subsequent development and implementation of applicable regulations. All of our PPAs contain provisions that permit us to charge the counterparty with some of the new costs incurred as a result of change in law, including environmental regulations. Certain environmental, natural resource and land use concerns could have an effect on site selection. This includes the potential for designation of target areas as non-attainment for ozone or particulate matter under newly adopted National Ambient Air Quality Standards, the availability of water withdrawal rights, uncertainties regarding aesthetic impacts such as increased light or noise or regarding any potential for adverse health impacts associated with electric and magnetic fields. Such concerns and uncertainties can increase the cost of siting and operating any type of electric generating facility. 25 LIQUIDITY AND CAPITAL RESOURCES The primary sources of our liquidity for the year ended December 31, 2001 and the six months ended June 30, 2002 were equity contributions and subordinated loans from Southern and borrowings under our Credit Facility, as well as the issuance of the Original Senior Notes in June 2002. The primary uses of these funds were for acquisitions related to and construction of our electric generating facilities. From time to time, we may receive subordinated loans from Southern in the form of a subordinated promissory note. On June 20, 2001, we issued a subordinated promissory note to Southern (the "Southern Subordinated Note"). As of June 30, 2002, $186 million aggregate principal amount was outstanding under the Southern Subordinated Note, which amount varies from month to month and is being used to fund Franklin 3, McIntosh 10 and McIntosh 11 until other financing is arranged. The Southern Subordinated Note bears interest at a rate that is the higher of the average effective interest cost of Southern's outstanding obligations for borrowed money or the applicable Federal Rate for short-term loans published by the Internal Revenue Service. The principal amount on the Southern Subordinated Note is due upon demand by Southern, but in no event later than June 20, 2003. The Southern Subordinated Note is subordinate and subject in right of payment to the prior payment in full of all of our indebtedness, liabilities and obligations (including the Original Senior Notes) whether direct or indirect, absolute or contingent, due or to become due or now in existence or hereinafter occurred for borrowed money, including without limitation, all principal, interest, premium upon repayment and related fees and expenses and, in respect of or pursuant to or otherwise arising out of any guarantees, indemnities, sureties, support or capital maintenance agreements or keep-well agreements of or with respect to our indebtedness, liabilities or obligations or any one or more of our affiliates or subsidiaries ("Senior Indebtedness") and any promissory notes issued pursuant thereto, subject, however, to any such indebtedness, liabilities or obligations being expressly designated as subordinate to the Southern Subordinated Note. We shall not make any payment on account of the Southern Subordinated Note if an "event of default" shall have occurred and be continuing under any Senior Indebtedness until such Senior Indebtedness shall have been paid in full. We may issue a similarly subordinated promissory note in June 2003 to repay any outstanding amounts on the Southern Subordinated Note. Additionally, from time to time in the future, we may issue similarly subordinated notes which may include provisions permitting us to extend maturity or convert into our equity. In November 2001, we entered into the three-year $850 million senior unsecured revolving Credit Facility with Citibank N.A., as the administrative agent and the lenders listed therein. We are permitted to use amounts drawn under the Credit Facility to finance acquisition and construction costs related to gas-fired electric generating facilities, general corporate purposes (subject to a $25 million limit) and to pay or back-stop commercial paper issued to finance construction or acquisition costs of gas-fired electric generating facilities, subject to borrowing limitations for each generating facility. Currently, costs of acquisition and construction of Dahlberg, Wansley 6, Wansley 7, Franklin 1, Franklin 2, Harris 1, Harris 2 and Stanton A are or will be funded in part under the Credit Facility. The Credit Facility does permit additional gas-fired generating facilities to be financed by borrowings under the Credit Facility upon meeting certain requirements. Southern executed an equity contribution agreement (the "Southern Equity Contribution Agreement") at the closing of our Credit Facility which requires Southern to make equity contributions to fund 40% of the costs of construction and acquisition of each generating facility financed under the Credit Facility. In connection with our execution of the Credit Facility, Southern executed a guarantee of completion of construction of each generating facility that is financed in part by the lenders under the Credit Facility (the "Completion Guarantee"). Under the terms of the Completion Guarantee, Southern guarantees timely completion of construction of the facilities financed under the Credit Facility, agrees to fund any associated construction cost overruns to the extent our own cash flow is insufficient, and agrees to prepay all of the indebtedness borrowed for a generating facility if such facility does not achieve completion of construction within two years of the scheduled completion date, and may be obligated to repay a portion of such indebtedness if completion is achieved but guaranteed performance levels at completion are not met. In addition, prepayment of all outstanding indebtedness under our Credit Facility associated with any generating facility which has not yet achieved completion is required upon the occurrence of certain events of default 26 relating to Southern, including, but not limited to, bankruptcy of Southern or any significant subsidiary of Southern, payment default under other Southern indebtedness of at least $100 million, or change of control of Southern. Our Credit Facility matures on November 15, 2004. Borrowings under our Credit Facility will accrue interest, at our option, at either (i) the base rate plus a specified margin or (ii) the eurodollar rate plus a specified margin. In addition, we pay fees and expenses based upon borrowing availability and administrative and legal costs. At December 31, 2001 and June 30, 2002, the eurodollar rate option was in effect with resulting interest rates of 3.44% and 3.01%, respectively. Our Credit Facility contains covenants restricting our activities, including limitations on payments of dividends and other distributions, creation of liens, incurrence of debt and asset sales. Our Credit Facility also requires us to maintain a ratio of recourse debt to total capitalization of not more than 0.6:1.0 (60%) throughout the term of the Credit Facility. As of June 30, 2002, we are in compliance with all of these covenants. As of June 30, 2002, we had approximately $158.2 million in outstanding borrowings and $691.8 million in borrowing availability remaining under our Credit Facility. Our Credit Facility permits us to fund construction of future generating facilities with borrowings under the Credit Facility upon meeting certain requirements. We intend to finance construction of certain future gas-fired electric generating facilities with a combination of equity contributions and subordinated loans from Southern, borrowings under our Credit Facility and other available financings. Upon completion of construction of a generating facility, we intend primarily to use proceeds of additional senior notes, and project financings on a limited basis, to repay borrowings under our Credit Facility. Southern is currently authorized by the SEC under the Holding Company Act to fund the development of our company up to an aggregate amount not to exceed $1.7 billion, which may take the form of purchases or contributions of equity interests, loans and guarantees issued in support of our securities or obligations. As of June 30, 2002, Southern has invested a total of $1.0 billion in us, in the form of equity investments, subordinated loans and guarantees. We also have SEC approval under the Holding Company Act to issue up to an aggregate amount of $2.5 billion of preferred securities, long and short-term debt and other equity issuances. We will maintain the equity component of our consolidated capitalization at or above 30% unless otherwise permitted by the SEC. ACCOUNTING POLICIES CRITICAL ACCOUNTING POLICIES Our accounting policies are described in Note 1 to our consolidated financial statements herein, under "Basis of Presentation and Summary of Significant Accounting Policies." We have identified three critical accounting policies that require a significant amount of judgment and are considered to be the most important to the presentation of our financial position and results of operations. The first critical policy is our levelized recognition of capacity revenues from long-term contracts as further described in Note 7 to our consolidated financial statements as of December 31, 2001 under "Long-Term Power Sales Contracts." Under this policy, we recognized $1.7 million and $5.0 million less in revenues for the year ended December 31, 2001 and for the six months ended June 30, 2002, respectively, than we actually received in payments. Secondly, as further described in Note 3 to our consolidated financial statements under "Financial and Other Derivative Instruments," we designate qualifying derivative instruments as cash flow or fair value hedges under Statement of Financial Accounting Standards ("SFAS") No. 133. We mark such derivative instruments to market based primarily on quoted market prices. The unrealized changes in fair value of qualifying cash flow hedges are deferred in Other Comprehensive Income. Any ineffectiveness in those hedges and changes in non-qualifying positions is reported as a component of current period income. Third, as further described in Note 8 to our consolidated financial statements under "Income Taxes," we use flow-through accounting for state manufacturer's tax credits. This means that we recognize the credit as a reduction of tax expense when it is more likely than not that it has been earned. We recognized $2.7 million of these credits in 2001. 27 NEW ACCOUNTING STANDARDS In June 2001, the FASB issued Statement No. 143, Asset Retirement Obligations, which establishes new accounting and reporting standards for legal obligations associated with retiring assets. The liability for an asset's future retirement must be recorded in the period in which the liability is incurred. The cost must be capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Changes in the liability resulting from the passage of time will be recognized as operating expense. Statement No. 143 must be adopted by January 1, 2003. We are currently assessing the impact of adopting Statement No. 143 on our financial statements. The Emerging Issues Task Force is currently addressing how to determine whether an arrangement, including purchase power agreements, constitutes a lease within the scope of SFAS No. 13, in Issue No. 01-08, Determining Whether an Arrangement is a Lease. Any impact on our company will depend on the form in which final rules may be ultimately adopted. FINANCIAL CONDITION OVERVIEW In 2001, gross utility plant additions were $766 million. These additions were primarily related to the purchase of the Dahlberg combustion turbine units and the construction of combined cycle units. For the six months ended June 30, 2002, gross utility plant additions were $853 million. These additions were primarily related to on-going construction of the combined cycle units and the purchase of Wansley 6 and Wansley 7. The funds needed for gross property additions were provided by our Credit Facility, the issuance of the Original Senior Notes and capital contributions and subordinated loans from Southern. CREDIT RATING RISK We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral -- but not accelerated payment -- in the event of a credit rating change to below investment grade. These contracts are primarily for physical electricity sales, fixed-price physical gas purchases and agreements covering interest rate swaps and currency swaps. At June 30, 2002, the maximum potential collateral requirements under the electricity sale contracts were approximately $174 million. Generally, collateral may be provided for by a Southern guaranty, letter of credit or cash. At June 30, 2002, there were no material collateral requirements for the gas purchase contracts or other financial instrument agreements. MARKET PRICE RISK We are exposed to market risks, including changes in interest rates, currency exchange rates, and certain commodity prices. To manage the volatility attributable to these exposures, we net the exposure to take advantage of natural offsets and enter into various derivative transactions, for the remaining exposure pursuant to our policies in areas such as counterparty exposure and hedging practices. Our policy is that derivatives are to be used primarily for hedging purposes. Derivative positions are monitored using techniques that include market valuation and sensitivity analysis. If we sustained a 100 basis-point change in interest rates for all variable rate long-term debt, the change would affect annualized gross interest cost by approximately $2.9 million at December 31, 2001 and $3.5 million at June 30, 2002. Most or all of that change would be capitalized, given the size of our construction program. To further mitigate our exposure to interest rates, in 2001, we entered into interest rate swaps that were designated as cash flow hedges of our 2002 and 2003 planned debt issuances. Changes in the fair values of these swaps are deferred in other comprehensive income. Based on our overall interest rate exposure at June 30, 2002, including derivative and other interest-rate sensitive instruments, a near-term 100 basis-point change in interest rates would not materially affect our financial statements. In addition, we are not aware of any facts or circumstances that would significantly affect such exposures in the near term. 28 Because energy from our facilities is primarily sold under long-term contracts with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the PPA Counterparties, our exposure to market volatility in commodity fuel prices and prices of electricity is limited. To mitigate residual risks in those areas, we enter into fixed-price contracts for the purchase or sale of fuel and electricity. In connection with the transfers to us of Franklin in 2001 and Wansley in 2002, Georgia Power Company transferred approximately $5.6 million and $1.6 million, respectively, in derivative assets relating to electric and gas forward contracts in effect at the date of the transfers. These contracts were recorded at fair value on the date of the transfer, which was equal to Georgia Power Company's carrying amount. Following the transfer, these contracts are marked to market until realized and settled. We have firm purchase commitments that require payment in Euros. As a hedge against fluctuations in the exchange rate for Euros, we entered into forward contracts to purchase Euros and have designated these contracts as fair value hedges of an unrecognized firm commitment. Since the terms of these Euro contracts mirror the purchase commitment terms, there is no ineffectiveness recognized in income. At June 30, 2002, we had outstanding contracts covering a notional amount of $19.8 million in commitments through May 2003. Unrealized gains and losses on electric and gas contracts used to hedge anticipated purchases and sales are deferred in other comprehensive income. Gains and losses on contracts that do not represent hedges are recognized in the Statement of Income as incurred. The fair values of derivative energy contracts at December 31, 2001 and June 30, 2002 are as follows:
TOTAL FAIR VALUE DEFERRED IN RECOGNIZED IN ELECTRIC AND GAS OTHER COMPREHENSIVE CURRENT PERIOD FORWARD CONTRACTS INCOME INCOME ----------------- ------------------- -------------- (IN MILLIONS) Contracts, January 8, 2001............. -- -- -- Less: Contracts realized or settled.... -- -- -- New contracts at inception............. 5.6 Changes in valuation techniques........ -- -- -- Current period changes................. (.1) (.7) .6 Contracts, December 31, 2001 based on actively quoted prices............... 5.5 -- -- Less: Contracts realized or settled.... 2.8 0.8 2.0 New contracts at inception............. 1.6 Changes in valuation techniques........ -- -- -- Current period changes................. -- -- -- Contracts, June 30, 2002 based on actively quoted prices............... 4.3
At June 30, 2002, approximately $2.3 million of these contracts will mature within 12 months, with the remainder maturing within 3 years. See "-- Financing Activities" below and Note 3 to the consolidated financial statements herein for additional information. 29 FINANCING ACTIVITIES At year-end 2001, our capitalization consisted of 61% equity and 39% debt. At June 30, 2002, our capitalization consisted of 43% equity and 57% debt including the Southern Subordinated Note. Our long-term target capitalization is 65% debt for facilities completed and in commercial operation. Currently, the Credit Facility requires us to maintain a ratio of recourse debt, which excludes the Southern Subordinated Note, to total capitalization of not more than 0.6:1.0 (60%). Additionally, under the Southern Equity Contribution Agreement, Southern is required to fund 40% of the cost of construction of each generating facility financed under the Credit Facility with capital contributions. If permitted by an amendment to our Credit Facility and Southern Equity Contribution Agreement or after the termination of our Credit Facility, we intend to fund our new construction first with the 35% equity from Southern before drawing on any debt construction financing. Capital contributions from Southern through year-end 2001 were approximately $452 million. During the first six months of 2002, Southern made additional equity contributions of approximately $254 million, plus subordinated loans of approximately $185 million. Equity contributions and subordinated loans from Southern are projected to total approximately $523 million by the end of 2002. No dividends were paid in 2001. No dividends are projected to be paid in 2002. In June 2002, we issued $575 million of the Original Senior Notes. The net proceeds were used to reduce outstanding indebtedness under our Credit Facility and subordinated loans from Southern. In June 2002, we also settled several interest rate swap agreements originally entered into in anticipation of this issuance for $16.9 million. This amount has been deferred in other comprehensive income and will be amortized to interest expense over the life of the Original Senior Notes. See Note L in the Notes to Condensed Consolidated Financial Statements herein for additional information. OFF-BALANCE SHEET FINANCING ARRANGEMENTS In 2001, we entered into a financing arrangement with Westdeutsche Landesbank Girozentrale ("WestLB") and Southern guaranteed our obligations under the arrangement. Under this agreement, we had the right to assign up to $125 million in vendor contracts for equipment to WestLB, who following such assignment would become the owner of such contracts. We acted as agent for WestLB, including instructing WestLB when to make payments to the vendors. At December 31, 2001, approximately $47 million of such vendor equipment contracts had been assigned to WestLB. This financing arrangement was terminated on March 22, 2002, and we repurchased the equipment at original cost, which totaled approximately $61 million including interest and fees, using funds from the Southern Subordinated Note. We will indemnify WestLB against any future claims arising from the arrangement and Southern has guaranteed our indemnification obligation. In conjunction with the termination of the agreement, WestLB assigned a contract with Alstom Power Inc. ("Alstom") related to the purchase and sale of a steam generator and auxiliary equipment for Franklin 3 to us. Southern entered into a limited keep-well arrangement with Alstom whereby Southern will contribute funds to us via loans or capital contributions to fund our performance or equipment purchases under certain arrangements. As of June 30, 2002, our remaining purchase obligations to Alstom totaled $5 million. CAPITAL REQUIREMENTS FOR CONSTRUCTION Capital expenditures are estimated to be $834 million for 2002, $488 million for 2003 and $473 million for 2004. For additional information, see Note 2 to our consolidated financial statements herein under "Asset Transfers and Construction Program." The significant contractual capital commitments during this period relate to turbine purchases of $141.1 million, $93.1 million and $34.1 million in 2002, 2003 and 2004, respectively. While the turbine 30 purchase contracts have cancellation options, we do not consider cancellation to be an economically viable alternative. Actual construction costs may vary from estimates because of changes in such factors as: business conditions; environmental regulations; the cost and efficiency of construction labor, equipment and materials and the cost of capital. OTHER CAPITAL REQUIREMENTS In addition to the construction program requirements, funds will also be required by the end of 2004 for principal payments on borrowings under our Credit Facility and the Southern Subordinated Note. We also have outstanding commitments for fuel and payments under our long-term service agreements ("LTSAs"). The LTSAs cannot be canceled before the end of 2004. At December 31, 2001, these capital requirements and purchase commitments -- discussed further in Notes 4, 5, and 9 to the consolidated financial statements herein -- are as follows.
2002 2003 2004 ---- ---- ---- (IN MILLIONS) Borrowings: Credit Facility........................................... -- -- 293 Southern Subordinated Note................................ 1 -- -- Purchase Commitments: Fuel...................................................... 2 8 4 Long-term Service Agreements.............................. 8 12 17
At June 30, 2002, we had used $158.2 million of our $850 million available credit, which expires in November 2004. In addition, we had $186 million outstanding under the Southern Subordinated Note. 31 OUR BUSINESS We are a wholly owned subsidiary of Southern. We were formed to own, construct and acquire Southern's new competitive contract-based wholesale generation assets. Consequently, our business activities should not be subject to traditional state regulation. We will be the primary vehicle to develop Southern's position in this competitive contract-based wholesale generation market. It is contemplated that substantially all of our generating capacity will be committed under long-term, fixed-price PPAs primarily with our affiliates. We are an electric utility company as defined under the Holding Company Act. We are subject to regulation under the Holding Company Act because we are a wholly owned subsidiary of Southern, a registered public utility holding company under the Holding Company Act. As a separate subsidiary in the Southern system, we provide the means by which Southern can own, construct and acquire new generation assets outside of the traditional rate-based state regulated generation structure. Substantially all of our operating or under construction generating facilities were acquired from affiliates within the Southern system. We intend to own and finance all of the new competitive contract-based wholesale generation assets to be built in the Southern system. Southern believes that this structure is most effective for pursuing generation opportunities in the competitive wholesale markets. This structure ensures a consistent approach to developing new wholesale generation and improves efficiency. We intend to own, construct and acquire generating facilities in the Super Southeast and to sell the output of our generating facilities under long-term, fixed-price capacity contracts to wholesale customers in this region. The Super Southeast includes the states in Southern's traditional service territory -- Alabama, Florida, Georgia, and Mississippi. Our customers in these states are expected to be predominantly the Operating Companies, but will include unaffiliated third parties as well. The Super Southeast also consists of the surrounding states of Kentucky, Louisiana, North Carolina, South Carolina, Tennessee, and Virginia. Although we will focus on the Super Southeast, we may also acquire or construct generating facilities outside of the Super Southeast or sell the output of our generating facilities to customers outside of the Super Southeast. As of June 30, 2002, we had 4,777 MW of generating capacity in commercial operation or under construction. By the end of 2005, we expect to have approximately 6,600 MW of generating capacity in commercial operation. Currently, substantially all of our existing, under construction and planned generating capacity is committed under PPAs with the PPA Counterparties. All of the PPA Counterparties are strong entities from either a credit or financial security perspective. Along with the Operating Companies, we are a member of and share in the benefits and obligations of the Southern Pool. As a member of the Southern Pool our generating facilities located within Southern's service territory will be economically dispatched with the generating facilities of the Operating Companies to serve the members' aggregate load requirements. A member of the Southern Pool has the first call on its own generating resources, but if lower cost generation resources are available on the Southern system, a Southern Pool member has the right to purchase that lower variable cost energy to satisfy its obligations. As a member of the Southern Pool, we will also benefit from economies of scale, share geographic load diversity and maintain lower reserve levels than would be required on a stand-alone basis. The Southern Pool includes approximately 37,000 MW of generating capacity. For each of our generating facilities located in the service territory of an Operating Company, there will be an interconnection agreement to govern the interconnected operations of that facility with the transmission facilities of the appropriate Operating Company. Each Operating Company is interconnected to the transmission facilities of the other Operating Companies by means of high-voltage lines. Additionally, the Operating Companies have long-standing contracts with the principal neighboring utility systems relating to capacity exchanges, capacity purchases and sales, transfers of economy energy and other similar transactions. For the most part, such interchange transactions are now conducted under market-based tariff arrangements. We expect each generating facility located outside of the Operating Companies' service territory will have an interconnection agreement with the applicable transmission provider. Regardless of whether a facility is 32 located in or outside of the service territory of an Operating Company, transmission service will need to be reserved across the applicable transmission systems to deliver power from each facility, which includes obtaining transmission service across each applicable Operating Company. In order to optimize efficiencies, we will utilize employees currently in the Southern system for our day-to-day operations at our generation facilities. For each of our generating facilities in an Operating Company's service territory, we intend for such Operating Company to provide operation and maintenance services at cost (in accordance with the Holding Company Act). There are or will be operation and maintenance contracts between us and the appropriate Operating Company for the facilities located in such Operating Company's service territory. Because Stanton A is located outside of the Operating Companies' service territory, SCS will be responsible for the operation and maintenance of Stanton A. Additionally, under the terms of a services agreement, SCS will perform overall project management of the construction process of our generating facilities. The FERC has adopted standards of conduct that govern the relationship between SCS on behalf of the Operating Companies (as transmission provider) and its affiliated wholesale merchant function, which includes us. Among other things, the standards of conduct prohibit employees of Southern's transmission function from providing preferential access to information about the Southern transmission system that is not publicly available to all users as posted on Southern's Open Access Same-Time Information System (OASIS). Southern (and the Operating Companies) is also required to provide transmission service in a non- discriminatory and impartial manner to affiliates and non-affiliates alike. In September 2001, the FERC issued a notice of proposed rulemaking to revise the standards of conduct. Among other things, the proposal would broaden the scope of the standards and may result in additional restrictions. The FERC has received comments on the proposed rule. The FERC issued a follow-up white paper in April 2002, and comments on that paper were due in June 2002. It is uncertain when the FERC will issue a final rule. In addition to these FERC rules, the applicable state PSCs may have affiliate rules in place that govern our interaction with an Operating Company (such as those pertaining to participation in an RFP). BUSINESS STRATEGY Our strategy is to develop and acquire additional generating facilities to compete for and serve the demand in the Super Southeast market. To implement this strategy, we plan to: DERIVE AT LEAST 80% OF OPERATING CASH FLOW UNDER LONG-TERM, FIXED PRICE PPAS. We intend to have a significant portion of our existing, under construction and planned capacity committed under PPAs mostly with the Operating Companies, but also with certain third parties that are predominantly strong entities from either a credit or financial security perspective. UTILIZE THE EXPERTISE OF SOUTHERN AFFILIATES IN PLANNING, DESIGNING, CONSTRUCTING, MARKETING, OPERATING AND MAINTAINING GENERATING FACILITIES. All of our business currently is and is expected to be operated by Southern affiliates with participation of our management. To optimize efficiencies, we will utilize employees currently in the Southern system for our day-to-day operations at our generating facilities located in Southern's service territory. In 2001, the employees of Southern and its affiliates achieved a peak season Equivalent Forced Outage Rate ("EFOR") of 2 percent, which was the lowest in Southern history. SCS will perform overall project management of the construction process of our generating facilities. MITIGATE MARKET PRICE, FUEL SUPPLY, FUEL TRANSPORTATION AND ELECTRIC TRANSMISSION RISK. By negotiating long-term PPAs for substantially all of our existing, under construction and planned generating capacity, we have attempted to lessen our exposure to market risk. Additionally, we have negotiated the terms of most of our PPAs to insulate our company from significant fuel supply, fuel transportation and electric transmission risks, in most instances, by making such risks mostly the responsibility of the PPA Counterparties. We intend to continue this business practice. 33 FOCUS ON THE SUPER SOUTHEAST FOR ADDITIONAL GENERATION AND WHOLESALE MARKETING OPPORTUNITIES. We intend to focus primarily on the Super Southeast for additional generation opportunities. We believe the Super Southeast is a particularly attractive market because the existing and projected supply and demand for power in this region will require the construction of new generating facilities to meet expected increased customer demand. Additionally, the Southeast has a stable regulatory environment for electricity with regulators that recognize the need for reliable power supply. EXPAND OUR ASSET BASE TO AT LEAST 6,600 MW IN COMMERCIAL OPERATION BY YEAR-END 2005, WITH POTENTIAL FOR FURTHER CAPACITY ADDITIONS THEREAFTER. We intend to continue to expand our generation capacity. By the end of 2003, we expect to have approximately 4,777 MW of generating capacity in commercial operation. We expect to begin construction of Franklin 3, McIntosh 10 and McIntosh 11 in the last half of 2002 with scheduled completion dates in June 2005. The expected capacity of Franklin 3 is 615 MW and McIntosh 10 and McIntosh 11 is 1,240 MW. The addition of these three units will increase our capacity to over 6,600 MW. We will continue to evaluate opportunities to construct or acquire new generating facilities. COMPETITIVE STRENGTHS We believe that we are well positioned to implement our business strategy because of the following competitive strengths: STABLE REVENUES UNDER LONG-TERM, FIXED-PRICE PPAS. Substantially all of our existing, under construction or planned capacity is committed under long-term, fixed-price PPAs with initial terms of five to 25 years. These PPAs are predominantly with the Operating Companies who all maintain solid investment grade credit ratings. Additionally, our existing PPAs with the Operating Companies relating to generating facilities in operation or under construction have already been approved by the respective state PSCs as well as the FERC. Given these minimal credit and regulatory risks, we believe that these PPAs will provide us with relatively stable energy revenues. MITIGATION OF MARKET PRICE, FUEL SUPPLY, FUEL TRANSPORTATION AND ELECTRIC TRANSMISSION RISK. Through the terms of the PPAs, we have effectively mitigated our market price risks for substantially all our existing, under construction and planned generating capacity. Additionally, with respect to most of our PPAs, fuel supply, fuel transportation and electric transmission are, in most instances, the responsibilities of the PPA Counterparties. By structuring these provisions of the PPAs in this manner, we are effectively insulated from any significant fuel supply, fuel transportation and electric transmission risk during the terms of the PPAs. RELATIONSHIP WITH SOUTHERN. Southern has been active in the Super Southeast wholesale market for years and has developed extensive marketing experience. Our management team is comprised of seasoned individuals from within the Southern system who have long-standing experience with generating facilities, power sales and dispatch, engineering, construction, market conditions, and business development. Additionally, Southern has developed strong relationships in the Southeast energy market. EFFICIENCIES RELATING TO NEW GENERATING FACILITIES. To maximize experience and efficiencies, we will utilize employees currently in the Southern system for our day-to-day operations of our generation facilities. Our agreements with the Operating Companies and SCS will allow us to optimize their extensive knowledge, experience and proven track record in power plant and power systems operations. Additionally, all of our initial facilities will be new, state of the art, gas-fired generation using GE gas turbines. To reduce our exposure to operation and maintenance costs we have entered into long-term service agreements with GE for substantially all of our generating facilities. Under these services agreements, GE is obligated to cover the major maintenance of the GE equipment. STABLE REGULATORY ENVIRONMENT. The Super Southeast has a stable regulatory environment for electricity. ABSENCE OF ELECTRIC RESTRUCTURING LEGISLATION IN SOUTHERN'S SERVICE TERRITORY. No state legislature or regulatory authority within the Southern traditional service territory has adopted electric utility service restructuring. 34 STABLE REGIONAL DEMAND. The Super Southeast has historically been a strong area for economic growth, and we believe that we will be able to benefit from future regional supply and demand patterns. OUR EXISTING ELECTRIC GENERATING FACILITIES Our electric generating facilities currently operating or under construction are:
FACILITY LOCATION UNIT TYPE(1) TOTAL MW(2) IN-SERVICE DATE - -------- -------- ------------ ----------- --------------- Dahlberg Units 1-10............... Jackson County, CT 810 May/June 2000 (Units 1-8) Georgia May 2001 (Units 9 & 10) Wansley 6 and Wansley 7(3)............... Heard County, Georgia CC 1,134 June 2002 Franklin 1........... Lee County, Alabama CC 571 June 2002 Franklin 2........... Lee County, Alabama CC 615 June 2003 (scheduled) Harris 1............. Autauga County, CC 618 June 2003 (scheduled) Alabama Harris 2............. Autauga County, CC 618 June 2003 (scheduled) Alabama Stanton A............ Orlando, Florida CC 411(4) October 2003 (scheduled) ----- TOTAL................ 4,777 =====
- --------------- (1) "CT" means combustion turbine and "CC" means combined-cycle. (2) Total MW reflects designed output under rated conditions as specified by each facility's capacity test under its respective PPA. Dahlberg reflects its tested new and clean capacity while peak firing. (3) We lease Wansley 6 and Wansley 7 from the Development Authority of Heard County and have the beneficial economic ownership. For a more detailed description of the ownership structure, See "-- Our Existing Electric Generating Facilities -- Wansley 6 and Wansley 7" below. (4) Represents our sixty-five percent undivided ownership interest in Stanton A. For a more detailed description of the ownership structure, See "-- Our Existing Electric Generating Facilities -- Stanton A" below. DAHLBERG Dahlberg is an 810 MW facility consisting of ten GE 7EA gas turbines located in Jackson County, near Athens, Georgia. Currently, all ten units are in service. The first eight units were completed in June 2000 under a turnkey contract with GE and the remaining two units were completed in May 2001. Georgia Power Company built Dahlberg to meet wholesale obligations under contracts with LEM and Dynegy Power, which have been assigned to us. On July 31, 2001, Georgia Power Company transferred the ten units to us and we financed such transfer using equity contributions and subordinated loans from Southern. WANSLEY 6 AND WANSLEY 7 Wansley 6 and Wansley 7 are two new combined-cycle units that are adjacent to an existing coal-fired plant in Heard County, Georgia, that is co-owned by Georgia Power Company, Oglethorpe Power Cooperative ("OPC"), Municipal Electric Authority of Georgia ("MEAG") and the City of Dalton, Georgia. Wansley 6 and Wansley 7 have a total output of 1,134 MW. Construction began in August 2000. On January 22, 2002, Georgia Power Company transferred its interest in Wansley 6 and Wansley 7 to us. Wansley 6 and Wansley 7 went into commercial operation in June 2002. Each Wansley unit includes two GE 7FA gas turbines, two Vogt-NEM triple pressure HRSGs, and a GE steam turbine. Dry low NOx burners are included in the gas turbines. Duct burners are provided for supplemental firing of the HRSGs to provide additional peaking capability. Each unit's summer peak capacity is 567 MW. 35 We lease Wansley 6 and Wansley 7 from the Development Authority of Heard County for certain ad valorem tax abatement opportunities. The Development Authority of Heard County holds legal title to Wansley 6 and Wansley 7 but beneficial economic ownership remains with us during the term of this arrangement. We have the right to purchase Wansley 6 and Wansley 7 at any time and are required to do so at the end of the lease term in each case for a nominal amount from the Development Authority of Heard County. FRANKLIN 1 AND FRANKLIN 2 Franklin 1 and Franklin 2 are part of a combined-cycle facility in Lee County, Alabama, that will total 1,186 MW upon completion. Until June 30, 2001, Georgia Power Company and Alabama Power Company owned the plant site as tenants in common. As of June 30, 2001, Alabama Power Company transferred its interest in the plant site and related contracts to us and as of November 16, 2001, Georgia Power Company transferred its interest in the plant site and related contracts in such property to us. The site currently has one unit in commercial operation, a second unit under construction and a third unit is planned. The site is permitted and engineered to allow for a fourth unit. Franklin 1 began construction in June 2000 and went into commercial operation in June 2002. Franklin 2 began construction in June 2001 with a scheduled completion date of June 2003. Franklin 1 is a natural gas-fired combined-cycle unit. It has two GE 7FA gas turbines, two Vogt-NEM triple pressure HRSGs, and a GE steam turbine. Dry low NOx burners are included in the gas turbines. Duct burners are provided for supplemental firing of the HRSGs to provide additional peaking capability. Franklin 1's capacity is 571 MW peak firing under summer conditions. Franklin 2 will be a slightly larger natural gas-fired combined-cycle unit than Franklin 1. It will use two GE 7FA gas turbines, two Deltak triple pressure HRSGs, and an Alstom steam turbine. Dry low NOx burners are also included in the gas turbines. Duct burners are provided for supplemental firing of the HRSGs to provide additional peaking capability. Franklin 2's expected capacity is 615 MW peak firing under summer conditions. Franklin 1 and Franklin 2 were previously known as Goat Rock 1 and Goat Rock 2, respectively. HARRIS 1 AND HARRIS 2 Harris 1 and Harris 2 are part of a combined-cycle facility in Autauga County, Alabama, approximately twenty miles northwest of Montgomery, Alabama. Harris 1 and Harris 2 will total 1,236 MW upon completion. On June 30, 2001, Alabama Power Company transferred its interest in Harris to us. Both Harris 1 and Harris 2 began construction in June 2001 with an expected completion date of June 2003. Harris 1 and Harris 2 each have an expected summer peak output of 618 MW. Two additional units could be built at this site. Harris 1 and Harris 2 will each be comprised of two GE 7FA gas turbines, two Deltak triple pressure HRSGs, and an Alstom steam turbine. Dry low NOx burners are included in the gas turbines. Duct burners are provided for supplemental firing of the HRSGs to provide additional peaking capability. STANTON A Stanton A is a natural gas-fired combined-cycle generating facility in Orange County, Florida that will total 633 MW upon completion. Stanton A began construction in October 2001 with an expected completion date of October 2003. Stanton A is located within the existing Stanton Energy Center that is approximately 10 miles southeast of Orlando, Florida. Stanton Energy Center currently contains Stanton Units 1 and 2 that are existing coal-fired units owned by Orlando Utilities Commission that began operating commercially in 1987 and 1996, respectively. The Stanton Energy Center encompasses approximately 3,280 acres of land in eastern Orange County, Florida. Stanton A will be constructed on approximately 60 acres at the site. Stanton A will be comprised of two GE 7FA gas turbines, two Deltak triple pressure HRSGs, and an Alstom steam turbine. Dry low NOx burners are also included in the gas turbines. Duct burners are provided 36 for supplemental firing of the HRSGs to provide additional peaking capability. The gas turbines will be capable of burning both natural gas and No. 2 distillate oil. Stanton has an expected average annual capacity of 633 MW. We have a 65% interest in Stanton A through our wholly owned subsidiary Southern Company -- Florida LLC, a Delaware limited liability company authorized to do business in the State of Florida ("Southern Company -- Florida"). Stanton A is co-owned by Southern Company -- Florida, Orlando Utilities Commission ("OUC"), Florida Municipal Power Agency ("FMPA") and Kissimmee Utility Authority ("KUA") and each company's ownership interest is 65%, 28%, 3.5% and 3.5%, respectively. Each owner is entitled to the capacity and energy of Stanton A in proportion to its ownership interest. OUR PLANNED ELECTRIC GENERATING FACILITIES Our electric generating facilities that are planned but not yet under construction or are in the preliminary stages of construction are:
TOTAL FACILITY(1) LOCATION UNIT TYPE MW(2) IN-SERVICE DATE - ----------- -------- --------- ----- --------------- Franklin 3.............. Lee County, Alabama CC 615 June 2005 (scheduled) McIntosh 10 and McIntosh 11.................... Effingham County, Georgia CC 1,240 June 2005 (scheduled) ----- TOTAL................... 1,855 =====
- --------------- (1) Franklin 3, McIntosh 10 and McIntosh 11 are in advanced stages of development as of the date of this prospectus. The PPAs relating to McIntosh 10 and McIntosh 11 are still subject to regulatory approval. The PPAs for Franklin 3, McIntosh 10 and McIntosh 11 have not been incorporated into the projections set forth in the Independent Engineer's Report included as Annex A to this prospectus. (2) Total MW reflects designed output under rated conditions as specified by each facility's capacity test under its respective PPA. FRANKLIN 3 Franklin 3 will use a natural gas-fired combined-cycle block similar to Goat Rock 2. It will use two GE 7FA gas turbines, two Deltak triple pressure HRSGs and an Alstom steam turbine. Dry low NOx burners will also be included in the gas turbines. Duct burners will be provided for supplemental firing of the HRSGs to provide additional peaking capability. We anticipate to begin construction in the last half of 2002 with a scheduled completion date of June 2005. Franklin 3 has an expected capacity of 615 MW peak firing under summer conditions. Franklin 3 was previously known as Goat Rock 3. MCINTOSH 10 AND MCINTOSH 11 McIntosh 10 and McIntosh 11 will consist of two new combined-cycle units to be built adjacent to the existing Plant McIntosh Steam and Combustion Turbine Plant, located in Effingham County, Georgia near the city of Savannah, Georgia. McIntosh 10 and McIntosh 11 are expected to total 1,240 MW upon completion. Savannah Electric and Power Company owns a 165 MW coal unit and two combustion turbines located on this site. Georgia Power Company owns six combustion turbines currently located on this site. We anticipate to begin construction in the last half of 2002 with a scheduled completion date of June 2005. Each combined-cycle unit will include two GE 7FA gas turbines with dry low NOx burners, two Deltak triple pressure heat recovery steam generators, and an Alstom steam turbine. Duct burners are provided for supplemental firing of the heat recovery steam generators to provide additional capacity. The gas turbines are also capable of running with power augmentation, providing additional peaking capacity. Each unit's expected 37 capacity is 620 MW under summer peak conditions with supplemental firing and power augmentation. The gas turbines will be capable of burning both natural gas and No. 2 distillate oil. EXISTING AND APPROVED POWER PURCHASE AGREEMENTS As described in the table below, we have entered into PPAs for substantially all of the capacity of our operating and under construction generating facilities. To the extent necessary, PPAs have received all required regulatory approvals from the FERC and all appropriate state regulatory bodies. In addition, these PPAs have been incorporated into the projections set forth in the Independent Engineer's Report included in Annex A to this prospectus. All PPAs commence on each facility's in-service date, with the exception of Harris 2, for which there is a one-year lag and Franklin 1 and Franklin 2, for which there is a one-year lag on a portion of the output. We expect to enter into forward sales contracts and bilateral agreements during the lag periods. Our PPAs are with the PPA Counterparties. All of the PPA Counterparties are strong entities from either a credit or financial security perspective. Our PPAs with non-affiliated counterparties have a material adverse change clause that requires the posting of collateral or an acceptable substitute guarantee in the event that S&P or Moody's downgrades such counterparty to below investment grade. As a general matter, our existing PPAs provide that the PPA Counterparties are responsible for substantially all of the cost of fuel relating to the energy delivered under such PPA. To the extent a particular generating facility does not meet certain operational thresholds in a PPA, however, we may be responsible for a portion of the related fuel costs. With respect to fuel transportation risk, most of our PPAs provide that the PPA Counterparties are responsible for procuring and transporting the fuel to the particular generating facility. Fixed and variable O&M costs will be recovered either through capacity charges or other charges based on dollars per kilowatt year or dollars per megawatt hour. The PPAs give us the flexibility to supply power purchased from the Southern Pool or alternate sources rather than from our generating facilities if it is economical or otherwise desirable to do so. It is expected that the capacity payments in the PPAs will produce sufficient cash flow to pay debt service and provide an equity return. Most of our PPAs provide for fixed capacity sales from specific generating facilities. These obligations and counterparties are described below.
FACILITY COUNTERPARTY COUNTERPARTY RATING(1) MW(2) END DATE - -------- ------------ ---------------------- ------ -------- Dahlberg Units 1-7... LG&E Energy Marketing, Inc. A3/BBB+/BBB+ 578 12/31/04(4) Dahlberg Unit 8-10... Dynegy Power Caa2/B-/B 225 5/31/05(4) Wansley 6 and Georgia Power Company A2/A/A+ 934 12/31/09 Wansley 7............ Savannah Electric and Power Company A2/A/NR 200 12/31/09 Franklin 1........... Georgia Power Company A2/A/A+ 571(5) 5/31/10 Franklin 2........... Georgia Power Company A2/A/A+ 615(6) 5/31/11 Harris 1............. Alabama Power Company A2/A/A 618 5/31/10 Harris 2............. Georgia Power Company A2/A/A+ 618(7) 5/31/19 Stanton A............ OUC Aa1/AA/AA 329(8) 10/31/13 KUA A2/NR/A 41(8) 10/31/13 FMPA A1/A+/A+ 41(8) 10/31/13
- --------------- (1) Issuer and corporate rating of guarantor by Moody's/S&P/Fitch, except as described in footnote 3 below. (2) Total MW includes expected demonstrated capacity; the PPAs for the combined cycles allow for contracted capacity to be adjusted based upon actual capacity demonstrated. (3) These are ratings on the senior unsecured debt of Dynegy, Inc. which is the guarantor for the PPA associated with the Dahlberg Units 8-10. Because these ratings are below investment grade, pursuant to the PPA, Dynegy Power has provided us, as security for its obligations under the PPA, letters of credit 38 totaling $20 million expiring in February 2003. These letters of credit can be drawn if they are not replaced by acceptable security prior to expiration or if Dynegy Power defaults under the PPA. (4) Capacity available after these contracts expire may be used to meet capacity needs under Requirements Service Agreements with Georgia Electric Membership Corporations signed in 2002 (see "-- Requirements Agreements" below). (5) During the first year of expected operation 370 MW have been contracted for sale pursuant to this PPA, and most of the remaining capacity has been sold in the forward market. (6) During the first year of expected operation 400 MW have been contracted for sale pursuant to this PPA. (7) Contract does not begin until the second year of expected facility operation. (8) Beginning in the sixth year of these PPAs, the counterparties collectively have the right to elect to reduce the amount of combined capacity they are purchasing in 25 MW or 50 MW increments per year in each of the sixth through tenth years, subject to a maximum reduction of 200 MW. 2002 POWER PURCHASE AGREEMENTS AND REQUIREMENTS AGREEMENTS POWER PURCHASE AGREEMENTS During the first six months of 2002, we executed four additional PPAs whereby we will make capacity sales from our planned generating facilities. These sales obligations will begin in 2005. The McIntosh 10 and McIntosh 11 are still subject to regulatory approval. The Franklin 3, McIntosh 10 and McIntosh 11 PPAs have not been incorporated into projections set forth in the Independent Engineer's Report included as Annex A to this prospectus. These respective obligations and counterparties are described below:
COUNTERPARTY BEGINNING FACILITY COUNTERPARTY RATING(1) MW(2) DATE END DATE - -------- ------------ ------------ ------- --------- -------- Franklin 3(3)........ Dynegy Power and Dynegy Marketing & Trade(4) B3/B-/B(5) 615 6/1/05 5/31/30 McIntosh 10 and Georgia Power Company A2/A/A+ 1,040 6/1/05 5/31/19 McIntosh 11(6)....... Savannah Electric and Power Company A2/A/NR 200 6/1/05 5/31/19
- --------------- (1) Issuer and corporate rating of guarantor by Moody's/S&P/Fitch, except as described in footnote 5 below. (2) Total MW includes contracted capacity; the PPAs allow for contracted capacity to be adjusted based upon actual capacity demonstrated at completion. (3) We have the right to determine the generating resource to be used to supply capacity and energy under the new PPAs with Dynegy and named Franklin 3 as this resource. (4) Represents two PPAs. One between us and Dynegy Power and one among us, Dynegy Power and Dynegy Marketing & Trade. (5) The guarantor for these PPAs is Dynegy Holdings, Inc. These are ratings on the senior unsecured debt of Dynegy Holdings, Inc. As a result of the non-investment grade ratings of Dynegy Holdings, Inc.'s long-term senior unsecured indebtedness, Dynegy Power and Dynegy Marketing & Trade have provided us two one-year letters of credit totaling $50 million as security for their obligations. We can draw on the letters of credit in the event of (a) a default by Dynegy Power or Dynegy Marketing & Trade under the PPA or (b) Dynegy Power's or Dynegy Marketing & Trade's failure to renew the letters of credit 10 days prior to their expiration. The obligation to provide letters of credit becomes effective only if Dynegy Holdings, Inc. (or other guarantor) is rated: (i) below investment grade by S&P or Moody's or BBB- and on negative CreditWatch by S&P or Baa3 and on watch for possible downgrade by Moody's (if prior to January 1, 2006); or (ii) rated below investment grade by S&P or Moody's (if after December 31, 2005). (6) Capacity for the new Georgia Power Company and Savannah Electric and Power Company PPAs is expected to be provided from McIntosh 10 and McIntosh 11. 39 REQUIREMENTS AGREEMENTS Also during the first six months of 2002, we executed agreements to coordinate the existing generating resources and meet the load growth and resource-retirement capacity requirements ("Requirements Agreements") of eleven Georgia Electric Membership Corporations ("EMCs"). These Requirements Agreements are entered into pursuant to market-based tariff arrangements and are subject to filing and acceptance by the FERC. No state PSC approval is required. Under the terms of the agreements, both the loads and the resources of the EMCs will be integrated into the Southern Pool as obligations and resources of our company. We forecast that the EMCs' load growth will be approximately 5% per year which would require us to provide 200 MW beginning in 2005 and increasing to 1,300 MW by 2012. We will fulfill the load requirements of the EMCs by utilizing the EMCs' entitlements to capacity resources owned by Oglethorpe Power Corporation ("OPC") and other capacity purchase contracts. We will secure additional capacity resources to meet load growth as needed. This additional capacity may be supplied from our existing resources as the current PPAs terminate, future construction or capacity purchases. Initially, the additional capacity requirements of the EMCs are expected to be most efficiently served from peaking-type resources, which could be served utilizing Dahlberg, if available. In addition, we have effectively mitigated our fuel costs and fuel transportation risks as well as the fixed and variable O&M costs throughout the terms of the Requirements Agreements. The Requirements Agreements also have a material adverse change clause that requires the posting of collateral if (i) S&P or Moody's downgrades such counterparty to below investment grade, or (ii) if not rated, the counterparty does not meet a minimum interest coverage test. SOUTHERN COMPANY SERVICES MANAGEMENT OF CONSTRUCTION Under the terms of a services agreement, SCS will oversee the construction process and perform overall project management of each generating facility. SCS will perform overall project management of the construction process with internal resources. SCS contracts directly for site work, pilings, concrete/underground, general erection, buildings, tank erection and transformer yard construction. These contractors may also utilize subcontractors for portions of their work. In order to achieve economies of scale, most of our new energy generating facilities which we construct will utilize a standardized design. The power block areas for the various facilities will be similar in size and layout. This reduces costs related to engineering, procurement, construction, parts inventory and maintenance. FUEL PROCUREMENT FUEL SUPPLY As a general matter, our existing PPAs provide that the PPA Counterparties are responsible for substantially all of the cost of fuel relating to the energy delivered under such PPA. To the extent a particular generating facility does not meet certain operational thresholds in a PPA, however, we may be responsible for a portion of the related fuel costs. In addition, SCS has a 20-year master storage contract with Petal Gas Storage Company ("Petal") which will provide Dahlberg, Wansley 6 and Wansley 7, Franklin 1, Franklin 2, Franklin 3, Harris 1 and Harris 2 with natural gas capacity and withdrawal rights for up to ten days of emergency fuel should gas supply interruptions occur. FUEL TRANSPORTATION SCS has entered into fuel transportation agreements as agent for the Operating Companies for gas transportation service under the PPAs with the Operating Companies. Gas transportation service for Dahlberg is acquired on a seasonal or daily interruptible basis from existing Transcontinental Gas Pipeline ("Transco") pipeline capacity. Dahlberg has oil backup for gas supply interruptions. Franklin 1, Franklin 2, Harris 1 and Harris 2 will obtain fuel transportation through firm transportation agreements with Southern Natural Gas Company ("SNG"), a subsidiary of the El Paso Corporation. For Wansley 6 and Wansley 7, SCS has a firm 40 transportation agreement in place with Transco. Each of these firm transportation agreements has a term of fifteen years. OUC is responsible for arranging and acquiring all natural gas for Stanton A. In that regard, OUC has entered into a 20-year firm transportation agreement with Florida Gas Transmission Company for service to Stanton A. OPERATION AND MAINTENANCE As each new facility in an Operating Company service area enters into service, we intend for an Operating Company to provide O&M services at cost in accordance with the Holding Company Act. SCS may provide O&M services for facilities outside the Operating Companies' service territory. There will be an O&M contract between us and the appropriate Operating Company for the facilities located in such Operating Company's service territory, which has been approved by the SEC. SCS may provide certain services on behalf of the Operating Company. The O&M responsibilities for our operating or under construction generating facilities are as follows: Dahlberg.................................................... Georgia Power Company Wansley..................................................... Georgia Power Company Franklin 1 and Franklin 2................................... Georgia Power Company Harris 1 and Harris 2....................................... Alabama Power Company Stanton A................................................... SCS
In order to control O&M costs, we executed Long-Term Service Agreements ("LTSAs") with GE to cover the major maintenance of major GE equipment at each of the facilities. Under the LTSAs, GE provides a number of significant services, including the procurement of initial spares and specified parts, scheduled and unscheduled maintenance services and an on-site technical advisor. The LTSAs have a fixed major maintenance cost on the equipment. Payments for maintenance costs under the LTSAs will be levelized over a period of 96,000 fired operating hours even though accounting recognition of the costs will occur as the work is actually performed. Under each LTSA, all major maintenance will be performed at intervals that are consistent with the published recommendations of GE. Furthermore, the LTSAs will control our costs by providing predictable escalators and outage planning and management, reducing inventory and carrying cost associated with major parts, and by reducing maintenance staffing levels over the life of the agreements. We and the O&M provider will continue to be responsible for O&M for all equipment not manufactured by GE or not covered by the LTSA. TRANSMISSION AND INTERCONNECTION For each facility located in the service territory of an Operating Company, we will have an Interconnection Agreement with the applicable Operating Company to govern the interconnected operation of each facility with the transmission facilities of such Operating Company. The Interconnection Agreements are expected to have 40-year terms. Interconnection Agreements require approval by the FERC. We currently have Interconnection Agreements with Georgia Power Company for Dahlberg, Wansley, Franklin 1 and Franklin 2 that have been approved by the FERC. We have Interconnection Agreements with Alabama Power Company for Harris 1 and Harris 2 that have been approved by the FERC. We will also have an Interconnection Agreement with the applicable transmission provider for each facility located outside of the Operating Companies' service territory. For Stanton A there is an Interconnection Agreement with OUC. The FERC recently issued a notice of proposed rulemaking to standardize the interconnection process, terms and conditions of interconnection agreements and certain cost issues. Depending on when the FERC issues its final rule, the interconnection agreements for the other facilities may be subject to the new rule. The FERC currently requires the interconnecting generator to pay for the cost of any upgrades in the transmission network for reliability and stability purposes resulting from the interconnection; however, current FERC policy requires the transmitting utility with which the new generator is interconnected to provide a credit against the cost of future transmission service from the facility in the amount of such network upgrades for which the generator has paid. The SMD NOPR proposes circumstances where a separate charge for 41 transmission service may not be assessed because the generator has paid for all resulting network upgrades. In that instance (generally referred to as "participant funding"), the credit concept may prove to be inapplicable. Each Operating Company is interconnected with the transmission facilities of the other Operating Companies and Southern Electric Generating Company ("SEGCO"), a subsidiary of Alabama Power Company and Georgia Power Company, by means of high-voltage lines. Operating contracts set forth arrangements between the Operating Company and principal neighboring utility systems relating to capacity exchanges, capacity purchases and sales, transfers of energy and other similar transactions. Additionally, the Operating Companies have entered into voluntary reliability agreements with the subsidiaries of Entergy Corporation, Florida Electric Power Coordinating Group, Tennessee Valley Authority, Carolina Power & Light Company, Duke Energy Corporation, Southern Carolina Electric Gas Company and Virginia Electric and Power Company, each of which provides for the establishment and periodic review of principles and procedures for planning and operating generation and transmission facilities, maintenance schedules, load retention programs, emergency operations, and other matters affecting the reliability of bulk power supply. The Operating Companies have joined with other utilities in the Southeast (including those referred to above) to form the Southeast Electric Reliability Council ("SERC") to augment further the reliability and adequacy of bulk power supply. The Operating Companies are represented on the National Electric Reliability Council through SERC. In addition to interconnection of the generating facilities to the transmission systems of the Operating Companies and other non-affiliated utilities, transmission capacity over the applicable transmission system must be reserved so that the generator output can be delivered. All of our existing PPAs place this responsibility on the PPA Counterparty. In December 1999, the FERC issued its final rule on RTOs. The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. Southern has submitted a series of status reports informing the FERC of progress toward the development of a Southeastern RTO. In these status reports, Southern has explained that it is developing a for-profit RTO known as SeTrans with a number of non-jurisdictional cooperative and public power entities. In addition, the FERC jurisdictional entities of Entergy Corporation and Cleco Power recently joined the SeTrans development process. In January 2002, the sponsors of SeTrans held a public meeting to form a Stakeholder Advisory Committee, which will participate in the development of the RTO. On April 25, 2002, the Stakeholder Advisory Committee met and selected the candidates that will be considered for the SeTrans ISA. Southern continues to work with the sponsors to develop the SeTrans RTO. On June 27, 2002, Southern and the other SeTrans sponsors submitted a Petition for Declaratory Order seeking the FERC's guidance on various issues. The petition asks for a response from the FERC by October 2002. In July 2002, FERC issued its SMD NOPR which, among other things, (1) proposed to require an independent entity to operate the transmission facilities of jurisdictional entities (which may or may not be SeTrans) and (2) proposed a type of new transmission service and new mechanisms to handle transmission expansion and transmission congestion. INTERCOMPANY INTERCHANGE CONTRACT The Intercompany Interchange Contract ("IIC") among the Operating Companies and us is an arrangement on file with the FERC that provides for the coordinated operation of the Southern Pool. Participants in the Southern Pool enjoy economies of scale, share geographic load diversity and maintain lower reserve levels than would be required on a stand-along basis. The IIC provides that Southern Pool members share the benefits and obligations of pooled operation, including equalization of capacity reserves. Our PPAs constitute our load, and we are responsible for committing to the Southern Pool operations our integrated capacity resources (including appropriate reserves) installed to serve those PPAs. We are able to buy and sell temporary shortages or surpluses of energy, enjoy the benefit of shared reserves, and our supply obligations will be served out of the Southern Pool under economic dispatch. If we are unable to generate 42 sufficient energy to meet our obligations, we can buy power from the Southern Pool at the marginal energy cost. Under the IIC, a Southern Pool member has first call on its own generating resources, but if cheaper sources of generation are available on the system, a Southern Pool member has the right to purchase that lower variable cost energy to satisfy its higher, fixed-price obligations. The IIC has been approved by the FERC. REGULATION FEDERAL POWER ACT The Federal Power Act gives the FERC exclusive rate-making jurisdiction over wholesale sales of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to the FERC's jurisdiction are required to file rate schedules with the FERC with respect to wholesale sales or transmission of electricity. Because we sell power in the wholesale markets, we are deemed to be a public utility for purposes of the Federal Power Act and are required to obtain the FERC's acceptance of our rate schedules (e.g. PPAs) for wholesale sales of electricity. We have received authorization from the FERC to sell energy at market-based rates. Such authority to sell power at market-based rates contemplates pricing for wholesale energy sales based upon arms-length bargaining and market transactions, thereby permitting the opportunity to earn entrepreneurial returns and minimizing rate setting uncertainty and administrative cost. The FERC is also authorized to order refunds if it finds that market-based rates are unreasonable. The FERC is undertaking an industry-wide effort to reserve the right to suspend market-based rate authority on a retroactive basis if it is subsequently determined that we or any of our affiliates exercised market power. If the FERC were to suspend our market-based rate authority, it would likely be necessary to obtain the FERC's acceptance of rate schedules on a cost justified basis. In addition, the loss of market-based rate authority would subject us to the accounting, record-keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules. The nature of regulation of the electric power industry is such that changes in regulatory policies that affect us may occur. For example, in order to retain market-based rate authority, every three years an entity granted market-based rate authority must conduct analyses prescribed by the FERC to demonstrate that the utility does not have market power. As discussed under "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION -- FERC Matters", the FERC has indicated that it may revise these required analyses required to support market-based rate authority. The FERC's acceptance of many of our PPAs as market-based rate schedules is based upon these analyses demonstrating a lack of market power. If the analyses are changed, it may be more difficult to demonstrate a lack of market power in certain markets. We are required to submit quarterly reports to the FERC listing specific transactional data for sales from the prior quarter. Our market-based rate authority does not extend to wholesale sales to affiliates. To date, all such PPAs with the Operating Companies have resulted from our selection through a competitive bidding process supervised by the appropriate state PSCs. The FERC has accepted those PPAs as market-based transactions based upon its finding that the rates are competitive with those offered by competing suppliers. HOLDING COMPANY ACT We are subject to regulation under the Holding Company Act as a wholly owned subsidiary of Southern, which is a registered public utility holding company. Under the restrictions of the Holding Company Act, we cannot issue debt or equity securities or guarantees without the approval of the SEC. We currently have approval to issue up to an aggregate amount of $2.5 billion of commercial paper, preferred securities, long and short-term debt and other equity issuances. Southern currently has approval to fund our development and growth up to an aggregate amount not to exceed $1.7 billion. Under the Holding Company Act, generally, we can invest only in traditional electric and gas utility businesses and related businesses. Our investments in exempt wholesale generators and foreign utility companies, as defined in the Holding Company Act, are 43 limited by the authority granted to us for securities issuances and Southern's authority to fund our development and growth. The acquisition of the voting stock of other gas or electric utilities is subject to prior SEC approval. In addition, the Holding Company Act requires that all of a registered holding company's utility subsidiaries constitute a single system that can be operated in an efficient, coordinated manner. This does not extend, however, to exempt wholesale generators or foreign utilities companies which are excluded from the definition of an electric utility company and public utility company, respectively, under the Holding Company Act. The Holding Company Act also imposes restrictions on transactions among affiliates. STATE UTILITY REGULATION We will sell electric energy exclusively for resale in interstate commerce subject to regulation by the FERC. Therefore, state PSC will not have traditional utility-type regulatory authority over our rates. However, the respective state PSCs do have broad powers of supervision and regulation over the Operating Companies and, therefore, can oversee aspects of transactions between the Operating Companies and us. Georgia PSC approval is still required for the McIntosh 10 and McIntosh 11 PPAs executed in 2002, but the balance of the PPAs with the Operating Companies have been approved by the appropriate state PSC. Power generation construction and operation will be subject to state and local licensing and permitting laws, as well as environmental regulation. ENVIRONMENTAL REGULATION Our operations are subject to federal, state and local environmental requirements which, among other things, regulate air emissions, water discharges, and the management of hazardous and solid waste in order to adequately protect the environment. We expect to comply with such requirements, which generally are becoming increasingly stringent, through technical improvements, the use of appropriate fuels, addition of environmental control facilities, changes in control techniques and, if necessary, reduction of the operating levels of generating facilities. Clean Air Act programs such as Title IV (acid rain), attainment of the National Ambient Air Quality Standards for various non-attainment areas (to include Atlanta and Birmingham), the regional nitrogen oxide "SIP Call" intended to reduce nitrogen oxide emissions in certain regions of the Southeastern and Midwestern United States, control strategies to reduce regional haze, Compliance Assurance Monitoring, and the development of an emissions control program for Hazardous Air Pollutants all are in various stages of development and/or implementation by both the regulatory agencies and the regulated community. Depending upon the location of our generating facilities and the stage of development of implementation of these Clean Air Act requirements, it is possible that these and other environmental compliance requirements could result in high costs to us. To a large extent, the final cost of these programs will not be able to be determined until the results of legal challenges to these program are known and/or state regulations implementing the programs are developed. The EPA and state environmental regulatory agencies are also reviewing and evaluating various other matters including: limits on pollutant discharges to impaired waters; cooling water intake restrictions; and hazardous waste disposal requirements. The impact of any new standards will depend on the development and implementation of applicable regulations. Several major pieces of environmental legislation are periodically considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation and Liability Act; and the Endangered Species Act. Changes to these laws could affect many areas of our operations. Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect us. The impact of new legislation, if any, will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as a result of lawsuits alleging personal injury and property damages caused by potential impacts of electricity generation activities such as air pollution emissions, water pollution discharges or the presence of electric and magnetic fields. 44 We are unable to predict at this time what additional steps we may be required to take as a result of the implementation of existing or future control requirements for air, water and hazardous or toxic materials, but such steps could adversely affect operations and result in substantial additional costs. Failure to comply with such requirements could result in the complete shutdown of individual facilities not in compliance as well as the imposition of civil and criminal penalties. EMPLOYEES Currently, we do not have any employees. Employees of SCS, in coordination with our management who are also employees of SCS, currently run our day-to-day operations. LITIGATION Although we are not currently involved in any litigation, from time to time, we may be a party to various legal proceedings that arise in the ordinary course of business. For a discussion of a mediation proceeding involving us and a former contractor and the resolution of such matter, please see Note 10 to our financial statements as of December 31, 2001 under "Contingencies" and Note M to our condensed consolidated financial statements as of June 30, 2002. SUMMARY OF INDEPENDENT CONSULTANTS' REPORTS In the preparation of the Independent Engineer's Report, the Independent Market Expert's Report and the opinions contained in the reports, the Independent Engineer and the Independent Market Expert have made the following qualifications about the information contained in their reports and the circumstances under which the reports were prepared: some information in the reports is necessarily based on predictions and estimates of future events and behaviors; such predictions or estimates may differ from that which other consultants specializing in the electricity industry might present; actual results may differ, perhaps materially, from those projected; the provision of the reports does not eliminate the need for you to make further inquiries as to the information included in the reports or to undertake your own analysis; the reports are not intended to be a complete and exhaustive analysis of the subject issues, and therefore may not consider some factors that are important to your decision; and nothing in the reports should be taken as a promise or guarantee as to the occurrence of any future events. The Independent Engineer's Report and the Independent Market Expert's Report rely on assumptions regarding material contingencies and other matters that are not within our control or the control of Beck or PA Consulting or any other person. While each of Beck and PA Consulting believes its assumptions to be reasonable for purposes of preparing its respective report, these assumptions are inherently subject to significant uncertainties and actual results may differ materially from those projected. The predictions, estimates and assumptions that underlie these reports may also differ from those that other consultants specializing in the electric power industry might present. SUMMARY OF THE INDEPENDENT ENGINEER'S REPORT The Independent Engineer has prepared the Independent Engineer's Report dated June 13, 2002 a copy of which is attached as Annex A to this prospectus. Following is a summary of the conclusions reached by the Independent Engineer in the Independent Engineer's Report. The Independent Engineer's conclusions are subject to the assumptions and qualifications set forth in the Independent Engineer's Report, and you should read this summary in conjunction with the full text of the Independent Engineer's Report. All capitalized terms in this summary are defined in the attached Independent Engineer's Report. The Independent Engineer has expressed the following opinions in the Independent Engineer's Report: 1. Provided Southern Power takes into account the recommendations in the geotechnical reports by Southern Geotech, the sites for the Generating Facilities are suitable for the construction and operation of the Generating Facilities. 45 2. Based on GE's previously demonstrated capability to address the issues similar to those related to the Frame 7FA described herein, the power generation technologies proposed for the Generating Facilities are sound, proven methods of energy recovery. If constructed, operated and maintained as proposed by Southern Power, the Generating Facilities should be capable of meeting the requirements of the Power Purchase Agreements and the currently applicable environmental permit requirements. Furthermore, all off-site requirements of the Generating Facilities have been adequately provided for, including fuel supply, water supply, wastewater disposal, and electrical interconnection. 3. The proposed method of design, construction, operation, and maintenance of the Generating Facilities has been developed in accordance with generally accepted industry practice and has taken into consideration the current environmental, license and permit requirements that the Generating Facilities must meet. 4. Based on Beck's review and provided that: (a) the units are operated and maintained by the operators in accordance with the policies and procedures as presented by Southern Power, (b) all required renewals and replacements are made on a timely basis as the units age, and (c) gas and oil burned by the units are within the expected range with respect to quantity and quality, the Generating Facilities should have useful lives of at least 20 years. 5. The performance guarantees proposed for the Generating Facilities under construction, if all the equipment contract guarantees are considered in their entirety, are similar to the performance tests of turnkey projects with which Beck is familiar. 6. The Generating Facilities should be capable of achieving the annual average output in full-pressure mode with power augmentation and the average annual net plant heat rates assumed in the Projected Operating Results. 7. The Generating Facilities should be capable of achieving the required average annual contract availabilities under the Power Purchase Agreements ranging from 96.5 to 97 percent, which exclude scheduled maintenance and allow Southern Power to replace the undelivered energy from another resource, and should also be capable of achieving an average annual availability of 92 percent, which includes provision for forced and scheduled maintenance. 8. The environmental site assessments performed by TTL, URS, ECT, and Williams related to the sites of the Generating Facilities were conducted in a manner consistent with industry standards, using comparable industry protocols for similar studies with which Beck is familiar. 9. Southern Power has identified the major permits and approvals necessary for the construction and operation of the Generating Facilities. While all of the required permits and approvals have not yet been obtained, Beck did not identify any technical or engineering circumstance that would prevent the issuance of the remaining permits and approvals. 10. Southern Power's estimates of the costs of operating and maintaining the Generating Facilities, including provision for major maintenance, are within the range of the costs of similar plants with which Beck is familiar. 11. For the Base Case Projected Operating Results, the projected revenues from the sale of electricity are adequate to pay annual operating and maintenance expenses (including major maintenance), fuel expense, and other operating expenses. Such revenues provide an annual interest coverage on the Debt of at least 3.28 times the annual interest requirement in each year during the term of the Notes and a weighted average coverage of 3.61 times the annual interest requirement on the Debt over the term of the Notes. There is insufficient cash available after the payment of interest to repay the entire principal due on the Debt upon maturity. Southern Power has assumed that the Debt will be refinanced upon maturity. 46 SUMMARY OF THE INDEPENDENT MARKET EXPERT'S REPORT PA Consulting Group, Inc. ("PA Consulting"), the independent market consultant, has prepared an Independent Market Expert's Report dated June 5, 2002, a copy of which is attached as Annex B to this prospectus. Southern Power owns or has ownership interests in companies with 4,777 MW of generation capacity. 4,366 MW are in the Southeastern Electric Reliability Council ("SERC") market and 411 MW are in the Florida Reliability Coordinating Council ("FRCC") market. Some information in the report is necessarily based on predictions and estimates of future events and behaviors, such predictions or estimates may differ from that which other consultants specializing in the electricity industry might present, the provision of a report by PA Consulting does not obviate the need for potential investors to make further appropriate inquiries as to the accuracy of the information included therein, or to undertake an analysis of their own. The report is not intended to be a complete and exhaustive analysis of the subject issues and therefore will not consider some factors that are important to a potential investor's decision making. PA Consulting and its employees cannot accept liability for loss suffered in consequence of reliance on the Market Expert's Report. Nothing in PA Consulting's report should be taken as a promise or guarantee as to the occurrence of any future events. Market Description Over the past two decades, the structure of the electric power industry has been increasingly shaped by the emergence of a prevailing market trend in the networked industries, namely the introduction of competition in formerly regulated markets. The SERC and FRCC markets are both bilateral markets, whereby seller and purchasers come together via contracts for the delivery of capacity and/or energy and the associated ancillary services. Forecasting Methodology The following is PA Consulting's description of its forecasting methodology. PA Consulting has developed a proprietary approach to market valuation and price forecasting. This market valuation process (MVP) applies best practice forecasting principles and leverages deep insight into energy market dynamics to deliver sound independent results. PA Consulting's proprietary Merchant Generation Database serves as the backbone of this process by ensuring that PA Consulting's opinion is supported by an accurate view of the ever-changing merchant energy market landscape. For this study, PA Consulting utilized a 4 step process: 1. Review market characteristics. 2. Establish market assumptions. 3. Complete baseline fundamental analysis results in overall market projections. 4. Dispatch the plants against the prices developed in the fundamental model. Key Assumptions There are many important assumptions in the development of the price projections, including but not limited to demand growth, fuel prices, and capacity additions and retirements. Variations in these three factors, as well as other assumptions, can lead to significant variations in the end price results. PA Consulting has tested the forecasts for variations of these three assumptions, which represent the high fuel, low fuel, and overbuild sensitivity cases. Another key fundamental assumption on which this analysis is based is the concept of a competitive wholesale market. These results are based on the assumptions that rational markets for electricity exist, that markets are attempting to adjust to economic equilibrium, and that market players make decisions based on sound economic judgment. 47 Results and Sensitivities PA Consulting developed three sensitivity cases. These sensitivity cases are intended to provide an indication as to how changes in certain input parameters such as fuel prices and new capacity additions affect forecasted price results. These sensitivities are not intended to be bounding, or worst case scenarios. Their purpose is to determine the impact of an assumed change on the price forecast results. The magnitude of the changes in input parameters may be greater than or less than those assumed in the sensitivities. The three sensitivity cases evaluated are as follows: - The low fuel case evaluates the effects of lower gas and oil prices represented as a $0.50/MMBtu reduction in the 2002 consensus gas and oil prices with escalation remaining unchanged (coal prices are not changed). - The high fuel case evaluates the effects of higher gas and oil prices represented as a $0.50/MMBtu increase in the 2002 gas and oil prices with escalation remaining unchanged (coal prices are not changed). - The overbuild case evaluates an over-exuberance of merchant plant development in the regions reviewed. In addition to the base case merchant capacity, the overbuild case assumes that additional capacity is constructed. 48 OUR MANAGEMENT Our directors and executive officers and their ages are as follows:
NAME AGE POSITION - ---- --- -------- W. Paul Bowers............................ 45 President, Chief Executive Officer and Director H. Allen Franklin......................... 57 Director Gale E. Klappa............................ 51 Director Charles D. McCrary........................ 50 Director David M. Ratcliffe........................ 53 Director Robert G. Moore........................... 52 Senior Vice President Cliff S. Thrasher......................... 52 Vice President, Comptroller and Chief Financial Officer Anthony J. Topazi......................... 51 Vice President
Currently, some of our directors and executive officers are also directors and officers of Southern or one of its subsidiaries other than Southern Power Company. W. Paul Bowers -- President, Chief Executive Officer and Director since May 2001; Executive Vice President of SCS since May 2001. Previously served as Senior Vice President of SCS and Chief Marketing Officer of Southern from March 2000 to May 2001; President and Chief Executive Officer of Western Power Distribution, a subsidiary of Mirant Corporation ("Mirant") located in Bristol, England from December 1998 to 2000; and Senior Vice President of Retail Marketing for Georgia Power Company from 1995 to 1998. H. Allen Franklin -- Director since January 2001; Chairman, President and Chief Executive Officer of Southern since April 2001. Previously served as President and Chief Executive Officer from March 2001 to April 2001; President and Chief Operating Officer of Southern from June 1999 to March 2001; and Executive Vice President of Southern and President and Chief Executive Officer of Georgia Power Company from January 1994 to June 1999. Mr. Franklin is a director of SouthTrust Corporation, Vulcan Materials Company, and Southern System companies -- Southern, Alabama Power Company, Georgia Power Company and Gulf Power Company. Gale E. Klappa -- Director since May 2001; Executive Vice President; Chief Financial Officer and Treasurer of Southern since May 2001. Previously served as Financial Vice President, Chief Financial Officer and Treasurer of Southern from March 2001 to May 2001; Senior Vice President and Chief Strategic Officer of Southern from October 1999 to March 2001; President of Mirant's North America Group and Senior Vice President of Mirant from December 1998 to October 1999; and President and Chief Executive Officer of Western Power Distribution, a subsidiary of Mirant located in Bristol, England, from September 1995 to December 1998. Charles D. McCrary -- Director since January 2001; Executive Vice President of Southern since February 2002 and President and Chief Executive Officer of Alabama Power Company since January 2002. Previously served as President and Chief Operating Officer of Alabama Power Company from May 2001 to October 2001; Vice President of Southern from February 1998 to April 2001; and Executive Vice President of Alabama Power Company from April 1994 to February 1998. Mr. McCrary is a director of AmSouth Banccorporation and Alabama Power Company. David M. Ratcliffe -- Director since January 2001; Executive Vice President of Southern since 1999 and President and Chief Executive Officer of Georgia Power Company since June 1999. Previously served as Executive Vice President, Treasurer and Chief Financial Officer of Georgia Power Company from March 1998 to June 1999; and Senior Vice President of Southern from March 1995 to March 1998. Mr. Ratcliffe is a director of Mississippi Chemical Company and Georgia Power Company. Robert G. Moore -- Senior Vice President since January 2002; Vice President of Gulf Power Company since July 1997; and Vice President of Fossil Generation of SCS since July 1998. Previously served as Plant Manager of Plant Bowen at Georgia Power Company from March 1993 to August 1997. 49 Cliff S. Thrasher -- Vice President, Comptroller and Chief Financial Officer since June 2002; Vice President of SCS since June 2002; Vice President, Comptroller and Chief Accounting Officer of Georgia Power Company since September 1995. Anthony J. Topazi -- Vice President since March 2001; Vice President of SCS since December 1999. Previously served as Vice President of Alabama Power Company from April 1995 to December 1999. EXECUTIVE COMPENSATION EMPLOYMENT, CHANGE IN CONTROL, AND SEPARATION AGREEMENTS Our officers are employees of SCS. As a result, the Southern Company Executive Change in Control Severance Plan, is applicable to certain of our officers. We have entered into an individual Change in Control Agreement with Mr. Bowers. If an executive officer is involuntarily terminated, other than for cause, within two years following a change in control of our company, the agreements provide for: - lump sum payment of two or three times annual compensation, - up to five years' coverage under group health and life insurance plans, - immediate vesting of all stock options previously granted, - payment of any accrued long-term and short-term bonuses and dividend equivalents, and - payment of any excise tax liability incurred as a result of payments made under the agreement. A change in control is defined under the agreements as: - acquisition of at least 20 percent of Southern's stock, - a change in the majority of the members of Southern's Board of Directors, - a merger or other business combination that results in Southern's stockholders immediately before the merger owning less than 65 percent of the voting power after the merger, or - a sale of substantially all the assets of Southern. If a change in control affects only a subsidiary of Southern, these payments would only be made to executives of the affected subsidiary who are involuntarily terminated as a result of that change in control. 50 SUMMARY COMPENSATION TABLE This table shows information concerning our executive officers serving during 2001.(1)
LONG-TERM COMPENSATION ------------- ANNUAL COMPENSATION NUMBER OF -------------------------------- SECURITIES OTHER ANNUAL UNDERLYING ALL OTHER NAME AND PRINCIPAL SALARY BONUS COMPENSATION STOCK OPTIONS COMPENSATION POSITION YEAR ($) ($) ($) (#) ($)(2) - ------------------ ---- ------- ------- ------------ ------------- ------------ W. Paul Bowers................... 2001 273,758 273,630 3,072 51,740 39,542 President & Chief Executive Officer Carson B. Harreld Jr.(3)......... 2001 204,132 123,944 811 47,616 110,053 Vice President, Comptroller & Chief Financial Officer Robert G. Moore.................. 2001 189,095 146,694 10,253 31,589 27,965 Senior Vice President Anthony J. Topazi................ 2001 237,095 185,293 112,839 49,800 213,144 Vice President Cliff S. Thrasher(4)............. 2001 171,357 128,636 1,807 32,665 8,559 Vice President, Comptroller and Chief Financial Officer
- --------------- (1) This table reports compensation of the named executives for all of 2001, our first fiscal year. (2) Contributions in 2001 to the Employee Savings Plan and Employee Stock Ownership Plan, non-pension related accruals under the Supplemental Benefit Plan, and tax sharing benefits paid to participants who elected receipt of dividends on Southern common stock held in the Employee Savings Plan are provided in the following table:
ESP TAX SHARING BENEFIT ESP($) ESOP($) SBP($) ------- ------ ------- ------ W. Paul Bowers..................................... -- 5,598 764 8,440 Carson B. Harreld Jr............................... 1,053 6,600 -- 2,400 Robert G. Moore.................................... 2,939 6,853 764 2,409 Anthony J. Topazi.................................. 748 6,853 764 4,779 Cliff S. Thrasher.................................. -- 6,646 764 1,149
This amount also includes additional incentive compensation for Messers. Bowers, Harreld, Moore and Topazi of $24,380, $100,000, $15,000 and $200,000, respectively. (3) Mr. Harreld was an executive officer of our company on December 31, 2001; however, he has not served as an executive officer since June 9, 2002. On May 28, 2002, he was elected Senior Vice President of SCS. (4) During 2001, Mr. Thrasher served as Vice President, Comptroller and Chief Accounting Officer of Georgia Power Company. 51 STOCK OPTION GRANTS IN 2001
INDIVIDUAL GRANTS --------------------------------------------------------- NUMBER OF SECURITIES PERCENT OF TOTAL GRANT UNDERLYING OPTIONS GRANTED EXERCISE OF DATE OPTIONS TO EMPLOYEES IN BASE PRICE EXPIRATION PRESENT NAME GRANTED(1) FISCAL YEAR(2) ($/SH)(1) DATE(1) VALUE($)(3) - ---- ----------- ---------------- ----------- ---------- ----------- W. Paul Bowers................... 25,561 .19 19.08 2/16/2011 135,491 26,179 .19 22.43 4/16/2011 138,749 Carson B. Harreld Jr. ........... 20,968 .15 19.08 2/16/2011 111,145 26,648 .20 22.43 4/16/2011 141,253 Robert G. Moore.................. 16,640 .12 19.08 2/16/2011 88,192 14,949 .11 22.43 4/16/2011 79,230 Anthony J. Topazi................ 25,077 .18 19.08 2/16/2011 132,908 24,723 .18 22.43 4/16/2011 131,032 Cliff S. Thrasher................ 15,880 .12 19.08 2/16/2011 84,164 16,785 .12 22.43 4/16/2011 88,961
- --------------- (1) Southern stock option grants were made on February 16, 2001 and April 16, 2001, and vest annually at a rate of one-third on the anniversary date of the grant. Grants fully vest upon termination as a result of death, total disability, or retirement and expire five years after retirement, three years after death or total disability, or their normal expiration date if earlier. Exercise price is the average of the high and low price of Southern's common stock on the date granted. Options may be transferred to certain family members, family trusts, and family limited partnerships. The number of options granted on February 16, 2001, and the exercise price thereof were adjusted after the spin off of Mirant Corporation under the anti-dilution provisions of the plan such that the options had the same aggregate intrinsic value on the day of the spin off as the day before. (2) A total of 13,623,507 stock options were granted in 2001 by Southern. (3) Value was calculated using the Black-Scholes option valuation model. The actual value, if any, ultimately realized depends on the market value of Southern's common stock at a future date. Significant assumptions are shown below:
DISCOUNT FOR FORFEITURE RISK: ----------------------------- GRANT RISK-FREE RATE DIVIDEND BEFORE BEFORE DATE VOLATILITY OF RETURN OPPORTUNITY TERM VESTING EXPIRATION ----- ---------- -------------- ----------- ---- ---------------- ---------- 2/16/2001 27.34% 5.10% 50% 10 7.79% 12.45% 4/16/2001 26.11% 5.14% 50% 10 7.79% 11.77%
These assumptions reflect the effects of cash dividend equivalents paid to participants under the Omnibus Incentive Compensation Plan assuming targets are met. AGGREGATED OPTION EXERCISES IN 2001 AND YEAR-END OPTION VALUES
NUMBER OF SECURITIES VALUE OF UNEXERCISED UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS AT NUMBER OF VALUE OPTIONS AT YEAR-END(#) YEAR-END($)(2) SHARES ACQUIRED REALIZED --------------------------- --------------------------- NAME ON EXERCISE(#) ($)(1) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE - ---- --------------- -------- ----------- ------------- ----------- ------------- W. Paul Bowers........ 10,570 104,401 45,004 74,783 459,597 475,106 Carson B. Harreld Jr. ................ 20,377 193,681 19,037 44,326 97,010 266,720 Robert G. Moore....... Not exercised -- 28,209 48,274 279,385 319,857 Anthony J. Topazi..... 15,703 173,654 35,825 72,517 355,546 464,810 Cliff S. Thrasher..... 13,532 124,580 124,972 44,569 248,099 270,379
52 - --------------- (1) The "Value Realized" is ordinary income, before taxes, and represents the amount equal to the excess of the fair market value of the shares at the time of exercise above the exercise price. (2) These columns represent the excess of the fair market value of Southern's common stock of $25.35 per share, as of December 31, 2001, above the exercise price of the options. The amounts under the Exercisable column report the "value" of options that are vested and therefore could be exercised. The Unexercisable column reports the "value" of options that are not vested and therefore could not be exercised as of December 31, 2001. PENSION PLAN TABLE YEARS OF ACCREDITED SERVICE
COMPENSATION 15 20 25 30 35 40 45 - ------------ -------- -------- -------- -------- -------- -------- -------- $100,000 $ 25,500 $ 34,000 $ 42,500 $ 51,000 $ 59,500 $ 68,000 $ 76,500 300,000 76,500 102,000 127,500 153,000 178,500 204,000 229,500 500,000 127,500 170,000 212,500 255,000 297,500 340,000 382,500 700,000 178,500 238,000 297,500 357,000 416,500 476,000 535,500 900,000 229,500 306,000 382,500 459,000 535,500 612,000 688,500
This table shows the estimated annual pension benefits payable at normal retirement age under Southern's qualified Pension Plan, as well as non-qualified supplemental benefits, based on the stated compensation and years of service with Southern's subsidiaries. Compensation for pension purposes is limited to the average of the highest three of the final 10 years' compensation. Compensation is base salary plus the excess of annual incentive compensation over 15 percent of base salary. These compensation components are reported under the columns titled "Salary" and "Bonus" in the Summary Compensation Table on page . As of December 31, 2001, the applicable compensation levels and accredited service for determination of pension benefits would have been:
ACCREDITED COMPENSATION SERVICE ------------ ---------- W. Paul Bowers.............................................. 414,907 22 Carson B. Harreld Jr.(1) ................................... 320,484 28 Robert G. Moore............................................. 287,068 28 Anthony J. Topazi........................................... 355,864 31 Cliff S. Thrasher........................................... 254,256 30
The amounts shown in the table were calculated according to the final average pay formula and are based on a single life annuity without reduction for joint and survivor annuities or computation of Social Security offset that would apply in most cases. (1) The number of years of accredited service includes 10 years credited to Mr. Harreld pursuant to a supplemental pension agreement. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPANTS We do not have a compensation committee and there is no other committee of the board that performs similar functions. The Compensation and Management Succession Committee of the Southern board considered compensation matters with respect to our executive officers. None of our executive officers serve on the boards of other Southern subsidiaries whose executive officers serve on our board. 53 DIRECTOR COMPENSATION The members of the board are officers of SCS or other subsidiaries of Southern, and they do not receive any compensation for serving on our board. STOCK OWNERSHIP TABLE This table shows the number of shares of Southern's common stock owned by directors, nominees, and executive officers as of June 30, 2002. The shares owned by all directors, nominees, and executive officers as a group constitute less than one percent of the total number of shares of the class. The number of shares of Southern common stock outstanding as of June 30, 2002 was 708,105,837.
SHARES BENEFICIALLY OWNED INCLUDE: -------------- SHARES INDIVIDUALS SHARES HAVE RIGHTS TO BENEFICIALLY ACQUIRE WITHIN TITLE OF SECURITY OWNED(1) 60 DAYS(2) --------------------- ------------ -------------- W. Paul Bowers............................... Southern Common Stock 66,537 60,083 H. Allen Franklin............................ Southern Common Stock 476,036 437,551 Gale E. Klappa............................... Southern Common Stock 116,511 92,620 Charles D. McCrary........................... Southern Common Stock 130,991 128,028 Robert G. Moore.............................. Southern Common Stock 44,454 30,295 David M. Ratcliffe........................... Southern Common Stock 163,082 151,025 Cliff S. Thrasher............................ Southern Common Stock 20,625 16,115 Anthony J. Topazi............................ Southern Common Stock 70,265 57,009 Directors, Nominees, and Executive Officers Southern Common Stock 1,088,501 972,726 as a Group (8 people)......................
- --------------- (1) "Beneficial ownership" means the sole or shared power to vote, or to direct the voting of, a security, or investment power with respect to a security, or any combination thereof. (2) Indicates shares of Southern's common stock that directors and executive officers have the right to acquire within 60 days. Shares indicated are included in the Shares Beneficially Owned column. THE OPERATING COMPANIES The Operating Companies consist of Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company and Savannah Electric and Power Company, each of which is an operating public utility company and a wholly owned subsidiary of Southern. Alabama Power Company is engaged, within the State of Alabama, in the generation and purchase of electricity and the distribution and sale of such electricity at retail in over 1,000 communities and at wholesale to 15 municipally owned electric distribution systems and two rural distributing cooperative associations. Alabama Power Company serves 1.3 million homes, businesses and industries in the southern two-thirds of Alabama. More than 78,000 miles of power lines carry electricity to customers throughout 44,500 square miles. Georgia Power Company is engaged in the generation and purchase of electric energy and the distribution and sale of such electricity within the State of Georgia at retail in over 600 communities, as well as in rural areas, and at wholesale currently to 39 rural cooperative associations and to 50 municipalities. Georgia Power Company serves customers in 57,000 of the state's 59,000 square miles. Georgia Power Company's 1.8 million customers are in all but six of Georgia's 159 counties. 54 Gulf Power Company is engaged in the generation and purchase of electricity and the distribution and sale of such electricity in Northwest Florida at retail to more than 373,000 customers directly and 13,000 indirectly through a nonaffiliated utility and a municipality. Gulf Power Company maintains 139 substations, 1,562 miles of transmission lines and 6,673 miles of distribution lines. Mississippi Power Company is engaged in the generation and purchase of electricity and the distribution and sale of such energy to more than 191,000 customers in 23 counties in Southeastern Mississippi, at retail in 123 communities, as well as in rural areas, and at wholesale to one municipality, six rural electric distribution cooperative associations and one generating and transmitting cooperative. To deliver electricity to its customers, Mississippi Power Company maintains 157 substations, more than 2,080 miles of transmission lines, 6,854 miles of primary overhead lines, and 390 miles of primary underground lines. Savannah Electric and Power Company is engaged in the generation and purchase of electricity and the distribution and sale of electricity at retail and the transmission and sale of wholesale energy. Savannah Electric and Power Company has approximately 250,000 customers in a five-county, 2,000 square-mile region in Eastern Georgia, including the City of Savannah and its surrounding area. Savannah Electric and Power Company maintains 89 substations, 457 miles of transmission lines and 3,243 miles of distribution lines. Alabama Power Company and Georgia Power Company each own 50% of the outstanding stock of Southern Electric Generating Company ("SEGCO"). SEGCO owns electric generating units near Wilsonville, Alabama with an aggregate capacity of approximately 1,020 megawatts. Alabama Power Company and Georgia Power Company are each entitled to one-half of SEGCO's capacity and energy. 55 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS TRANSFER OF ASSETS Substantially all of our operating or under construction generating facilities were transferred from the Operating Companies. The Dahlberg units were transferred to us from Georgia Power Company in July 2001. In connection with such transfer, the PPAs with LEM and Dynegy Power for Dahlberg were assigned to us. In June 2001, Alabama Power Company transferred the Harris plant site and assigned the related vendor contracts to us. Alabama Power Company also transferred its interest in the Goat Rock site (which was subsequently renamed the Franklin site) to us at that time. In July 2001, Georgia Power Company transferred Dahlberg to us and assigned us three related PPAs with non-affiliated entities. In November 2001, Georgia Power Company transferred to us its interests in the Franklin site, including land and construction work in progress and assigned us the related vendor contracts. In January 2002, Georgia Power Company transferred the construction work in progress for Wansley 6 and 7 to us. See Notes B and I to our condensed consolidated financial statements and Note 2 to our consolidated financial statements herein for additional information related to these asset transfers. Certain keep-well agreements were created to facilitate the assignment of specific partially executory vendor contracts to our company. As of June 30, 2002, Southern keep-well agreements were in place to facilitate the transfer of specific vendor contracts from Alabama Power Company to our company related to the Harris construction. Southern keep-wells are also in place for the transfer of specific vendor contracts from Georgia Power Company to the company for the operation of Dahlberg and construction at the Franklin and Stanton sites. As of June 30, 2002, the keep-well agreements have estimated values of $2 million for the Alabama Power Company contracts and $32.6 million related to the Georgia Power Company contracts. POWER PURCHASE AGREEMENTS Several of the Operating Companies are parties to PPAs with us. See "OUR BUSINESS -- Existing and Approved Power Purchase Agreements" and "-- Power Purchase Agreements and Requirements Agreements Subject to Approval." SERVICES AGREEMENTS We have signed a services agreement with SCS to provide administrative services, including project management of the construction process for each of our generating facilities. See "OUR BUSINESS -- Southern Company Services Management of Construction." As each new facility is placed into commercial operation in an Operating Company's service territory, such Operating Company will provide O&M services at cost under the terms of an O&M contract. SCS may provide O&M services for facilities outside of the Operating Companies' service territory similar to that provided for Stanton A. See "OUR BUSINESS -- Operation and Maintenance." INTERCONNECTION AGREEMENTS For each new generating facility, we will have an Interconnection Agreement with the applicable transmission provider. See "OUR BUSINESS -- Transmission and Interconnection." Southern has guaranteed our obligations to Alabama under Interconnection Agreements for Franklin 1, Franklin 2, Harris 1, Harris 2, Wansley 6, Wansley 7 and the aggregate amount of these guarantees is $13.4 million. INTERCOMPANY INTERCHANGE CONTRACT As a member of the Southern Pool, we are a party to the IIC and share in the benefits and obligations of that arrangement. See "OUR BUSINESS -- Intercompany Interchange Contract." 56 CAPITAL CONTRIBUTIONS, SUBORDINATED LOANS AND GUARANTEES The total capital contributions and subordinated loans to us from Southern were $894 million as of June 30, 2002. We have not paid any dividends to Southern since the date of our incorporation. Additionally, Southern has (i) guaranteed certain obligations of Southern Power-Florida under the PPAs related to Stanton and (ii) executed the Completion Guarantee in connection with our Credit Facility. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- LIQUIDITY AND CAPITAL RESOURCES." TAX SHARING AGREEMENT We file a consolidated federal tax return with Southern and Southern's subsidiaries. The consolidated tax liability is allocated among the parties in accordance with an Income Tax Allocation Agreement. The agreement provides an equitable method for determining the share of each party's consolidated federal tax burdens and benefits to be attributed to each party. OTHER KEEP-WELL ARRANGEMENTS Certain other keep-well arrangements were entered into in order to enhance the efficiency and flexibility of the energy sales and related natural gas procurements function. Acting as agent for the Operating Companies and our company under agency agreements ("Agreements"), SCS may enter into various types of wholesale energy and natural gas contracts. Under such Agreements, each of the Operating Companies may be jointly and severally liable for the obligations of each of the other Operating Companies and us. In that regard, the creditworthiness of our company is currently inferior to the creditworthiness of the other Operating Companies. To insure that such other Operating Companies will not subsidize or be responsible for any costs, losses, liabilities or damages arising out of or resulting from our company's inclusion as a contracting party under the Agreements, Southern has entered into a keep-well agreement with each of the other Operating Companies. 57 THE EXCHANGE OFFER PURPOSE AND EFFECT OF THE EXCHANGE OFFER We sold the Original Senior Notes on June 18, 2002 to the initial purchasers with further distribution permitted only to (i) "qualified institutional buyers" under Rule 144A under the Securities Act, (ii) "institutional accredited investors" under Rule 501(a)(1), (2), (3) or (7) under the Securities Act and (iii) non-U.S. persons in offshore transactions in reliance on Regulation S under the Securities Act. In connection with the sale of the Original Senior Notes, we and the initial purchasers entered into a Registration Rights Agreement, dated June 18, 2002, which requires us to use our best efforts to consummate a registered offer to exchange the Original Senior Notes for Exchange Senior Notes, identical in all material respects to the Original Senior Notes except for certain transfer restrictions and registration rights related to the outstanding Original Senior Notes. We will keep the Exchange Offer open for not less than 20 business days and not more than 30 business days after the date notice of the Exchange Offer is mailed to the holders. A copy of the Registration Rights Agreement has been filed as an exhibit to the Registration Statement of which this prospectus is a part. The Exchange Offer is being made pursuant to the Registration Rights Agreement to satisfy our obligations thereunder. Based on SEC staff interpretations contained in several no-action letters regarding similar exchange offers, we believe that, except as described below, the Exchange Senior Notes issued pursuant to the Exchange Offer in exchange for Original Senior Notes may be offered for resale, resold and otherwise transferred by any holder of the Exchange Senior Notes (other than any holder which is a broker-dealer or an "affiliate" of our company within the meaning of Rule 405 under the Securities Act) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that: (i) you acquired such Exchange Senior Notes in the ordinary course of your business; (ii) you have no arrangement or understanding with any person to participate in the distribution of such Exchange Senior Notes; and (iii) you are not engaged in, and do not intend to engage in, a distribution of such Exchange Senior Notes. By tendering Original Senior Notes for Exchange Senior Notes, you will represent to us that, among other things: (i) the Exchange Senior Notes issued in the Exchange Offer are being acquired in the ordinary course of business of the person receiving the Exchange Senior Notes, whether or not such person is the holder; (ii) neither you nor any such other person is engaging in or intends to engage in or has an arrangement or understanding with any person to participate in a distribution of such Exchange Senior Notes within the meaning of the Securities Act; (iii) neither you nor any such other person is an affiliate of our company, or if you or such other person is an affiliate of our company, you or such other person will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable; and (iv) you are not a broker-dealer, or if you are a broker-dealer, that you will receive the Exchange Senior Notes for your own account, you will deliver a prospectus on resale of your Exchange Senior Notes and you acquired your Original Senior Notes as a result of market-making activities or other trading activities. In the event that you cannot make the requisite representations to us, you cannot rely on such interpretations by the staff of the SEC and must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction. Unless an exemption from registration is otherwise available, any such resale transaction should be covered by an effective registration statement containing the selling securityholder information required by Item 507 of Regula- 58 tion S-K under the Securities Act. This prospectus may be used for an offer to resell, resale or other retransfer of Exchange Senior Notes only as specifically set forth herein. As noted above, we base our belief on interpretations by the SEC staff in no-action letters issued to other issuers in exchange offers like ours. We have not, however, asked the SEC to consider this particular Exchange Offer in the context of a no-action letter. Therefore, you cannot be sure that the SEC will treat this Exchange Offer in the same way it has treated other exchange offers in the past. If our belief is wrong, you could incur liabilities under the Securities Act. We will not protect you against any loss incurred as a result of this liability under the Securities Act. Each broker-dealer that receives Exchange Senior Notes for its own account in exchange for Original Senior Notes, where such Original Senior Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Senior Notes. See "PLAN OF DISTRIBUTION." Pursuant to the Registration Rights Agreement, there are circumstances where we are required to file a shelf registration statement for resale of Original Senior Notes. TERMS OF THE EXCHANGE OFFER Upon the terms and subject to the conditions set forth in this prospectus and in the Letter of Transmittal, we will accept for exchange any and all Original Senior Notes properly tendered and not withdrawn prior to 5:00 p.m., New York City time, on the Expiration Date of the Exchange Offer. You should read "-- Expiration Date; Extensions; Amendments" below for an explanation of how the Expiration Date may be amended. Holders may exchange some or all of their Original Senior Notes in denominations of $1,000 and integral multiples thereof. We will issue and deliver $1,000 principal amount of Exchange Senior Notes in exchange for each $1,000 principal amount of outstanding Original Senior Notes accepted in the Exchange Offer. The form and terms of the Exchange Senior Notes will be the same as the form and terms of the Original Senior Notes except the Exchange Senior Notes will be registered under the Securities Act and therefore will not bear legends restricting the transfer thereof. The Exchange Senior Notes will evidence the same debt as the Original Senior Notes. The Exchange Senior Notes will be issued under and entitled to the benefits of the Indenture, dated June 1, 2002 between us and The Bank of New York, as Trustee, and supplemented by the First Supplemental Indenture dated June 18, 2002 which also authorized the issuance of the Original Senior Notes, such that both series will be treated as a single class of debt securities under the Indenture. As of the date of this prospectus, $575 million aggregate principal amount of the Original Senior Notes is outstanding. This prospectus, together with the Letter of Transmittal, is being sent to all registered holders of Original Senior Notes. There will be no fixed record date for determining registered holders of Original Senior Notes entitled to participate in the Exchange Offer. The Exchange Offer is not conditioned upon any minimum principal amount of Original Senior Notes being tendered for exchange. However, the obligation to accept Original Senior Notes for exchange pursuant to the Exchange Offer is subject to certain conditions, as described under "-- Conditions." We intend to conduct the Exchange Offer in accordance with the provisions of the Registration Rights Agreement and the applicable requirements of the Exchange Act, and the rules and regulations of the SEC thereunder. Original Senior Notes which are not tendered for exchange in the Exchange Offer will remain outstanding and continue to accrue interest and will be entitled to the rights and benefits such holders have under the Indenture and the Registration Rights Agreement. We will be deemed to have accepted for exchange properly tendered Original Senior Notes when, as and if we have given oral or written notice thereof to the Exchange Agent and complied with the provisions of 59 the Indenture. The Exchange Agent will act as agent for the tendering holders for the purposes of receiving the Exchange Senior Notes from us. If you tender Original Senior Notes in the Exchange Offer you will not be required to pay brokerage commissions or fees or, subject to the instructions in the Letter of Transmittal, transfer taxes with respect to the exchange of Original Senior Notes pursuant to the Exchange Offer. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the Exchange Offer. See "-- Fees and Expenses." EXPIRATION DATE; EXTENSIONS; AMENDMENTS The term "Expiration Date" shall mean 5:00 p.m., New York City time on November 6, 2002, unless we, in our sole discretion, extend the Exchange Offer, in which case the term "Expiration Date" shall mean the latest date to which the Exchange Offer is extended. If the Exchange Offer is not completed by March 17, 2003, the interest rate on the Original Senior Notes shall be increased by 50 basis points per annum. We will pay such additional interest on regular interest payment dates. Such additional interest will be in addition to any other interest payable from time to time with respect to the Original Senior Notes. If we extend the Exchange Offer, we will notify the Exchange Agent of any extension by oral or written notice and will mail to the holders an announcement thereof, prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date. We reserve the right, in our sole discretion, (i) to delay accepting any Original Senior Notes, to extend the Exchange Offer or to terminate the Exchange Offer and not permit acceptance of Original Senior Notes not previously accepted, if any of the conditions set forth below under "-- Conditions" have not been satisfied, by giving oral or written notice of the delay, extension or termination to the Exchange Agent or (ii) to amend the terms of the Exchange Offer in any manner which, in our good faith judgment, is advantageous to the holders of the Original Senior Notes, whether before or after any tender of the Exchange Senior Notes. Any delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by oral or written notice thereof to the holders. If the Exchange Offer is amended in a manner determined by us to constitute a material change, we will promptly notify holders of the amendment by means of a prospectus supplement that will be distributed to the registered holders, if required by law, and we will extend the Exchange Offer for a period of five to ten business days, depending upon the significance of the amendment and the manner of disclosure to the registered holders, if the Exchange Offer would otherwise expire during such five to ten business day period. INTEREST ON THE EXCHANGE SENIOR NOTES The Exchange Senior Notes will bear interest at 6.25% per year. Interest on the Exchange Senior Notes will be payable semi-annually, in arrears, on January 15 and July 15 of each year, commencing on January 15, 2003. Interest on the Exchange Senior Notes will accrue from the last interest payment date on which interest was paid on the Original Senior Notes surrendered in exchange therefor or, if no interest has been paid on the Original Senior Notes, from the date of the original issuance of the Original Senior Notes. CONDITIONS Prior to the Expiration Date, we may terminate the Exchange Offer if: (a) any action or proceeding is instituted or threatened in any court or by or before any governmental agency with respect to the Exchange Offer which, in our judgment, might materially impair our ability to proceed with the Exchange Offer, or (b) any law, statute, rule or regulation is proposed, adopted or enacted, or any existing law, statute, rule or regulation is interpreted by the staff of the SEC, which, in our judgment, might materially impair our ability to proceed with the Exchange Offer, or 60 (c) any governmental approval has not been obtained, which approval we shall, in our discretion, deem necessary for the consummation of the Exchange Offer as contemplated hereby. If we determine in our discretion that any of these conditions are not satisfied, we may (i) refuse to accept any Original Senior Notes and return all tendered Original Senior Notes to the tendering holders, (ii) extend the Exchange Offer and retain all Original Senior Notes tendered prior to the expiration of the Exchange Offer, subject, however, to the rights of holders who tendered such Original Senior Notes to withdraw their tendered Original Senior Notes, or (iii) waive such unsatisfied conditions with respect to the Exchange Offer and accept all properly tendered Original Senior Notes which have not been withdrawn. The foregoing conditions are for our benefit and may be asserted by us regardless of the circumstances giving rise to any such condition or may be waived by us in whole or in part at any time and from time to time in our discretion prior to the Expiration Date. Our failure at any time to exercise any of our rights shall not be deemed a waiver of any such right, and each such right will be deemed an ongoing right which may be asserted at any time and from time to time. PROCEDURES FOR TENDERING BOOK-ENTRY INTERESTS The Original Senior Notes sold to "qualified institutional buyers" under Rule 144A under the Securities Act and to non-U.S. persons in offshore transactions under Regulation S under the Securities Act were issued as global securities in fully registered form without interest coupons. Beneficial interests in the global securities, held by direct or indirect participants in DTC, are shown on, and transfers of these interests are effected only through, records maintained in book-entry form by DTC with respect to its participants. If you hold your Original Senior Notes in the form of book-entry interests and you wish to tender your Original Senior Notes for exchange pursuant to the Exchange Offer, you must transmit to the Exchange Agent on or prior to the Expiration Date either: (1) a written or facsimile copy of a properly completed and duly executed Letter of Transmittal, including all other documents required by such Letter of Transmittal, to the Exchange Agent at the address set forth on the cover page of the Letter of Transmittal; or (2) a computer-generated message transmitted by means of DTC's Automated Tender Offer Program system and received by the Exchange Agent and forming a part of a confirmation of book-entry transfer, in which you acknowledge and agree to be bound by the terms of the Letter of Transmittal. In addition, in order to deliver Original Senior Notes held in the form of book-entry interests: (1) a timely confirmation of book-entry transfer of such Original Senior Notes into the Exchange Agent's account at DTC pursuant to the procedure for book-entry transfers described below under "-- Book-Entry Transfer" must be received by the Exchange Agent prior to the Expiration Date; or (2) you must comply with the guaranteed delivery procedures described below. THE METHOD OF DELIVERY OF ORIGINAL SENIOR NOTES AND THE LETTER OF TRANSMITTAL FOR YOUR ORIGINAL SENIOR NOTES AND ALL OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT YOUR ELECTION AND RISK. INSTEAD OF DELIVERY BY MAIL, WE RECOMMEND THAT YOU USE AN OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL CASES, SUFFICIENT TIME SHOULD BE ALLOWED TO ASSURE DELIVERY TO THE EXCHANGE AGENT BEFORE THE EXPIRATION DATE. YOU SHOULD NOT SEND THE LETTER OF TRANSMITTAL OR ORIGINAL SENIOR NOTES TO US. YOU MAY REQUEST YOUR BROKER, DEALER, COMMERCIAL BANK, TRUST COMPANY, OR NOMINEE TO EFFECT THE ABOVE TRANSACTIONS FOR YOU. CERTIFICATED ORIGINAL SENIOR NOTES The Original Senior Notes sold to "institutional accredited investors" under Rule 501(a)(1), (2), (3) or (7) under the Securities Act were issued in certificated fully registered form without coupons. Only registered holders of certificated Original Senior Notes may tender those Original Senior Notes in the Exchange Offer. 61 If your Original Senior Notes are certificated and you wish to tender those Original Senior Notes for exchange pursuant to the Exchange Offer, you must transmit to the Exchange Agent on or prior to the Expiration Date a written or facsimile copy of a properly completed and duly executed Letter of Transmittal, including all other required documents, to the the Exchange Agent at the address set forth on the cover page of the Letter of Transmittal. In addition, in order to validly tender your certificated Original Senior Notes: (1) the certificates representing your Original Senior Notes must be received by the Exchange Agent prior to the Expiration Date; or (2) you must comply with the guaranteed delivery procedures described below. PROCEDURES APPLICABLE TO ALL HOLDERS If you properly tender an Original Senior Note and you do not withdraw the tender prior to the Expiration Date, you will have made an agreement with us in accordance with the terms and subject to the conditions set forth in this prospectus and in the Letter of Transmittal. If your Original Senior Notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your Original Senior Notes, you should contact the registered holder promptly and instruct the registered holder to tender on your behalf. If you wish to tender on your own behalf, you must, prior to completing and executing the Letter of Transmittal and delivering your Original Senior Notes, either make appropriate arrangements to register ownership of the Original Senior Notes in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time. Signatures on a Letter of Transmittal or a notice of withdrawal must be guaranteed by an eligible institution unless: (1) Original Senior Notes tendered in the Exchange Offer are tendered either (A) by a registered holder who has not completed the box entitled "Special Issuance Instructions" or "Special Delivery Instructions" on the holder's Letter of Transmittal or (B) for the account of an eligible institution; and (2) the box entitled "Special Issuance Instructions" on the Letter of Transmittal has not been completed. If signatures on a Letter of Transmittal or a notice of withdrawal are required to be guaranteed, the guarantee must be by a financial institution, which includes most banks, savings and loan associations and brokerage houses, that is a participant in the Securities Transfer Agents Medallion Program, the New York Stock Exchange Medallion Program or the Stock Exchanges Medallion Program. If the Letter of Transmittal is signed by a person other than you, your Original Senior Notes must be endorsed or accompanied by a properly completed bond power and signed by you as your name appears on those Original Senior Notes. If the Letter of Transmittal or any Original Senior Notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, those persons should so indicate when signing. Unless we waive this requirement, in this instance you must submit with the Letter of Transmittal proper evidence satisfactory to us of their authority to act on your behalf. We will determine, in our sole discretion, all questions regarding the validity, form, eligibility, including time of receipt, acceptance and withdrawal of tendered Original Senior Notes. This determination will be final and binding. We reserve the absolute right to reject any and all Original Senior Notes not properly tendered or any Original Senior Notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defects, irregularities or conditions of tender as to particular Original 62 Senior Notes. Our interpretation of the terms and conditions of the Exchange Offer, including the instructions in the Letter of Transmittal, will be final and binding on all parties. You must cure any defects or irregularities in connection with tenders of your Original Senior Notes within the time period we will determine unless we waive that defect or irregularity. Although we intend to notify you of defects or irregularities with respect to your tender of Original Senior Notes, neither we, the Exchange Agent nor any other person will incur any liability for failure to give this notification. Your tender will not be deemed to have been made and your Original Senior Notes will be returned to you if: (1) you improperly tender your Original Senior Notes; (2) you have not cured any defects or irregularities in your tender; and (3) we have not waived those defects, irregularities or improper tender. The Exchange Agent will return your Original Senior Notes, unless otherwise provided in the Letter of Transmittal, as soon as practicable following the expiration of the Exchange Offer. In addition, we reserve the right in our sole discretion to: (1) purchase or make offers for, or offer registered Notes for, any Original Senior Notes that remain outstanding subsequent to the expiration of the Exchange Offer; (2) terminate the Exchange Offer; and (3) to the extent permitted by applicable law, purchase Original Senior Notes in the open market, in privately negotiated transactions or otherwise. The terms of any of these purchases or offers could differ from the terms of the Exchange Offer. In all cases, issuance of Exchange Senior Notes for Original Senior Notes that are accepted for exchange in the Exchange Offer will be made only after timely receipt by the Exchange Agent of certificates for your Original Senior Notes or a timely book-entry confirmation of your Original Senior Notes into the Exchange Agent's account at DTC, a properly completed and duly executed Letter of Transmittal, or a computer-generated message instead of the Letter of Transmittal, and all other required documents. If any tendered Original Senior Notes are not accepted for any reason set forth in the terms and conditions of the Exchange Offer or if Original Senior Notes are submitted for a greater principal amount than you desire to exchange, the unaccepted or non-exchanged Original Senior Notes, or Original Senior Notes in substitution therefor, will be returned without expense to you. In addition, in the case of Original Senior Notes tendered by book-entry transfer into the Exchange Agent's account at DTC pursuant to the book-entry transfer procedures described below, the non-exchanged Original Senior Notes will be credited to your account maintained with DTC, as promptly as practicable after the expiration or termination of the Exchange Offer. Each broker-dealer that receives Exchange Senior Notes for its own account in exchange for Original Senior Notes, where such Original Senior Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Senior Notes. See "PLAN OF DISTRIBUTION." GUARANTEED DELIVERY PROCEDURES If you desire to tender your Original Senior Notes and time will not permit your required documents to reach the Exchange Agent by the Expiration Date, or the procedure for book-entry transfer cannot be completed on time, you may tender if: (1) you tender through an eligible financial institution; (2) on or prior to 5:00 p.m., New York City time, on the Expiration Date, the Exchange Agent receives from an eligible institution a written or facsimile copy of a properly completed and duly executed Letter of Transmittal and Notice of Guaranteed Delivery, substantially in the form provided by us; and 63 (3) the certificates for all certificated Original Senior Notes, in proper form for transfer, or a book-entry confirmation, and all other documents required by the Letter of Transmittal, are received by the Exchange Agent within three New York Stock Exchange trading days after the date of execution of the Notice of Guaranteed Delivery. The Notice of Guaranteed Delivery may be sent by facsimile transmission, mail or hand delivery. The Notice of Guaranteed Delivery must set forth: (1) your name and address; (2) the amount of Original Senior Notes you are tendering; and (3) a statement that your tender is being made by the Notice of Guaranteed Delivery and that you guarantee that within three New York Stock Exchange trading days after the execution of the Notice of Guaranteed Delivery, the eligible institution will deliver the following documents to the Exchange Agent: (A) the certificates for all certificated Original Senior Notes being tendered, in proper form for transfer or a book-entry confirmation of tender; (B) a written or facsimile copy of the Letter of Transmittal, or a book-entry confirmation instead of the Letter of Transmittal; and (C) any other documents required by the Letter of Transmittal. BOOK-ENTRY TRANSFER The Exchange Agent will establish an account with respect to the book-entry interests at DTC for purposes of the Exchange Offer promptly after the date of this prospectus. You must deliver your book-entry interest by book-entry transfer to the applicable account maintained by the Exchange Agent at DTC. Any financial institution that is a participant in DTC's systems may make book-entry delivery of book-entry interests by causing DTC to transfer the book-entry interests into the Exchange Agent's applicable account at DTC in accordance with DTC's procedures for transfer. If one of the following situations occurs: (1) you cannot deliver a book-entry confirmation of book-entry delivery of your book-entry interests into the Exchange Agent's applicable account at DTC; or (2) you cannot deliver all other documents required by the Letter of Transmittal to the Exchange Agent prior to the Expiration Date, then you must tender your book-entry interests according to the Guaranteed Delivery Procedures discussed above. WITHDRAWAL RIGHTS You may withdraw tenders of your Original Senior Notes at any time prior to 5:00 p.m., New York City time, on the Expiration Date. For your withdrawal to be effective, the Exchange Agent must receive a written or facsimile transmission notice of withdrawal at its address set forth below under "-- Exchange Agent" prior to 5:00 p.m., New York City time, on the Expiration Date. The notice of withdrawal must: (1) state your name; (2) identify the specific Original Senior Notes to be withdrawn, including the certificate number or numbers, if any, and the principal amount of withdrawn Original Senior Notes; (3) be signed by you in the same manner as you signed the Letter of Transmittal when you tendered your Original Senior Notes, including any required signature guarantees or be accompanied by 64 documents of transfer sufficient for the Exchange Agent to register the transfer of the Original Senior Notes into your name; and (4) specify the name in which the Original Senior Notes are to be registered, if different from yours. We will determine all questions regarding the validity, form and eligibility, including time of receipt, of withdrawal notices. Our determination will be final and binding on all parties. Any Original Senior Notes withdrawn will be deemed not to have been validly tendered for exchange for purposes of the Exchange Offer. Any Original Senior Notes which have been tendered for exchange but which are not exchanged for any reason will be returned to you without cost as soon as practicable after withdrawal, rejection of tender or termination of the Exchange Offer. Properly withdrawn Original Senior Notes may be retendered by following one of the procedures described under "-- Procedures for Tendering" above at any time on or prior to 5:00 p.m., New York City time, on the Expiration Date. EXCHANGE AGENT The Bank of New York has been appointed as Exchange Agent of the Exchange Offer. Questions and requests for assistance, requests for additional copies of this prospectus or of the Letter of Transmittal and requests for Notices of Guaranteed Delivery should be directed to the Exchange Agent addressed as follows: BY HAND DELIVERY, REGISTERED OR CERTIFIED MAIL OR OVERNIGHT DELIVERY: The Bank of New York Corporate Trust Operations Reorganization Unit 101 Barclay Street - 7E New York, New York 10286 Attn: Ms. Carolle Montreuil BY FACSIMILE: (212) 298-1915 FOR INFORMATION OR CONFIRMATION BY TELEPHONE: (212) 815-5920 FEES AND EXPENSES We will pay the expenses of soliciting tenders. The principal solicitation is being made by mail; however, additional solicitation may be made by telegraph, telephone, facsimile, or in person by officers and our regular employees and our affiliates. We have not retained any dealer-manager in connection with the Exchange Offer and will not make any payments to brokers, dealers or others soliciting acceptances of the Exchange Offer. However, we will pay the Exchange Agent reasonable and customary fees for its services and will reimburse it for its reasonable out-of-pocket expenses in connection therewith. We may also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding copies of the prospectus and related documents to the beneficial owners of the Original Senior Notes and in handling or forwarding tenders for exchange. We will pay the cash expenses to be incurred in connection with the Exchange Offer, which we estimate to be approximately $850,000 in the aggregate. Such expenses include fees and expenses of the Exchange Agent and Trustee, accounting and legal fees and printing costs, among others. We will pay all transfer taxes, if any, applicable to the exchange of Original Senior Notes pursuant to the Exchange Offer. If, however, Exchange Senior Notes or Original Senior Notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be issued in the name of, any person other 65 than the holder of the Original Senior Notes tendered, or if tendered Original Senior Notes are registered in the name of any person other than the person signing the Letter of Transmittal, or if a transfer tax is imposed for any reason other than the exchange of Original Senior Notes pursuant to the Exchange Offer, then the amount of any transfer taxes (whether imposed on the holder or any other persons) will be payable by the tendering holder. If satisfactory evidence of payment of such taxes or exemption therefrom is not submitted with the Letter of Transmittal, the amount of such transfer taxes will be billed directly to such tendering holder. CONSEQUENCES OF FAILURE TO EXCHANGE Holders of Original Senior Notes who do not exchange their Original Senior Notes for Exchange Senior Notes pursuant to the Exchange Offer will continue to be subject to the restrictions on transfer of such Original Senior Notes as set forth in the legend on the Original Senior Notes and in the Indenture. In general, the Original Senior Notes may not be offered or sold, unless registered under the Securities Act, except under an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. We do not currently anticipate that we will register under the Securities Act the resale of any Original Senior Notes that remain outstanding after consummation of the Exchange Offer. However, generally, (i) due to any change in law or applicable interpretations thereof by the SEC's staff, we determine that we are not permitted to effect the Exchange Offer, (ii) for any reason the Exchange Offer is not consummated within 270 days from June 18, 2002, (iii) if any initial purchaser so requests with respect to Original Senior Notes not eligible to be exchanged for Exchange Senior Notes in the Exchange Offer and held by it following consummation of the Exchange Offer or (iv) if any holder of Original Senior Notes (except certain broker dealers) is not eligible to participate in the Exchange Offer or, in the case of any holder of Original Senior Notes (except certain broker-dealers) that participates in the Exchange Offer, does not receive freely tradeable Exchange Senior Notes in exchange for Original Senior Notes, we are obligated to file a registration statement on the appropriate form under the Securities Act relating to the Original Senior Notes held by such persons. ACCOUNTING TREATMENT The Exchange Senior Notes will be recorded at the same carrying value as the Original Senior Notes as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize a gain or loss for accounting purposes. The expenses of the Exchange Offer will be amortized over the term of the Exchange Senior Notes. 66 DESCRIPTION OF THE EXCHANGE SENIOR NOTES AND THE INDENTURE GENERAL We issued the Original Senior Notes and we will issue the Exchange Senior Notes under an indenture between us and The Bank of New York, as trustee, and a supplemental indenture thereto relating to the Original Senior Notes and Exchange Senior Notes (collectively, the "Indenture"). The aggregate principal amount of bonds, debentures, promissory notes or other evidences of indebtedness which may be issued under the Indenture is unlimited. Subject to the terms of the Indenture, we may issue additional senior notes under the Indenture in the future at our discretion. Issuances of individual series of senior notes, including this offering, will be governed by the Indenture and the corresponding series supplemental indenture. We may, without the consent of holders of the Exchange Senior Notes, issue additional senior notes having the same ranking and the same interest rate, maturity and other terms (except the issue price and issue date) as the Exchange Senior Notes. Any additional senior notes having such terms will constitute one single series of senior notes. The following summaries of certain provisions of the Exchange Senior Notes and the Indenture do not purport to be complete and are subject, and qualified in their entirety by reference, to all of the provisions of the Exchange Senior Notes and the Indenture, including the definitions of certain terms therein. The definitions of certain capitalized terms used in the following summary are set forth below under "-- Certain Definitions." The Exchange Senior Notes will not be guaranteed by, or otherwise be obligations of, Southern or any of its direct or indirect subsidiaries other than our company. PRINCIPAL, MATURITY AND INTEREST The Exchange Senior Notes will be initially issued in the aggregate principal amount of $575,000,000. The entire principal amount of the Exchange Senior Notes will mature and become due and payable, together with all accrued interest thereon, on July 15, 2012. The Exchange Senior Notes are not subject to any sinking fund provision. The Exchange Senior Notes will be issued in denominations of $1,000 and integral multiples thereof. Each Exchange Senior Note shall bear interest at the rate of 6.25% per annum from the date of original issuance, payable semiannually in arrears on January 15 and July 15 of each year to the person in whose name such Exchange Senior Notes are registered at the close of business on the fifteenth calendar day prior to such payment date. The initial interest payment date is January 15, 2003. The amount of interest payable will be computed on the basis of a 360-day year of twelve 30-day months. In the event that any date on which interest is payable on the Exchange Senior Notes is not a Business Day, then payment of the interest payable on such date will be made on the next succeeding day that is a Business Day (and without any interest or other payment in respect of any such delay), with the same force and effect as if made on such date. "Business Day" means a day other than a (i) Saturday or Sunday, (ii) a day on which banks in New York, New York are authorized or obligated by law or executive order to remain closed, or (iii) a day on which the trustee's corporate trust office is closed. For so long as the Exchange Senior Notes are issued in book-entry form, payments of principal and interest shall be made in immediately available funds by wire transfer to DTC or its nominee. If the Exchange Senior Notes are issued in certificated form to a Holder (as defined below) other than DTC, payments of principal and interest shall be made by check mailed to such Holder at such Holder's registered address or, upon written application by a Holder of $1,000,000 or more in aggregate principal amount of the Exchange Senior Notes to the trustee in accordance with the terms of the Indenture, by wire transfer of immediately available funds to an account maintained by such Holder with a bank or other financial institution. Default interest will be paid in the same manner to Holders as of a special record date established in accordance with the Indenture. 67 All amounts paid by us for the payment of principal, premium (if any) or interest on any Exchange Senior Notes that remain unclaimed at the end of two years after such payment has become due and payable will be repaid to us, and the Holders of such Exchange Senior Notes will thereafter look only to us for payment thereof. RANKING The Exchange Senior Notes will be issued as unsecured senior debt securities under the Indenture and will rank equally with all of our unsecured and unsubordinated debt. We have not issued, nor do we have any arrangements to issue, any significant indebtedness that would be senior to the Exchange Senior Notes. OPTIONAL REDEMPTION At any time and at our option, we may redeem the Exchange Senior Notes, in whole or in part (if in part, by lot or by such other method as the trustee shall deem fair or appropriate) at the redemption price of 100% of principal amount of such Exchange Senior Notes, plus accrued interest on the principal amount of such Exchange Senior Notes, if any, to the redemption date, plus the Make-Whole Premium. Notice of redemption to the Holders of Exchange Senior Notes to be redeemed will be given by us by mailing notice of such redemption by first class mail at least 30 days and not more than 60 days prior to the date fixed for redemption to such Holders of Exchange Senior Notes at their last addresses as they shall appear in the securities register. Failure to give notice by mail, or any defect in the notice to the Holder of any Exchange Senior Note designated for redemption as a whole or in part will not affect the validity of the proceedings for the redemption of any other Exchange Senior Note. The notice of redemption to each Holder will specify that the Exchange Senior Notes are being redeemed pursuant to the Indenture, the date fixed for redemption, the place or places of payment, the CUSIP and ISIN numbers (as applicable), that payment will be made upon presentation and surrender of the Exchange Senior Notes, that interest accrued to the date fixed for redemption will be paid as specified in the Indenture and that, on and after said date interest thereon or on the portions thereof to be redeemed will cease to accrue. REPORTING OBLIGATIONS; INFORMATION TO HOLDERS We will furnish to the trustee: (i) unless we are then filing comparable reports pursuant to the reporting requirements of the Exchange Act, as soon as practicable and in any event within 45 days after the end of the first, second and third quarterly accounting periods of each fiscal year (commencing with the quarter ending June 30, 2002), our unaudited consolidated balance sheet as of the last day of such quarterly period and the related consolidated statements of income and cash flows during such quarterly period prepared in accordance with GAAP and (in the case of second and third quarterly periods) for the portion of the fiscal year ending with the last day of such quarterly period, setting forth in each case in comparative form corresponding unaudited figures from the preceding fiscal year (except in the case where the preceding fiscal year includes periods prior to our formation) and accompanied by (A) a written statement of our authorized representative to the effect that such financial statements fairly represent in all material respects our financial condition and results of operations at and as of their respective dates and (B) a section substantially similar to the "Management's Discussion and Analysis" ("MD&A") section of an SEC Form 10-Q (without any comparison to periods prior to our formation); (ii) unless we are then filing comparable reports pursuant to the reporting requirements of the Exchange Act, as soon as practicable and in any event within 90 days after the end of each fiscal year (commencing with the fiscal year ending December 31, 2002), our consolidated balance sheet as of the end of such year and the related consolidated statements of income, cash flows, and retained earnings during such year setting forth in each case in comparative form corresponding figures from the preceding fiscal year (except in the case where the preceding fiscal year includes periods prior to our formation), accompanied by (A) an audit report thereon of a firm of independent public accountants of recognized 68 national standing and (B) a section substantially similar to the MD&A section of an SEC Form 10-K (without any comparison to periods prior to our formation); (iii) at the time of the delivery of the report provided for in clause (ii) above (or at the time of the filing of the comparable report pursuant to the Exchange Act), an officer's certificate to the effect that, to the best of such officer's knowledge, no default or event of default under the Exchange Senior Notes or the Indenture has occurred and is continuing or, if any default or event of default thereunder has occurred and is continuing, specifying the nature and extent thereof and what action we are taking or propose to take in response thereto; and (iv) promptly after we obtain actual knowledge of the occurrence thereof, written notice of the occurrence of any event or condition which constitutes an event of default, and an officer's certificate of our company specifically stating that such event of default has occurred and setting forth the details thereof and the action which we are taking or propose to take with respect thereto. All such information provided to the trustee as indicated above also will be provided by the trustee upon written request to the trustee (which may be a single continuing request), to (x) Holders, (y) holders of beneficial interests in the Exchange Senior Notes or (z) prospective purchasers of the Exchange Senior Notes or beneficial interests in the Exchange Senior Notes. We will furnish to the trustee, upon its request, sufficient copies of all such information to accommodate the requests of such holders and prospective holders of beneficial interests in the Exchange Senior Notes. Upon the request of any Holder, any holder of a beneficial interest in the Exchange Senior Notes, or the trustee (on behalf of a Holder or a holder of a beneficial interest in the Exchange Senior Notes), we will furnish such information as is specified in paragraph (d)(4) of Rule 144A to Holders (and to holders of beneficial interests in the Exchange Senior Notes), prospective purchasers of the Exchange Senior Notes (and of beneficial interests in the Exchange Senior Notes) who are qualified institutional buyers or "institutional accredited investors" or to the trustee for delivery to such Holder or prospective purchasers of the Exchange Senior Notes or beneficial interests therein, as the case may be, unless, at the time of such request, we are subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act. CERTAIN COVENANTS CONSOLIDATION, MERGER AND SALE We shall not consolidate with or merge into any other corporation or convey, transfer or lease our properties and assets substantially as an entirety to any person, unless (1) such other corporation or person is a corporation organized and existing under the laws of the United States, any state thereof or the District of Columbia and such other corporation or person expressly assumes, by supplemental indenture executed and delivered to the trustee, the payment of the principal of (and premium, if any) and interest on all senior notes and the performance of every covenant of the Indenture on the part of our Company to be performed or observed; (2) immediately after giving effect to such transaction, no Event of Default shall have happened and be continuing; and (3) we delivered to the trustee an officer's certificate and an opinion of counsel, each stating that such transaction complies with the provisions of the Indenture governing consolidation, merger, conveyance, transfer or lease and that all conditions precedent thereto have been complied with. LIMITATION ON ASSET SALES Except for the sale of our properties and assets substantially as an entirety as described in "-- Consolidation, Merger and Sale" above, and other than assets required to be sold to conform with governmental regulations, we will not, and will not permit any of our Subsidiaries to, consummate any Asset Sale, if the aggregate net book value of all such Asset Sales consummated during the most recent twelve month period would exceed 10% of our Consolidated Tangible Assets as of the beginning of our most recently ended full fiscal quarter preceding such Asset Sale; provided, however, that any such Asset Sale will be disregarded for purposes of the 10% limitation specified above if the proceeds thereof (i) are, within 18 months of such Asset Sale, invested or reinvested by us or any Subsidiary in a Permitted Business, (ii) are 69 used by us or a Subsidiary to repay Indebtedness of our company or such Subsidiary or (iii) are retained by us or a Subsidiary. LIMITATION ON LIENS We shall not, and shall not permit any of our Subsidiaries to, issue, assume, guarantee or permit to exist any Indebtedness for borrowed money secured by any lien on any property of our company or our Subsidiaries, whether owned on the date that the Original Senior Notes were issued or thereafter acquired, without in any such case effectively securing the outstanding Exchange Senior Notes (together with, if we shall so determine, any other Indebtedness of or guaranteed by our company ranking equally with the Exchange Senior Notes) equally and ratably with such Indebtedness (but only so long as such Indebtedness is so secured); provided, however, that the foregoing restriction shall not apply to the following liens: (i) liens, if any, in existence on the date the Original Senior Notes were issued, (ii) pledges or deposits in the ordinary course of business in connection with bids, tenders, contracts or statutory obligations or to secure surety or performance bonds, (iii) liens imposed by law, such as carriers', warehousemen's and mechanics' liens, arising in the ordinary course of business, (iv) liens for taxes being contested in good faith, (v) minor encumbrances, easements or reservations which do not in the aggregate materially adversely affect the value of the properties or impair their use, (vi) liens on any property existing at the time of acquisition thereof by us or any of our Subsidiaries, (vii) liens on any property (other than Existing Assets) securing (a) all or any portion of the cost of acquiring, constructing, altering, improving or repairing any real or personal property or improvements used or to be used in connection with such property or (b) Indebtedness incurred by us or any of our Subsidiaries prior to, at the time of, or within one year after the later of the acquisition, the completion of construction (including any improvements on an existing property), alteration, improvement, repair or the commencement of commercial operation of the property, which Indebtedness is incurred for the purpose of financing or refinancing all or any part of the purchase price, construction, improvements, alterations or repairs, (viii) liens to secure purchase money Indebtedness not in excess of the cost or value of the property acquired, (ix) mortgages securing obligations issued by a state, territory or possession of the United States, or any political subdivision of any of the foregoing or the District of Columbia, to finance the acquisition or construction of property, and on which the interest is not, in the opinion of tax counsel of recognized standing or in accordance with a ruling issued by the Internal Revenue Service, includible in gross income of the holder by reason of Section 103(a)(1) of the Internal Revenue Code (or any successor to such provision) as in effect at the time of the issuance of such obligations, (x) other liens to secure Indebtedness for borrowed money or in connection with a project financing (including a sale-leaseback transaction) in an aggregate principal amount which does not at the time such Indebtedness is incurred exceed 20% of our Consolidated Tangible Assets, or (xi) liens granted in connection with extending, renewing, replacing or refinancing (or successive extensions, renewals, replacements or refinancings) any of the Indebtedness (so long as there is no increase in the principal amount of the Indebtedness) described in clauses (i) through (x) above. In the event that we shall propose to pledge, mortgage or hypothecate any property, other than as permitted by clauses (i) through (xi) of the previous paragraph, we shall (prior thereto) give written notice thereof to the trustee, who shall give notice to the Holders, and we shall, prior to or simultaneously with such 70 pledge, mortgage or hypothecation, effectively secure all the Exchange Senior Notes equally and ratably with such Indebtedness. This covenant does not restrict our ability or the ability of any of our Subsidiaries to pledge, mortgage, hypothecate or permit to exist any mortgage, pledge or lien upon any assets (other than an Existing Asset, except to the extent permitted by clauses (i) through (xi) above) in connection with project financings or otherwise. RESTRICTIONS ON SUBSIDIARY INDEBTEDNESS Except to the extent permitted under "Limitations on Liens", we shall not permit any Subsidiary which owns any Existing Asset to create or incur or suffer to exist any Indebtedness for borrowed money. MINIMUM CONTRACT MAINTENANCE COVENANT We will not declare or pay any dividends or make any other distributions (except dividends payable or distributions made in shares of our common stock and dividends payable in cash in cases where, concurrently with the payment of the dividend, an amount in cash equal to the dividend is received by us as a capital contribution or as the proceeds of the issue and sale of shares of our common stock) on our common stock, or purchase or permit any of our Subsidiaries to purchase any shares of our common stock or make any payment on Affiliate Subordinated Indebtedness, unless (i) the percentage derived from dividing Contracted Operating Cash Flows by Total Operating Cash Flows is at least 80%, or (ii) the ratio of Recourse Indebtedness to Total Capitalization is 60% or less. CERTAIN DEFINITIONS "Affiliate Subordinated Indebtedness" means the Southern Subordinated Note and any other borrowings by us from Southern, or an affiliate of Southern, provided that such borrowings are subordinated on terms substantially similar to the terms of subordination set forth in the Southern Subordinated Note. "Asset Sale" means any sale, lease, sale and leaseback transfer, conveyance or other disposition of any assets including by way of the issue by us or any of our Subsidiaries of equity interests in such Subsidiaries which own any assets, except (a) in the ordinary course of business to the extent that such property is worn out or is no longer useful or necessary in connection with the operation of our business or sale of inventory, (b) if, prior to such conveyance or disposition, each Rating Agency provides a Ratings Reaffirmation of the Senior Notes after giving effect to such transaction, or (c) sale and leaseback or similar transfers of assets (other than Existing Assets). "Consolidated Tangible Assets" means, at any date of determination, the total assets of our company and our Subsidiaries determined in accordance with GAAP, excluding, however, from the determination of total assets (a) goodwill, organizational expenses, research and product development expenses, trademarks, trade names, copyrights, patents, patent applications, licenses and rights in any thereof, and other similar intangibles, (b) all deferred charges or unamortized debt discount and expenses, (c) all reserves carried and not deducted from assets, (d) securities which are not readily marketable, (e) cash held in sinking or other analogous funds established for the purpose of redemption, retirement or prepayment of capital stock or other equity interests or debt, (f) any write-up in the book value of any assets resulting from a revaluation thereof subsequent to March 31, 2002, and (g) any items not included in clauses (a) through (f) above which are treated as intangibles in conformity with GAAP, plus the aggregate net book value of all asset sales or dispositions made by our company and any of our Subsidiaries since the original issue date of the Original Senior Notes to the extent that the proceeds thereof or other consideration received therefor are not invested or reinvested in a Permitted Business, or are not retained by us or our Subsidiaries. "Contracted Operating Cash Flow" means the projection done at the end of each fiscal quarter of the next four fiscal quarters of our and our Subsidiaries' (other than Unrestricted Subsidiaries) total cash flow available for debt service from fixed-price capacity power contracts, each contract having a term from initial commencement to expiry of at least five years; provided, however, that up to 12.5% of the Contracted Operating Cash Flows may be derived from fixed-price capacity power contracts that have contract terms of at least two years but less than five years from initial commencement to expiry. The projection shall be 71 consistent with our financial reporting procedures. The term fixed-price capacity PPA includes any PPA that states the base capacity price on a per unit basis (for example, in dollars per megawatt) and which may allow for adjustments to that base price that are generally encompassed within the our company's or the electric generation industry's commercial expectations for a PPA of a similar duration (including but not limited to adjustments to accommodate changed capacity purchase levels, variations in expected or actual construction costs or demonstrated capability levels, changes in equipment or law and force majeure); provided, however, that a PPA will not be considered to be a fixed-price capacity PPA if a material portion of the capacity price varies based upon a market index for electric capacity or energy, fuel, weather or other factor that is external to the facility and the transaction between the Company and its customer. The method of calculating the energy price shall not be considered in assessing whether a PPA is a fixed-priced capacity PPA. "Existing Assets" means the following of our generating facilities: (i) Dahlberg Units 1-10; (ii) Wansley 6 and Wansley 7; (iii) Franklin 1 and Franklin 2; (iv) Harris 1 and Harris 2; and (v) Stanton A. "GAAP" means U.S. generally accepted accounting principles. "Holder" means a registered holder of an Exchange Senior Note. "Indebtedness" of any person means (i) all indebtedness of such person for borrowed money, (ii) all obligations of such person evidenced by bonds, debentures, notes, or other similar instruments, (iii) all obligations of such person to pay the deferred purchase price of property or services (other than trade accounts obtained on normal commercial terms in the ordinary course of business or practice), (iv) all indebtedness created or arising under any conditional sale or other title retention agreement with respect to property acquired by such person (even though the rights and remedies of the seller or lender under such agreement in the event of default are limited to repossession or sale of such property), (v) all capital lease obligations of such person that are required to be accounted for as a capital lease in accordance with GAAP, (vi) all obligations of the type referred to in clauses (i) through (v) above of other persons which such person is responsible for as guarantor, and (vii) all Indebtedness of the type referred to in clauses (i) through (vi) above secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any lien or security interest on property. "Make-Whole Premium" means, with respect to the Exchange Senior Notes, a computation as of a date not more than five days prior to the redemption date of the following: (i) the average life of the remaining scheduled payments of principal in respect of outstanding Exchange Senior Notes (the "Remaining Average Life") as of the redemption date; (ii) the yield to maturity for the United States treasury security having an average life equal to the Remaining Average Life and trading in the secondary market at the price closest to the principal amount thereof (the "Primary Issue") (subject to extrapolation if no United States treasury security has an average life equal to the Remaining Average Life); and (iii) the discounted present value of the then-remaining scheduled payments of principal and interest (but excluding that portion of any scheduled payment of interest that is actually due and paid on the redemption date) in respect of outstanding Exchange Senior Notes as of the redemption date using a discount factor equal to the sum of (x) the yield to maturity for the Primary Issue, plus (y) 25 basis points. The amount of Make-Whole Premium in respect of Exchange Senior Notes to be redeemed shall be an amount equal to (x) the discounted present value of such Exchange Senior Notes to be redeemed determined in accordance with clause (iii) above, minus (y) the unpaid principal amount of such Exchange Senior Notes; provided, however, that the Make-Whole Premium shall not be less than zero. "Permitted Business" means a business that is the same as or similar to our business as of the date that the Original Senior Notes were issued under the Indenture, or any business reasonably related thereto. "Rating Agencies" means Moody's Investors Service, Inc. and Standard & Poor's Ratings Services. 72 "Ratings Reaffirmation" means a reaffirmation by a rating agency of the higher of its minimum investment grade rating or the then current credit ratings (as applicable) of any of the Exchange Senior Notes outstanding, giving effect to the transaction giving rise to such request for such reaffirmation. "Recourse Indebtedness" means all Indebtedness (other than Affiliate Subordinated Indebtedness) of our company and of our Subsidiaries (other than Unrestricted Subsidiaries). "Subsidiary" means any corporation or other entity of which sufficient voting stock or other ownership or economic interests having ordinary voting power to elect a majority of the board of directors (or equivalent body) are at the time directly or indirectly held by us. "Total Capitalization" means the sum of (a) the aggregate of the capital stock and other equity accounts (including retained earnings and paid-in-capital) of our company and Subsidiaries (other than Unrestricted Subsidiaries; provided, however, that retained earnings of Unrestricted Subsidiaries shall be included); (b) all Recourse Indebtedness; and (c) Affiliate Subordinated Indebtedness. "Total Operating Cash Flow" means the projection done at the end of each fiscal quarter of the next four fiscal quarters of our and our Subsidiaries' (other than Unrestricted Subsidiaries) total cash flow available for debt service, as projected consistent with our financial reporting procedures. "Unrestricted Subsidiary" means any Subsidiary of our company all the Indebtedness of which (a) is nonrecourse to our company or any of our Subsidiaries (other than any other Unrestricted Subsidiary), other than with respect to stock or other ownership interest of our company or any of our Subsidiaries in such Subsidiary, and (b) is not secured by any property of our company or any of our Subsidiaries (other than the property of, or stock or other ownership interest in, an Unrestricted Subsidiary). EVENTS OF DEFAULT The Indenture provides that any one or more of the following described events with respect to the Exchange Senior Notes, which has occurred and is continuing, constitutes an "Event of Default" with respect to the Exchange Senior Notes: (a) failure for 30 days to pay interest on the Exchange Senior Notes, when due on an interest payment date other than at maturity or upon earlier redemption; or (b) failure to pay principal or premium, if any, or interest on the Exchange Senior Notes when due at maturity or upon earlier redemption; or (c) an event of default, as defined in any of our instruments under which there may be issued, or by which there may be secured or evidenced, of any Indebtedness of our company that has resulted in the acceleration of such Indebtedness, or any default occurring in payment of any such Indebtedness at final maturity (and after the expiration of any applicable grace periods), other than such Indebtedness the principal of which does not individually, or in the aggregate, exceed $50,000,000; or (d) our failure to perform or observe any covenant or agreement (while such covenant or agreement is effective) under the Indenture and such failure shall continue uncured for more than thirty (30) days after we have actual knowledge of such failure; or (e) one or more final judgments, decrees or orders of any court, tribunal, arbitrator, administrative or other governmental body or similar entity for the payment of money shall be rendered against us or any of our properties in an aggregate amount in excess of $50,000,000 (excluding the amount thereof covered by insurance) and such judgment, decree or order shall remain unvacated, undischarged, unsatisfied and unstayed for more than sixty (60) consecutive days, except while being contested in good faith by appropriate proceedings; or (f) certain events of bankruptcy, insolvency or reorganization involving our company or a Subsidiary. 73 If an Event of Default (other than an Event of Default based on an event of our bankruptcy, insolvency or reorganization) shall occur and be continuing, either the trustee or the Holders of not less than 25% in aggregate principal amount of the Exchange Senior Notes may, by written notice to us (and to the trustee if given by Holders), declare the principal of and accrued interest on all Exchange Senior Notes outstanding under the Indenture to be immediately due and payable, but upon certain conditions such declaration may be annulled and past defaults (except, unless theretofore cured, a default in payment of principal, premium or interest) may be waived by the Holders of a majority in aggregate principal amount of Exchange Senior Notes then outstanding under the Indenture. If an Event of Default due to our bankruptcy, insolvency or reorganization occurs, all unpaid principal, premium, if any, and interest in respect of the Exchange Senior Notes issued under the Indenture will automatically become due and payable without any declaration or other act on the part of the trustee or any Holder. The occurrence of an event described in paragraph (f) of this section with respect to a Subsidiary shall not constitute an Event of Default if (x) the creditors of such Subsidiary have no recourse to our company or (y) such Subsidiary is not a "significant subsidiary" as defined in Regulation S-X under the Securities Act. The Holders of a majority in principal amount of the Exchange Senior Notes then outstanding under the Indenture shall have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee under the Indenture, subject to certain limitations specified in the Indenture, provided that the Holders shall have offered to the trustee reasonable indemnity against expenses and liabilities. MODIFICATION The Indenture contains provisions permitting us and the trustee, with the consent of the holders of not less than a majority in principal amount of the outstanding senior notes of each series affected thereby, to modify the Indenture or the rights of the holders of the senior notes of such series; provided, that no such modification may, without the consent of the holder of each outstanding senior note affected thereby, (i) change the stated maturity of the principal of, or any installment of principal of or interest on, any senior note, or reduce the principal amount thereof or the rate of interest thereon or any premium payable upon the redemption thereof, or change the method of calculating the rate of interest thereon, or impair the right to institute suit for the enforcement of any such payment on or after the stated maturity thereof (or, in the case of redemption, on or after the redemption date), or (ii) reduce the percentage of principal amount of the outstanding senior notes of any series, the consent of whose holders is required for any such supplemental indenture, or the consent of whose holders is required for any waiver (of compliance with certain provisions of the Indenture or certain defaults thereunder and their consequences) provided for in the Indenture, or (iii) modify any of the provisions of the Indenture relating to supplemental indentures, waiver of past defaults, or waiver of certain covenants, except to increase any such percentage or to provide that certain other provisions of the Indenture cannot be modified or waived without the consent of the holder of each outstanding senior note affected thereby. In addition, we and the trustee may execute, without the consent of any holders of senior notes, any supplemental indenture for certain other usual purposes, including the creation of any new series of senior notes. SATISFACTION AND DISCHARGE AND COVENANT DISCHARGE SATISFACTION AND DISCHARGE The Indenture provides that upon our request the Indenture will cease to be of further effect and the trustee shall execute proper instruments acknowledging satisfaction and discharge of the Indenture when: (A) either (i) all senior notes outstanding under the Indenture have been delivered to the trustee for cancellation; or (ii) all senior notes outstanding under the Indenture that have not been delivered to the trustee for cancellation have become due and payable or have been called for redemption and we have deposited or caused to be deposited with the trustee as funds in trust an amount sufficient to pay and discharge the entire indebtedness on such senior notes not delivered to the trustee for cancellation, for principal (and premium, if 74 any) and interest to the date of stated maturity, redemption date or the date of payment; (B) we have paid or caused to be paid all sums payable under the Indenture; and (C) we have delivered to the trustee an officer's certificate and opinion of counsel, each stating that all conditions precedent relating to the satisfaction and discharge of the Indenture have been complied with. DISCHARGE OF CERTAIN COVENANTS AND CERTAIN EVENTS OF DEFAULT The provisions of the supplemental indenture relating to the Exchange Senior Notes will cease to be applicable with respect to (i) the covenants described under "Certain Covenants -- Limitation on Asset Sales," "-- Limitation on Liens," "-- Restrictions on Subsidiary Indebtedness" and "-- Minimum Contract Maintenance Covenant" and (ii) clause (d) under "Events of Default" with respect to such covenants and clauses (c) and (e) under "Events of Default" when (A) we have deposited with the trustee, as funds held in trust, money and/or U.S. Obligations that through the payment of interest and principal in respect thereof in accordance with their terms will provide money in an amount sufficient to pay the principal, premium, if any, and accrued interest on the Exchange Senior Notes; (B) we have delivered to the trustee an officer's certificate and an opinion of counsel, each stating that all conditions precedent relating to the discharge of the certain covenants and certain events of default have been complied with; and (C) we have delivered to the trustee an opinion of counsel, among other things, to the effect that the Holders will not recognize income, gain or loss for federal income tax purposes as a result of such deposit and discharge of certain covenants and Events of Default and will be subject to federal income tax on the same amount and in the same manner and at the same time as would have been the case if such deposit and discharge had not occurred. DISCHARGE AND CERTAIN OTHER EVENTS OF DEFAULT If we exercise our option to omit compliance with certain covenants and provisions of the supplemental indenture with respect to the Exchange Senior Notes as described in the immediately preceding paragraph and the Exchange Senior Notes are declared due and payable because of the occurrence of an Event of Default that remains applicable, the amount of funds on deposit with the trustee will be sufficient to pay amounts due on the Exchange Senior Notes, at the time of their stated maturity, but may not be sufficient to pay amounts due on the Exchange Senior Notes at the time of acceleration resulting from such Event of Default. We shall remain liable for such payments. REGISTRATION AND TRANSFER We are not required to (i) issue, register the transfer of or exchange Exchange Senior Notes during a period of 15 days immediately preceding the date notice is given identifying the Exchange Senior Notes called for redemption, or (ii) register the transfer of or exchange any Exchange Senior Notes so selected for redemption, in whole or in part, except the unredeemed portion of any Exchange Senior Note being redeemed in part. INFORMATION CONCERNING THE SENIOR NOTE INDENTURE TRUSTEE The trustee, prior to an Event of Default with respect to senior notes of any series, undertakes to perform, with respect to senior notes of such series, only such duties as are specifically set forth in the Indenture and, in case an Event of Default with respect to senior notes of any series has occurred and is continuing, shall exercise, with respect to senior notes of such series, the same degree of care as a prudent individual would exercise in the conduct of his or her own affairs. Subject to such provision, the trustee is under no obligation to exercise any of the powers vested in it by the Indenture at the request of any holder of senior notes of any series, unless offered reasonable indemnity by such holder against the costs, expenses and liabilities which might be incurred thereby. The trustee is not required to expend or risk its own funds or otherwise incur any financial liability in the performance of its duties if the trustee reasonably believes that repayment or adequate indemnity is not reasonably assured to it. 75 BOOK-ENTRY, DELIVERY AND FORM GENERAL The Exchange Senior Notes initially will be issued in the form of one or more fully registered Exchange Senior Notes in global form (the "Global Notes"). The Global Notes will be deposited upon issuance with the Trustee as custodian for DTC and registered in the name of DTC or its nominee, in each case for credit to the accounts of institutions that have accounts with DTC or its nominee (the "DTC participants") and to the accounts of institutions that have accounts with Euroclear or its nominee participants (the "Euroclear participants" and, collectively with the DTC participants, the "participants"). Each of DTC and Euroclear is referred to herein as a "Book Entry Facility." Ownership of beneficial interests in the Global Notes will be limited to participants or persons that may hold interests through participants. Ownership of beneficial interests in the Global Notes will be shown on, and the transfer of that ownership will be effected only through, records maintained by a Book Entry Facility or its nominee (with respect to participants' interests) for such Global Notes or by participants or persons that hold interests through participants (with respect to beneficial interests of persons other than participants). The laws of some jurisdictions may require that certain purchasers of securities take physical delivery of such securities in definitive form. Such limits and laws may impair the ability to transfer or pledge beneficial interests in the Global Notes. So long as DTC, or its nominee, is the registered holder of the Global Notes, DTC or such nominee, as the case may be, will be considered the sole legal owner and holder of the Exchange Senior Notes represented by such Global Notes for all purposes under the Indenture and the Exchange Senior Notes. Except as set forth below, owners of beneficial interests in the Global Notes will not be entitled to have such Global Notes or any Exchange Senior Notes represented thereby registered in their names, will not receive or be entitled to receive physical delivery or certificated Exchange Senior Notes in exchange therefor and will not be considered to be the owners or holders of such Global Notes or any Notes represented thereby for any purpose under the Exchange Senior Notes or the Indenture. We understand that under existing industry practice, in the event an owner of a beneficial interest in a Global Note desires to take any action that DTC, as the holder of such Global Notes, is entitled to take, DTC would authorize the participants to take such action, and that the participants would authorize beneficial owners owning through such participants to take such action or would otherwise act upon the instructions of beneficial owners owning through them. Any payment of principal or interest due on the Exchange Senior Notes on any interest payment date or at maturity will be made available by us to the Trustee by such date. As soon as possible thereafter, the Trustee will make such payments to DTC or its nominee, as the case may be, as the registered owner of the Global Notes representing such Exchange Senior Notes in accordance with existing arrangements between the Trustee and DTC. We expect that DTC or its nominee, upon receipt of any payment of principal or interest in respect of the Global Notes will credit immediately the accounts of the related participants with payments in amounts proportionate to their respective beneficial interests in the principal amount of such Global Notes as shown on the records of DTC. We also expect that payments by participants to owners of beneficial interests in the Global Notes held through such participants will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers in bearer form or registered in "street name," and will be the responsibility of such participants. None of us, the Trustee or any payment agent for the Global Notes will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests or for other aspects of the relationship between DTC and its participants or the relationship between such participants and the owners of beneficial interests in the Global Notes owning through such participants. Because of time zone differences, the securities account of a Euroclear participant purchasing an interest in a Global Note from a DTC participant will be credited, and any such crediting will be reported to the relevant Euroclear participant, during the securities settlement processing day (which must be a business day 76 for Euroclear) immediately following the DTC settlement date. Cash received in Euroclear as a result of sales of interests in a Global Note by or through a Euroclear participant to a DTC participant will be received with value on the DTC settlement date but will be available in the relevant Euroclear cash account only as of the business day following settlement in DTC. Unless and until exchanged in whole or in part for Exchange Senior Notes in definitive form in accordance with the terms of the Exchange Senior Notes, the Global Notes may not be transferred except as a whole by DTC to a nominee of DTC or by a nominee of DTC to DTC or another nominee of DTC or by DTC or any such nominee to a successor of DTC or a nominee of each successor. Although DTC has agreed to the foregoing procedures in order to facilitate transfers of interests in the Global Notes among participants of a Book Entry Facility, it is under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued at any time. None of us or the Trustee will have any responsibility for the performance by a Book Entry Facility or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations. We and the Trustee may conclusively rely on, and shall be protected in relying on, instructions from a Book Entry Facility for all purposes. CERTIFICATED NOTES The Global Notes shall be exchangeable for corresponding Exchange Senior Notes in certificated fully registered form ("Certificated Notes") registered in the name of persons other than DTC or its nominee only if (A) DTC (i) notifies us that it is unwilling or unable to continue as depositary for the Global Note and we fail to appoint a successor depository within 90 days after receipt of such notice or (ii) at any time ceases to be a clearing agency registered under the Exchange Act, and we fail to appoint a successor depository within 90 days after we became aware of such cessation or (B) there shall have occurred and be continuing an Event of Default (as defined in the Indenture) or any event which after notice or lapse of time or both would be an Event of Default under the Indenture and payment of principal and interest has been accelerated. Any Certificated Notes will be issued only in fully registered form, and shall be issued without coupons in denominations of $1,000 and integral multiples thereof. Any Certificated Notes so issued will be registered in such names and in such denominations as DTC shall request. THE CLEARING SYSTEM DTC has advised us as follows: DTC is a limited-purpose trust company organized under the laws of the State of New York, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code, and "a clearing agency" registered pursuant to the provisions of section 17A of the Exchange Act. DTC was created to hold securities of institutions that have accounts with its participants and to facilitate the clearance and settlement of securities transactions among its participants in such securities through electronic book-entry changes in accounts of participants, thereby eliminating the need for physical movement of securities certificates. DTC's participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. Access to DTC's book-entry system is also available to others such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, whether directly or indirectly. THE TRUSTEE The Bank of New York is the trustee under the Indenture. GOVERNING LAW The Indenture and the Senior Notes are governed by, and construed in accordance with, the laws of the State of New York. 77 MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS The following is a general discussion of the material U.S. federal income tax considerations relevant to the exchange of Original Senior Notes for Exchange Senior Notes pursuant to the Exchange Offer. This discussion is based upon currently existing provisions of the Internal Revenue Code of 1986, as amended (the "Code"), Treasury regulations promulgated thereunder, and administrative and judicial interpretations thereof, all as in effect on the date hereof and all of which are subject to change, possibly on a retroactive basis. There can be no assurance that the Internal Revenue Service will not take positions contrary to those taken in this discussion, and no ruling from the Internal Revenue Service has been or will be sought. This discussion does not address all of the U.S. federal income tax considerations that may be important to holders of the Original Senior Notes in light of their individual circumstances, nor does it address the U.S. federal income tax considerations that may be important to holders subject to special rules, including banks and other financial institutions, insurance companies, tax-exempt entities, dealers in securities or foreign currencies, partnerships or other entities classified as partnerships for U.S. federal income tax purposes, certain former citizens or former long-term residents of the United States, hybrid entities, persons holding the Original Senior Notes as part of a hedging or conversion transaction or a straddle, or holders that are U.S. persons, as defined by the Code, that have a functional currency other than the U.S. dollar. Beneficial owners of the Original Senior Notes are urged to consult their own tax advisors as to the particular U.S. federal income tax law consequences to them of exchanging Original Senior Notes for Exchange Senior Notes, as well as the tax consequences under state, local, foreign, and other tax laws, and the possible effects of changes in tax laws. The exchange of Original Senior Notes for Exchange Senior Notes pursuant to the Exchange Offer will not be treated as an "exchange" for U.S. federal income tax purposes. A holder that exchanges Original Senior Notes for Exchange Senior Notes pursuant to the Exchange Offer will not recognize taxable gain or loss on such exchange, such holder's adjusted tax basis in the Exchange Senior Notes will be the same as its adjusted tax basis in the Original Senior Notes exchanged therefor immediately before such exchange, and such holder's holding period for the Exchange Senior Notes will include the holding period for the Original Senior Notes exchanged therefor. There will be no U.S. federal income tax consequences to holders that do not exchange their Original Senior Notes pursuant to the Exchange Offer. 78 RATINGS Moody's Investors Service, Inc., Standard and Poor's Ratings Services and Fitch Ratings have assigned the Exchange Senior Notes the ratings set forth under "SUMMARY OF THE OFFERING -- Ratings." Such ratings reflect only the views of these organizations, and an explanation of the significance of each such rating may be obtained from Moody's Investors Service, Inc., 99 Church Street, New York, New York 10007, Standard & Poor's Ratings Services, 55 Water Street, New York, New York 10004 and Fitch Ratings, One State Street Plaza, New York, New York 10004. There is no assurance that such rating will continue for any given period of time or that they will not be revised downward or withdrawn entirely by such rating agencies or either of them, if, in their judgment, circumstances so warrant. A downward change in or withdrawal of such ratings by any of them may have an adverse effect on the market price of the Exchange Senior Notes. PLAN OF DISTRIBUTION Each broker-dealer that receives Exchange Senior Notes for its own account pursuant to the Exchange Offer must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Senior Notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Senior Notes received in exchange for Original Senior Notes where such Original Senior Notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a 270-day period following the consummation of the Exchange Offer, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until December 29, 2002, all dealers effecting transactions in the Exchange Senior Notes may be required to deliver a prospectus. We will not receive any proceeds from any sale of Exchange Senior Notes by broker-dealers. Exchange Senior Notes received by broker-dealers for their own account as a result of the Exchange Offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the Exchange Senior Notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to the prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such Exchange Senior Notes. Any broker-dealer that resells Exchange Senior Notes that were received by it for its own account pursuant to the Exchange Offer and any broker or dealer that participates in a distribution of such Exchange Senior Notes may be deemed to be an "underwriter" within the meaning of the Securities Act, and any profit on any such resale of Exchange Senior Notes and any commissions or concessions received by any of these persons may be deemed to be underwriting compensation under the Securities Act. The Letter of Transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. For a period of 270 days following the consummation of the Exchange Offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the Letter of Transmittal. We have agreed to pay all expenses incident to this Exchange Offer (including the expenses of one counsel for the holder of the Exchange Senior Notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the Exchange Senior Notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act. EXPERTS The financial statements of Southern Power Company as of December 31, 2001 and for the period from January 8, 2001 (inception) through December 31, 2001 and Plant Dahlberg (a wholly-owned carve-out entity of Georgia Power Company), as of and for the seven month period ended July 31, 2001, as of and for the year ended December 31, 2000 and for the year ended December 31, 1999 included in this prospectus have 79 been audited by Deloitte & Touche LLP, independent auditors, as stated in their reports appearing herein. We have included our financial statements in this prospectus and elsewhere in the Registration Statement of which this prospectus forms a part in reliance on Deloitte & Touche LLP's reports (which report on Plant Dahlberg expresses an unqualified opinion and includes an explanatory paragraph referring to the carve-out from Georgia Power Company), given on their authority as experts in accounting and auditing. INDEPENDENT ENGINEER The Independent Engineer's Report included as Annex A to this prospectus has been prepared by R.W. Beck and is included in this prospectus in reliance upon the authority of R.W. Beck and its affiliates as experts in the review of the design and operation of electric generating facilities and the preparation of financial projections. INDEPENDENT MARKET EXPERT The Independent Market Expert's Report included as Annex B to this prospectus has been prepared by PA Consulting and is included in this prospectus in reliance upon the authority of that firm as experts in the analysis of power markets, including future market demand, future market prices for electric energy and capacity and related matters, for electric generating facilities. LEGAL MATTERS The validity of the Exchange Senior Notes will be passed upon for us by Balch & Bingham LLP, Birmingham, Alabama, our counsel, relying on the opinion of Dewey Ballantine LLP, New York, New York, with respect to matters of New York law. 80 INDEX TO FINANCIAL STATEMENTS
PAGE ---- SOUTHERN POWER COMPANY Condensed Consolidated Balance Sheets as of June 30, 2002 and December 31, 2001 (Unaudited)......................... F-2 Condensed Consolidated Statements of Income for the Six-Month Periods Ended June 30, 2002 and 2001 (Unaudited)............................................... F-3 Condensed Consolidated Statement of Stockholder's Equity for the Six-Month Period Ended June 30, 2002 (Unaudited)...... F-4 Condensed Consolidated Statements of Comprehensive Income (Loss) for the Six-Month Periods Ended June 30, 2002 and 2001 (Unaudited).......................................... F-5 Condensed Consolidated Statements of Accumulated Other Comprehensive Income (Loss) (Unaudited) as of June 30, 2002 and December 31, 2001................................ F-5 Condensed Consolidated Statements of Cash Flows for the Six-Month Periods Ended June 30, 2002 and 2001 (Unaudited)............................................... F-6 Notes to Condensed Consolidated Financial Statements (Unaudited) for the Six-Month Periods Ended June 30, 2002 and 2001.................................................. F-7 Independent Auditors' Report................................ F-10 Consolidated Balance Sheet as of December 31, 2001.......... F-11 Consolidated Statement of Income for the Period from January 8, 2001 (Inception) to December 31, 2001.................. F-12 Consolidated Statement of Stockholder's Equity for the Period from January 8, 2001 (Inception) to December 31, 2001...................................................... F-13 Consolidated Statement of Comprehensive Income for the Period from January 8, 2001 (Inception) to December 31, 2001...................................................... F-14 Consolidated Statement of Cash Flows for the Period from January 8, 2001 (Inception) to December 31, 2001.......... F-15 Notes to Consolidated Financial Statements.................. F-16 PLANT DAHLBERG (A WHOLLY OWNED CARVE-OUT ENTITY OF GEORGIA POWER COMPANY) Independent Auditors' Report................................ F-28 Balance Sheets as of July 31, 2001 and December 31, 2000.... F-29 Statements of Income for the Six Months Ended June 30, 2001 (unaudited), the Seven Months Ended July 31, 2001 and Year Ended December 31, 2000................................... F-30 Statements of Cash Flows for the Six Months Ended June 30, 2001 (unaudited), the Seven Months Ended July 31, 2001, and the Years Ended December 31, 2000 and 1999............ F-31 Notes to Financial Statements............................... F-32
F-1 SOUTHERN POWER COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
JUNE 30, 2002 DECEMBER 31, 2001 ------------- ----------------- (IN THOUSANDS, EXCEPT SHARE AMOUNTS) ASSETS CURRENT ASSETS: Cash and cash equivalents................................. $ 5,361 $ 3,711 Receivables: Accounts receivable..................................... 8,083 3,416 Affiliated companies.................................... 35,256 1,965 Derivative instruments.................................... 3,656 9,208 Fossil fuel stock, at average cost........................ 3,083 3,425 Materials and supplies, at average cost................... 5,068 5,731 Prepayments............................................... 74 183 ---------- -------- Total current assets................................ 60,581 27,639 ---------- -------- PROPERTY, PLANT, AND EQUIPMENT.............................. 886,239 265,153 LESS ACCUMULATED DEPRECIATION............................... (8,775) (3,291) ---------- -------- 877,464 261,862 CONSTRUCTION WORK IN PROGRESS............................... 729,841 500,358 ---------- -------- Total property, plant, and equipment, net........... 1,607,305 762,220 DERIVATIVE INSTRUMENTS...................................... -- 9,059 DEFERRED INCOME TAXES....................................... 30,698 11,915 OTHER DEFERRED CHARGES...................................... 15,168 12,024 ---------- -------- Total Assets........................................ $1,713,752 $822,857 ========== ======== LIABILITIES AND STOCKHOLDER'S EQUITY CURRENT LIABILITIES: Note payable to parent.................................... $ 186,342 $ 950 Accounts payable: Affiliated companies.................................... 18,364 26,135 Other................................................... 9,329 4,278 Accrued income taxes payable.............................. 11,174 394 Other..................................................... 2,918 886 ---------- -------- Total current liabilities........................... 228,127 32,643 ---------- -------- LONG-TERM DEBT.............................................. 732,401 293,205 ---------- -------- DEFERRED CREDITS AND OTHER LIABILITIES: Due to affiliated companies............................... 24,332 23,415 Other..................................................... 10,606 6,601 Derivative instruments.................................... 10,362 -- ---------- -------- Total deferred credits and other liabilities............ 45,300 30,016 ---------- -------- Total liabilities......................................... 1,005,828 355,864 ---------- -------- COMMITMENTS AND CONTINGENCIES COMMON STOCKHOLDER'S EQUITY: Common stock, $.01 par value; 1,000,000 shares authorized; 1,000 shares issued and outstanding..................... -- -- Paid-in capital........................................... 705,869 452,097 Accumulated other comprehensive income (loss)............. (19,465) 6,689 Retained earnings......................................... 21,520 8,207 ---------- -------- Total common stockholder's equity....................... 707,924 466,993 ---------- -------- Total Liabilities and Stockholder's Equity.............. $1,713,752 $822,857 ========== ========
See notes to condensed consolidated financial statements. F-2 SOUTHERN POWER COMPANY CONDENSED CONSOLIDATED STATEMENTS OF INCOME FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 2002 AND 2001 (UNAUDITED)
FOR THE SIX MONTHS ENDED JUNE 30, ------------------- 2002 2001 -------- -------- (IN THOUSANDS) OPERATING REVENUES: Electricity sales: Nonaffiliates.......................................... $42,842 $ -- Affiliates............................................. 34,147 -- Other revenues............................................ 87 -- ------- ------- Total operating revenues.......................... 77,076 -- ------- ------- OPERATING EXPENSES: Fuel...................................................... 21,165 -- Purchased power: Nonaffiliates.......................................... 10,725 -- Affiliates............................................. 4,791 -- General and administrative................................ 7,452 1,692 Operations and maintenance................................ 1,821 -- Depreciation.............................................. 5,485 -- Taxes other than income taxes............................. 1,503 -- ------- ------- Total operating expenses.......................... 52,942 1,692 ------- ------- OPERATING INCOME (LOSS)..................................... 24,134 (1,692) OTHER INCOME (LOSS): Interest income........................................... 229 15 Other, net................................................ (1,449) -- ------- ------- Total other income (loss)......................... (1,220) 15 INTEREST EXPENSE, NET....................................... 1,195 1 ------- ------- INCOME (LOSS) BEFORE INCOME TAXES........................... 21,719 (1,678) ------- ------- INCOME TAXES................................................ 8,406 (655) ------- ------- NET INCOME (LOSS)........................................... $13,313 $(1,023) ======= =======
See notes to condensed consolidated financial statements. F-3 SOUTHERN POWER COMPANY CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 2002 (UNAUDITED)
ACCUMULATED COMMON STOCK OTHER --------------- PAID-IN COMPREHENSIVE RETAINED SHARES AMOUNT CAPITAL INCOME (LOSS) EARNINGS TOTAL ------ ------ -------- ------------- -------- -------- (IN THOUSANDS, EXCEPT SHARES) BALANCE, January 1, 2002........ 1,000 $ -- $452,097 $ 6,689 $ 8,207 $466,993 Capital contributions from parent..................... 253,772 253,772 Other comprehensive income (loss)..................... (26,154) (26,154) Net income.................... 13,313 13,313 ----- ---- -------- -------- ------- -------- BALANCE, June 30, 2002.......... 1,000 $ -- $705,869 $(19,465) $21,520 $707,924 ===== ==== ======== ======== ======= ========
See notes to condensed consolidated financial statements. F-4 SOUTHERN POWER COMPANY CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 2002 AND 2001 (UNAUDITED) (IN THOUSANDS)
FOR THE SIX MONTHS ENDED JUNE 30 ------------------ 2002 2001 -------- ------- NET INCOME (LOSS)........................................... $ 13,313 $(1,023) CHANGES IN FAIR VALUE OF QUALIFYING CASH FLOW HEDGES, NET OF TAX OF $(16,572)....................................... (26,154) -- LESS: RECLASSIFICATION ADJUSTMENT FOR AMOUNTS INCLUDED IN NET INCOME, NET OF TAX OF $24............................. 38 -- -------- ------- COMPREHENSIVE INCOME (LOSS)................................. $(12,803) $(1,023) ======== =======
SOUTHERN POWER COMPANY CONDENSED CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (UNAUDITED) (IN THOUSANDS)
AT AT JUNE 30, DECEMBER 31, 2002 2001 ----------- ------------ Balance at beginning of period.............................. $ 6,689 $ -- Change in current period.................................... (26,154) 6,689 -------- ------- TOTAL ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)......... $(19,465) $ 6,689 ======== =======
See notes to condensed consolidated financial statements. F-5 SOUTHERN POWER COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 2002 AND 2001 (UNAUDITED) (IN THOUSANDS)
FOR THE SIX MONTHS ENDED JUNE 30, --------------------- 2002 2001 --------- --------- OPERATING ACTIVITIES: Net income (loss)......................................... $ 13,313 $ (1,023) Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and Amortization........................... 6,871 -- Deferred income taxes................................... (1,888) -- Unrealized losses on derivative instruments, net........ 1,960 -- Cash received in excess of levelized revenues............. 5,019 -- Changes in assets and liabilities: Receivables............................................. (37,958) -- Prepayments............................................. 109 (654) Fossil fuel stock....................................... 342 -- Materials and supplies.................................. 663 -- Accounts payable........................................ 17,126 1,693 Accrued income taxes payable............................ 10,780 -- Miscellaneous current and accrued liabilities........... 1,278 -- Prepaid capacity revenues............................... (710) -- --------- --------- Net cash provided from operating activities........ 16,905 16 INVESTING ACTIVITIES: Gross property additions.................................. (853,256) (101,985) Decrease in construction-related payables................. (20,390) -- Deferred project development costs........................ 1,243 -- Acquired premium on derivative instrument................. (1,576) -- --------- --------- Net cash used in investing activities.............. (873,979) (101,985) FINANCING ACTIVITIES: Capital contributions from parent......................... 253,772 99,964 Proceeds from issuance of original senior notes........... 574,189 -- Revolving credit facility................................. 417,000 -- Redemptions of revolving credit facility.................. (552,000) -- Proceeds from subordinated notes payable to parent........ 185,392 10,889 Deferred payable to affiliate............................. 1,049 -- Deferred financing costs.................................. (5,973) -- Settlement of interest rate swap on senior note........... (16,884) -- Other..................................................... 2,179 -- --------- --------- Net cash provided from financing activities........ 858,724 110,853 --------- --------- NET INCREASE IN CASH AND CASH EQUIVALENTS................... 1,650 8,884 CASH AND CASH EQUIVALENTS, beginning of period.............. 3,711 -- --------- --------- CASH AND CASH EQUIVALENTS, end of period.................... $ 5,361 $ 8,884 ========= ========= SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid (received) during the period for interest (net of amount capitalized).................................. $ -- $ -- ========= ========= Cash paid during the period for income taxes.............. $ 724 $ -- ========= =========
See notes to condensed consolidated financial statements. F-6 SOUTHERN POWER COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 2002 AND 2001 A. The Company has prepared the condensed consolidated financial statements included herein, without audit, pursuant to the rules and regulations of the SEC. In the opinion of management, the information furnished herein reflects all adjustments necessary to present fairly the results of operations for the periods ended June 30, 2002 and 2001. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations, although management believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Therefore, it is suggested that these condensed financial statements be read in conjunction with the Company's consolidated financial statements as of and for the period from January 8, 2001 (inception) to December 31, 2001 and the notes thereto included herein. Due to seasonal variations in the demand for energy, operating results for the period presented do not necessarily indicate operating results for the entire year. B. In January 2002, Georgia Power Company transferred the Plant Wansley combined cycle facility under construction to the Company. In accordance with the Affiliate Transaction Rule of the Public Utility Holding Company Act of 1935 the plant was transferred at Georgia Power Company's net carrying cost of ($389.9 million) and recorded as construction work in progress in the accompanying condensed consolidated balance sheet. Included in the carrying costs for Wansley were $1.6 million in derivative assets relating to electric and gas forward positions in effect at the date of the transfer. Such forward contracts were recorded at fair value on the date of transfer which was equal to Georgia Power Company's carrying amount. Following the transfer, these contracts are marked to market until realized and settled. See Note 2, "Asset Transfers and Construction Program," in the notes to the Consolidated Financial Statements herein. C. In 2002, the Company executed additional long-term power sales agreements whereby the Company will sell capacity and energy from planned generating facilities. These contracts begin in 2005 and are subject to regulatory approval. These respective obligations are described below:
BEGINNING FACILITIES PLANNED MEGAWATTS DATE END DATE - ------------------ --------- --------- -------- Franklin 3............................................ 615 6/1/05 5/31/30 McIntosh 10 and 11.................................... 1,040 6/1/05 5/31/19 200 6/1/05 5/31/19
Under these contracts, we have the right, at our sole discretion, to supply capacity and energy under these arrangements from any resource available to us as part of the Southern Pool. See Note 7, "Long-Term Power Sales Contracts," in the notes to the Consolidated Financial Statements. D. In 2002, we executed agreements to coordinate the generating resources and meet the additional capacity requirements ("Requirement Agreements") of 11 Georgia Electric Membership Corporations ("EMCs"). These Requirement Agreements went into effect in June 2002. Under these agreements, both the loads and the resources of the EMCs will be integrated into the Southern Pool. E. On June 18, 2002, we issued $575 million of 6.25% Senior Notes, Series A due July 15, 2012. The proceeds of the issue were used to reduce the amount outstanding of the revolving credit facility and note payable to Southern. F. During 2002, the Company created several wholly owned subsidiaries as limited liability companies for the purchase of land, land options and development of potential sites for future generating units. G. Effective June 1, 2002, the Company changed Plant Dahlberg's estimated useful life from 35 to 40 years, resulting in a $79,000 monthly decrease in depreciation expense. The change is the result of a F-7 recent actuarial study that estimated the useful life of a gas turbine electric generating unit to be at least 40 years. The Company continues to depreciate combined-cycle electric generating facilities over 35 years. H. Southern has committed to directly fund 40% of the construction costs of the facilities funded under the revolving credit facility. In addition, Southern has guaranteed the timely completion of Company projects currently financed under a revolving credit facility. In this guarantee, Southern agrees to pay for cost overruns to the extent that the Company's own cash flow is insufficient. Southern also agrees to prepay any portion of the credit facility used for Company projects not completed within two years of the proposed projects' completion dates. At June 30, 2002, the outstanding amount of this revolving credit facility related to projects under construction was $158 million. I. Certain keep-well agreements were created to facilitate the assignment of specific partially executory vendor contracts to the Company. As of June 30, 2002, Southern keep-well agreements were in place to facilitate the transfer of specific vendor contracts from Alabama Power Company to the Company related to the Harris construction. Southern keep-wells are also in place for the transfer of specific vendor contracts from Georgia Power Company to the Company for the operation of Plant Dahlberg and construction at the Franklin and Stanton sites. As of June 30, 2002, the keep-well agreements have an estimated value of $32.6 million related to the Georgia Power Company contracts. Certain other keep-well arrangements were entered into in order to enhance the efficiency and flexibility of the energy sales and related natural gas procurements function. Acting as agent for Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company and Savannah Electric and Power Company (collectively, the "Operating Companies") and the Company under agency agreements ("Agreements"), Southern Company Services, Inc. ("SCS") may enter into various types of wholesale energy and natural gas contracts. Under such Agreements, each of the Operating Companies may be jointly and severally liable for the obligations of each of the other Operating Companies and the Company. In that regard, the creditworthiness of the Company is currently inferior to the creditworthiness of the other Operating Companies. To insure that such other Operating Companies will not subsidize or be responsible for any costs, losses, liabilities or damages arising out of or resulting from the Company's inclusion as a contracting party under the Agreements, Southern has entered into a keep-well agreement with each of the other Operating Companies. Based on the Company's share of natural gas and wholesale energy purchase commitments, Southern's maximum exposure under the Agreements was $36.8 million as of June 30, 2002. J. As the Company has no employees, all employee-related charges are rendered at cost under agreements with SCS or the Operating Companies. Costs for these services amounted to approximately $13.1 million for the period ended June 30, 2002, of which approximately $5.7 million is included in general and administrative expenses in the accompanying statements of income; the remainder was capitalized to construction work in progress. Southern Power has an agreement with Georgia Power Company to provide operation and maintenance services for Plants Dahlberg, Wansley and Franklin. These services are billed at cost on a monthly basis and are recorded as operations and maintenance expense in the accompanying statements of income. For the period ended June 30, 2002, these services totaled approximately $1.6 million. K. Project costs for Plant Wansley (Units 6 & 7) and Plant Franklin (Unit 1), which were placed in service on June 1, 2002, reflect the recording of revenues and cost during the test period for these units. Revenues for test period generation charged to the project were approximately $25.2 million and total costs were approximately $27.3 million. Additionally, in accordance with Financial Accounting Standard No. 133, gains and losses on electric and gas forward contracts related to these units that were realized during the test period were charged to Other Comprehensive Income. F-8 L. In addition to the fixed price electric and gas contracts used to mitigate exposure to volatile energy prices (see "Market Price Risk" in MANAGEMENT'S DISCUSSION AND ANALYSIS), the Company has entered into interest rate swaps to hedge exposure to interest rate changes. These swaps related to forecasted issuances of long-term debt and are accounted for as cash flow hedges. The swaps were structured to mirror the terms of the hedged debt instruments; therefore, no ineffectiveness has been recorded in earnings. As of June 30, 2002, the following swaps were outstanding: CASH FLOW HEDGES
WEIGHTED AVERAGE FAIR VALUE NOTIONAL VARIABLE RATE FIXED RATE MATURITY JUNE 30, 2002 AMOUNT RECEIVED PAID DATE (INCLUDED IN OCI) -------- ------------- ---------- --------- ----------------- $350 million 1-month LIBOR 6.2348% June 2013 $(9,755,000) $100 million 1-month LIBOR 6.1863% June 2008 $(3,557,000)
For the six month period ended June 30, 2002, approximately $0.1 million was reclassified from other comprehensive income to interest expense. For the 12-month period ended June 2003, approximately $1.7 million is expected to be reclassified. M. See Note 10, "Contingencies," in the notes to the Consolidated Financial Statements herein for information regarding a dispute with a former contractor at Plants Wansley and Franklin. This dispute and the related lien was settled in July 2002 for a total of $6.9 million. The payment will be capitalized as a cost of the plants. N. General and administrative expenses included the write-off in May 2002 of $2.9 million in previously deferred site investigation and development costs, such that certain amounts billed by SCS that were previously capitalized as project development costs are being expensed as incurred. Effective May 2002, the Company modified its policy regarding deferred project development costs, such that certain amounts billed by SCS that were previously capitalized as project development costs are being expensed as incurred. See Note 1 to the consolidated financial statements where deferred project development costs are described. F-9 INDEPENDENT AUDITORS' REPORT To Southern Power Company: We have audited the accompanying consolidated balance sheet of Southern Power Company and subsidiary (the "Company") as of December 31, 2001 and the related consolidated statements of income, stockholder's equity, comprehensive income, and cash flows for the period from January 8, 2001 (inception) to December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, such financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2001 and the results of its operations and its cash flows for the period from January 8, 2001 (inception) to December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Atlanta, Georgia May 31, 2002 F-10 SOUTHERN POWER COMPANY CONSOLIDATED BALANCE SHEET DECEMBER 31, 2001 (IN THOUSANDS, EXCEPT SHARE AMOUNTS) ASSETS CURRENT ASSETS: Cash and cash equivalents................................. $ 3,711 Receivables: Accounts receivable..................................... 3,416 Affiliated companies.................................... 1,965 Derivative instruments (Note 3)........................... 9,208 Fossil fuel stock, at average cost........................ 3,425 Materials and supplies, at average cost................... 5,731 Prepayments............................................... 183 -------- Total current assets............................... 27,639 -------- PROPERTY, PLANT AND EQUIPMENT............................... 265,153 LESS ACCUMULATED DEPRECIATION............................... (3,291) -------- 261,862 CONSTRUCTION WORK IN PROGRESS............................... 500,358 -------- Total property, plant, and equipment, net.......... 762,220 DERIVATIVE INSTRUMENTS (Note 3)............................. 9,059 DEFERRED INCOME TAXES, NET.................................. 11,915 OTHER DEFERRED CHARGES...................................... 12,024 -------- Total Assets....................................... $822,857 ======== LIABILITIES AND STOCKHOLDER'S EQUITY CURRENT LIABILITIES: Note payable to parent.................................... $ 950 Accounts payable: Affiliated companies.................................... 26,135 Other................................................... 4,278 Accrued income taxes payable.............................. 394 Other..................................................... 886 -------- Total current liabilities.......................... 32,643 -------- LONG-TERM DEBT (Note 9)..................................... 293,205 -------- DEFERRED CREDITS AND OTHER LIABILITIES: Due to affiliated companies (Notes 1 and 8)............... 23,415 Other..................................................... 6,601 -------- Total deferred credits and other liabilities....... 30,016 -------- Total liabilities.................................. 355,864 -------- COMMITMENTS AND CONTINGENCIES (Notes 2, 3, 4, 5, and 10) STOCKHOLDER'S EQUITY: Common stock, $.01 par value; 1,000,000 shares authorized; 1,000 shares issued and outstanding in 2001............. -- Paid-in capital........................................... 452,097 Accumulated other comprehensive income.................... 6,689 Retained earnings......................................... 8,207 -------- Total stockholder's equity......................... 466,993 -------- Total Liabilities and Stockholder's Equity......... $822,857 ========
See notes to consolidated financial statements. F-11 SOUTHERN POWER COMPANY CONSOLIDATED STATEMENT OF INCOME FOR THE PERIOD FROM JANUARY 8, 2001 (INCEPTION) TO DECEMBER 31, 2001 (IN THOUSANDS) OPERATING REVENUES: Electricity sales: Nonaffiliates.......................................... $26,390 Affiliates............................................. 2,906 Other revenues............................................ 5 ------- Total operating revenues.......................... 29,301 ------- OPERATING EXPENSES: Fuel...................................................... 3,779 Purchased power: Nonaffiliates.......................................... 1,209 Affiliates............................................. 3,517 General and administrative................................ 5,615 Operations and maintenance................................ 1,010 Depreciation.............................................. 3,291 Taxes, other than income taxes............................ 393 ------- Total operating expenses.......................... 18,814 ------- OPERATING INCOME............................................ 10,487 OTHER INCOME: Interest income........................................... 78 Other, net................................................ 580 ------- Total other income................................ 658 INTEREST EXPENSE, NET....................................... 427 ------- INCOME BEFORE INCOME TAXES.................................. 10,718 INCOME TAXES (Note 8)....................................... 2,511 ------- NET INCOME.................................................. $ 8,207 =======
See notes to consolidated financial statements. F-12 SOUTHERN POWER COMPANY CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY FOR THE PERIOD FROM JANUARY 8, 2001 (INCEPTION) TO DECEMBER 31, 2001
ACCUMULATED COMMON STOCK OTHER --------------- PAID-IN COMPREHENSIVE RETAINED SHARES AMOUNT CAPITAL INCOME EARNINGS TOTAL ------ ------ -------- ------------- -------- -------- (IN THOUSANDS, EXCEPT SHARES) BALANCE, January 8, 2001 (Inception).................... -- $ -- $ -- $ -- $ -- $ -- Initial capitalization......... 1,000 -- -- Capital contributions from parent...................... 452,097 452,097 Other comprehensive income..... 6,689 6,689 Net income..................... 8,207 8,207 ----- ----- -------- ------ -------- -------- BALANCE, December 31, 2001....... 1,000 $ -- $452,097 $6,689 $ 8,207 $466,993 ===== ===== ======== ====== ======== ========
See notes to consolidated financial statements. F-13 SOUTHERN POWER COMPANY CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME FOR THE PERIOD FROM JANUARY 8, 2001 (INCEPTION) TO DECEMBER 31, 2001 (IN THOUSANDS) NET INCOME.................................................. $ 8,207 CHANGES IN FAIR VALUE OF QUALIFYING CASH FLOW HEDGES, NET OF TAX OF $4,219.......................................... 6,689 ------- COMPREHENSIVE INCOME........................................ $14,896 =======
See notes to consolidated financial statements. F-14 SOUTHERN POWER COMPANY CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE PERIOD FROM JANUARY 8, 2001 (INCEPTION) TO DECEMBER 31, 2001 (IN THOUSANDS) OPERATING ACTIVITIES: Net income................................................ $ 8,207 Adjustments to reconcile net income to net cash provided from operating activities: Depreciation and amortization.......................... 3,291 Deferred income taxes.................................. 3,534 Unrealized gains on derivative instruments, net........ (580) Changes in assets and liabilities: Receivables............................................ (5,381) Prepayments............................................ (183) Fossil fuel stock...................................... (3,425) Materials and supplies................................. (5,731) Accounts payables...................................... 2,242 Accrued income taxes payable........................... 394 Prepaid capacity revenues.............................. 4,255 Cash revenues in excess of levelized revenues.......... 1,731 Other.................................................. 250 --------- Net cash provided from operating activities....... 8,604 --------- INVESTING ACTIVITIES: Gross property additions.................................. (765,511) Increase in construction-related payables................. 28,171 Deferred project development costs........................ (4,509) Acquired derivative assets................................ (5,617) --------- Net cash used in investing activities............. (747,466) --------- FINANCING ACTIVITIES: Capital contributions..................................... 452,097 Long-term debt............................................ 293,205 Note payable to parent.................................... 950 Deferred financing costs.................................. (7,306) Deferred payable to affiliate............................. 3,792 Other..................................................... (165) --------- Net cash provided from financing activities....... 742,573 --------- NET INCREASE IN CASH AND CASH EQUIVALENTS................... 3,711 CASH AND CASH EQUIVALENTS, beginning of period.............. -- --------- CASH AND CASH EQUIVALENTS, end of period.................... $ 3,711 ========= SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid during the period for interest (net of amount capitalized)........................................... $ 427 ========= Cash received during the period for income taxes.......... $ (423) =========
See notes to consolidated financial statements. F-15 SOUTHERN POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2001 1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization -- Southern Power Company ("Southern Power") is a wholly owned subsidiary of Southern Company ("Southern"). Southern Power created a wholly owned subsidiary, Southern Company Florida-LLC ("SCF") to own, operate and maintain Plant Stanton Unit A, a jointly owned generating facility. See Note 6, Joint Ownership Agreements for further information. Southern Power and its subsidiary were established to construct, own, and manage Southern's competitive contract-based wholesale generation assets which operate outside of traditional state regulation, and to sell electricity at market-based rates in the wholesale market. Southern Power provides energy and capacity to various third-party purchasers and affiliates under long-term contracts. Southern is the parent company of five operating companies, Southern Company Services ("SCS"), Southern Communications Services ("Southern LINC"), Southern Nuclear Operating Company ("Southern Nuclear"), Southern Power, and other direct and indirect subsidiaries. The operating companies, consisting of Alabama Power Company ("APC"), Georgia Power Company ("GPC"), Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company (collectively, the "Operating Companies") provide electric service in four southeastern states. Contracts among the Operating Companies and Southern Power, including those related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power, are regulated by the Federal Energy Regulatory Commission ("FERC") and/or the Securities and Exchange Commission ("SEC"). SCS provides, at cost, specialized services to Southern Company and subsidiary companies. Southern Nuclear provides services to Southern's nuclear power plants. Southern is registered as a holding company under the Public Utility Holding Company Act of 1935, as amended ("PUHCA"). Southern, Southern Power, and the Operating Companies are subject to the regulatory provisions of PUHCA. Southern Power is also subject to regulation by the FERC. Formation of Southern Power and Initiation of Commercial Operations -- Southern Power was formed on January 8, 2001. Southern Power began commercial operations in August 2001 after GPC transferred its interest in Plant Dahlberg Units 1 through 10. See Note 2, Asset Transfers and Construction Program, for further information regarding asset transfers from affiliates. Basis of Presentation -- The consolidated financial statements of Southern Power present the historical financial position as of December 31, 2001 and results of operations and cash flows for the period from January 8, 2001 (inception) through December 31, 2001, which have been prepared in accordance with accounting principles generally accepted in the United States of America ("generally accepted accounting principles"). The results of operations of the Plant Dahlberg assets (Note 2) are incorporated into Southern Power's consolidated results of operations beginning August 1, 2001. Principles of Consolidation -- The consolidated financial statements include the accounts of Southern Power and its wholly owned subsidiary, SCF. All intercompany accounts and transactions have been eliminated in consolidation. Related Party and Affiliate Transactions -- Southern Power along with the Operating Companies are members of and share the benefits and obligations of the Southern system power pool ("Southern Pool"). The Southern Pool is operated by SCS. As a member of the Southern Pool, Southern Power's units will be economically dispatched with the generating facilities of the Operating Companies to serve the members' aggregate load requirements. A member of the Southern Pool has the first call on its own generating resources, but if lower cost generation resources are available within the Southern system, a Southern Pool member has the right to purchase that lower variable cost energy to satisfy its obligations. Additionally, if a Southern Pool member is unable to generate sufficient capacity and energy to meet its obligations, it can buy F-16 power from the Southern Pool at the marginal energy cost. The Southern Pool is governed by the Intercompany Interchange Contract ("IIC"), which has been approved by the FERC. Southern Power has an agreement with SCS under which the following services are rendered to Southern Power at cost: Southern Pool operations, construction, general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and pensions, human resources, systems and procedures, and other services with respect to business operations and power pool management. SCS also enters into fuel purchase and transportation arrangements and contracts, financial instruments for purposes of hedging, and wholesale energy purchase and sale transactions for the benefit of Southern Power. As Southern Power has no employees, all employee related charges are rendered at cost under agreements with SCS or the Operating Companies. Costs for these services from SCS amounted to approximately $12 million for the period ended December 31, 2001, of which approximately $4.7 million was general and administrative expenses; the remainder was capitalized to construction work in progress. Southern Power has an agreement with GPC to provide operation and maintenance services for Plant Dahlberg. These services are billed at cost on a monthly basis and are recorded as operations and maintenance expense in the accompanying statements of income. For the period ended December 31, 2001, these services totaled approximately $1.0 million. Additionally, Southern Power has agreements with APC and GPC to provide procurement, payables, and other accounting functions related to the construction at Plants Harris and Goat Rock in Alabama and Plant Wansley in Georgia. Cost for these services are billed monthly. Southern Power sells the output of its generating assets under long-term, market-based contracts both to unaffiliated wholesale purchasers as well as the Operating Companies (under power purchase agreements approved by the respective public service commissions). Southern Power and its affiliates generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity. See Notes 2, 3, 4, 6, and 9 for additional discussion of certain related party and affiliate transactions. Revenues -- Revenues include capacity and energy sales and are recorded based on output and energy delivery. Capacity is sold at rates specified under contractual terms, and is recognized on a levelized basis over the respective contract periods. Energy is generally sold at market-based rates and is recognized as delivered. Significant portions of Southern Power's revenues have been derived from certain customers. LG&E Energy Marketing, Inc. and Dynegy Power Marketing Inc. accounted for approximately 66% and 21% of revenues, respectively, for the period ended December 31, 2001. The Emerging Issues Task Force ("EITF") is currently addressing the question of how to determine whether an arrangement, including purchase power agreements, constitutes a lease within the scope of Statement of Financial Accounting Standards ("SFAS") No. 13, in Issue 01-08, Determining Whether an Arrangement is a Lease. Final conclusions reached by the EITF may impact the consolidated financial statements of Southern Power; however, such impact cannot yet be determined. Fuel Costs -- Fuel costs are expensed as the fuel is consumed. Depreciation -- Depreciation of the original cost of assets is computed under the straight-line method based on the assets' estimated useful lives determined by Southern Power. The primary asset in property, plant and equipment is a power plant which has an estimated useful life of 35 years. Income Taxes -- Southern Power uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Additionally, Southern Power joins in the filing of a consolidated federal income tax return by Southern. Southern Power records its tax liabilities as though it was filing separate returns and records tax benefits to the extent that Southern is able to receive those benefits. Southern Power uses the flow-through method of accounting for State of Georgia Manufacturer's Tax Credit. See Note 8, Income Taxes, for additional discussion. F-17 Property, Plant and Equipment -- Property, plant and equipment are stated at original cost. Original cost includes materials, direct labor incurred by affiliated companies, minor items of property, and appropriate administrative costs. Interest is capitalized on qualifying projects during the development and construction period. For the period ended December 31, 2001, approximately $2.9 million of interest was capitalized in connection with the development and construction of power plants. Upon commencement of plant operations, capitalized interest is amortized over the estimated useful life of the plant. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred. The cost of replacements of property that extend the useful life of the plant, exclusive of minor items of property, is capitalized. Construction work in progress is recorded at cost, which includes materials, direct labor incurred by affiliated companies, appropriate administrative costs, and capitalized interest. Fair Values -- SFAS No. 107, Disclosures About Fair Value of Financial Instruments, requires the disclosure of the fair value of all financial instruments. At December 31, 2001, financial instruments recorded at contractual amounts that approximate market or fair value include cash and cash equivalents, accounts receivable, accounts payable and variable rate debt. The market values of such items are not materially sensitive to shifts in market interest rates because of the limited term to maturity of many of these instruments and/or their variable interest rates. Impairment of Long-Lived Assets -- Long-lived assets held and used by Southern Power are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared to the carrying value of the assets. If the carrying amount of the asset exceeds the expected future cash flows expected to be generated by the asset, an impairment loss is recognized, and the asset is written down to its estimated fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Cash and Cash Equivalents -- For purposes of the consolidated financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Deferred Project Development Costs -- Southern Power capitalizes project development costs once it is determined that it is probable that a specific site will be acquired and a power plant constructed. These costs include professional services, permits and other costs directly related to the construction of a new project. Certain amounts billed by SCS are also capitalized as project development costs as SCS serves in a manner similar to an external third party. These costs are generally transferred to construction work in progress upon commencement of construction. The total deferred project development costs at December 31, 2001 were $4.5 million. Deferred Financing Costs -- Financing costs, consisting primarily of bank fees, legal fees and other direct costs incurred to obtain financing, are deferred and amortized over the financing term. Major Maintenance -- The Company expenses major maintenance costs as incurred. See Note 5, Long Term Service Agreements, for additional discussion. Comprehensive Income -- Southern Power's comprehensive income consists of income and changes in the fair value of qualifying cash flow hedges, net of income taxes. Use of Estimates -- The process of preparing financial statements in conformity with accounting principles generally accepted in the United States of America requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Also, such estimates relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts. The Company's construction program is subject to periodic review and revision. Actual construction costs may vary from estimates because of numerous factors, including, but not limited to, changes in business conditions, load growth estimates, environmental regulations, and regulatory requirements. F-18 The Company, through SCS as its agent, uses derivative financial instruments primarily to hedge exposures to fluctuations in interest rates, foreign currency exchange rates and commodity prices. In measuring the fair value of such instruments, SCS as the Company's agent, uses estimates. Such estimates of fair value are generally based on prevailing market prices and financial models using market data and certain assumptions. The use of different assumptions or estimation methodologies may have a material effect on the estimated fair value amounts. Accordingly, the estimates presented herein are not necessarily indicative of the amount the Company could actually realize as the transactions are terminated or settled. Derivative Instruments -- Southern Power applies SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that companies recognize all derivatives as either assets or liabilities measured at fair value on the statement of financial position. SFAS No. 133 provides an exception for certain contracts that qualify as "normal purchases and sales." To qualify for this exception, certain criteria must be met, including that it must be probable that the contract will result in physical delivery. See Note 3 Financial and Other Derivative Instruments. New Accounting Pronouncements -- Asset Retirement Obligations -- In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 143, Accounting for Asset Retirement Obligations. This statement requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred. The associated asset retirement costs would be capitalized as part of the carrying amount of the long-lived asset and depreciated over the asset's useful life. Changes in the liability resulting from the passage of time will be recognized as operating expenses. It would apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and (or) the normal operation of a long-lived asset. This statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. Southern Power has not yet determined the impact of this statement on its consolidated financial statements. Long-Lived Assets -- In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This statement establishes a single accounting model for long-lived assets to be disposed of by sale, whether previously held and used, or newly acquired. This statement is effective for financial statements issued for fiscal years beginning after December 15, 2001. Southern Power adopted this statement on January 1, 2002, with no impact on the consolidated financial statements. Business Segments -- SFAS No. 131, Disclosures About Segments at an Enterprise and Related Information, require that companies report certain financial and descriptive information about operating segments in their financial statements. Southern Power operates as a single reportable segment, as defined by SFAS No. 131 as the primary vehicle to own, construct, acquire, and manage Southern's competitive, contract-based wholesale generation assets. 2. ASSET TRANSFERS AND CONSTRUCTION PROGRAM On July 31, 2001, GPC transferred its interests in Plant Dahlberg Units 1 through 10 and related working capital to Southern Power. In accordance with the affiliate transaction rules of PUHCA, these assets were transferred at GPC's net carrying costs of $260.1 million. The transferred assets consist primarily of 10 combustion turbine units (810 MW) in operation, all located in Jackson County, Georgia. In connection with the asset transfer, GPC also assigned to Southern Power its interest in three power purchase agreements related to Dahlberg. Southern Power effected the transfer of these assets using equity contributions and subordinated loans from Southern. F-19 The following projects, which were under construction, were transferred from APC and GPC to Southern Power:
TRANSFERRED PLANT FROM DATE AMOUNT - ----- ----------- --------- ------------- (IN MILLIONS) Harris 1 and 2.................................... APC June 2001 $ 91.4 Goat Rock 1 and 2................................. GPC/APC Nov 2001 $267.9 Wansley 6 and 7................................... GPC Jan 2002 $389.9
These assets were recorded by Southern Power at the respective affiliate's book value and are included in construction work in progress in the accompanying consolidated balance sheet at December 31, 2001. The results of operations of Plant Dahlberg are included in the financial statements from August 1, 2001. In conjunction with these transfers, APC and GPC have assigned certain vendor contracts related to the on-going construction of these facilities to Southern Power. Southern has entered into limited keep-well arrangements with APC and GPC whereby Southern will contribute funds to Southern Power via loans or capital contributions to fund the performance of Southern Power as equipment purchaser under certain arrangements. As of December 31, 2001, Southern Power's remaining purchase obligations to equipment vendors totaled $132 million. Southern Power's obligations for construction of transmission interconnection facilities to these plants by APC and GPC totaled $13 million at December 31, 2001, and are also guaranteed by Southern. Additionally, Southern Power is constructing Plant Stanton Unit A, a jointly owned combined cycle facility located near Orlando, Florida. Southern has agreed to grant performance guarantees on behalf of Southern Power and its subsidiary, SCF, for SCF's payment obligations under construction and power purchase agreements associated with the Orlando project. Southern Power's maximum exposure is $53 million under the construction and ownership agreement and $20 million under the power purchase agreement. See Note 6 Joint Ownership Agreements. 3. FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS Southern Power, through SCS as its agent, uses derivative financial instruments to hedge exposures to fluctuations in interest rates, foreign currency exchange rates, and certain commodity prices. Fluctuations in fair market value on qualifying hedges are recorded in other comprehensive income ("OCI") and recognized into income when the underlying transaction settles or the hedge is no longer effective. At December 31, 2001, Southern Power had interest rate swaps with four counterparties related to planned debt issuances in 2002 ($250 million) and 2003 ($200 million), scheduled to coincide with the anticipated in-service date of units under construction. These swaps have been designated as cash flow hedges. There is no ineffectiveness related to these swaps for the period ended December 31, 2001. Southern Power's interest rate swaps have maturity dates between 2012 and 2013. The range of fixed interest rates Southern Power will pay on the swaps are between 5.47% and 6.3%. At December 31, 2001, Southern Power had derivative hedging assets of approximately $11.5 million, $4.3 million current and $7.2 million long-term, with corresponding amounts recorded in OCI ($7 million) and deferred income taxes ($4.5 million) on the accompanying consolidated balance sheet. The fair value of interest rate swaps is determined based on the estimated amount that Southern Power would receive or pay to terminate the swap agreement at the reporting date based on third-party quotations. If it becomes probable that the anticipated transaction will not occur, any deferred gains and losses recorded in accumulated other comprehensive income will be realized into income. Southern Power has firm purchase commitments for equipment that require payment in Euros. As a hedge against fluctuations in the exchange rate for Euros, Southern Power entered into forward contracts to purchase Euros. Southern Power has designated these contracts as fair value hedges of an unrecognized firm commitment. The total notional amount is 48 million Euros, with 42 million maturing in 2002 and 6 million maturing in 2003. The forward contracts to purchase Euros are on the same dates and in the same amounts as F-20 the Euro payments that Southern Power owes for the equipment. As all of the critical terms of the forward Euro purchases (dates and amounts) match those of the Euro payment obligations, the changes in fair value attributable to the risk being hedged are expected to completely offset at inception and on an ongoing basis. Therefore, there is no ineffectiveness related to this hedge. Additionally, in connection with the transfer of Plant Goat Rock from GPC (see Note 2, Asset Transfers and Construction Programs), GPC transferred approximately $5.6 million in derivative assets relating to electric forward positions in effect at the date of the transfer. Such forwards were recorded at fair value on the date of transfer, which was equal to GPC's carrying amount, and were subsequently marked-to-market. SCS, acting as agent for Southern Power and the Operating Companies, enters into commodity related forward and option contracts to limit exposure to changing prices on certain fuel purchases and electricity purchases and sales. Substantially all of SCS's bulk energy purchases and sales contracts meet the definition of a derivative under the SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. In many cases, these fuel and electricity contracts qualify for normal purchase and sale exceptions under SFAS No. 133 and are accounted for under the accrual method. Other contracts qualify as cash flow hedges of anticipated transactions, resulting in the deferral of related gains and losses, and are recorded in other comprehensive income until the hedged transactions occur. Any ineffectiveness is recognized currently in net income. Ineffectiveness is immaterial for the period ended December 31, 2001. Contracts that do not qualify for the normal purchase and sale exception that have not been designated as hedges or that do not meet the hedge requirements are marked to market through current period income. SCS allocates gains and losses on fuel and electricity derivative contracts to the Operating Companies and Southern Power under the terms of the IIC (See Note 1). At December 31, 2001, Southern Power had net derivative assets of approximately $5.5 million related to commodity related hedging financial instruments. The fair value of these forward contacts is calculated based on closing exchange or over-the-counter market price quotations. Certain of these forwards did not meet the hedge criteria. For the period from January 8, 2001 (inception) through December 31, 2001, Southern Power has recorded a net unrealized gain on these transactions of approximately $580 thousand. This amount is reported in other income on the accompanying consolidated income statement. The following table summarizes Southern Power's derivative and hedging activity for the period from January 8, 2001 (inception) to December 31, 2001 (in thousands):
INTEREST ELECTRIC AND RATE GAS FORWARD EURO SWAPS CONTRACTS FORWARDS TOTAL -------- ------------ -------- ------- Unrealized gains............................ $11,521 $ 6,542 $ 204 $18,267 Unrealized losses........................... -- (1,046) (204) (1,250) ------- ------- ----- ------- Net derivative asset........................ $11,521 $ 5,496 $ -- $17,017 ======= ======= ===== ======= OCI, net of income tax effects.............. $ 7,065 $ (376) $ -- $ 6,689 Purchased derivative assets................. -- 5,617 -- 5,617 Other income................................ -- 580 -- 580
Southern Power is exposed to losses related to financial instruments in the event of counterparties' nonperformance. SCS, in its capacity as agent for the Operating Companies and Southern Power, has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate its exposure to counterparty credit risk. F-21 4. FUEL COMMITMENTS SCS, as agent for the Operating Companies and Southern Power, has entered into various fuel transportation and procurement agreements to supply a portion of the fuel (primarily natural gas) requirements for the operating facilities. In most cases, these contracts contain provisions for firm transportation costs, storage costs, minimum purchase levels, and other financial commitments. At December 31, 2001, total estimated long-term fuel commitments related to Southern Power's generating units, based on contractual terms, were as follows (in millions): 2002........................................................ $ 2 2003........................................................ 8 2004........................................................ 4 2005........................................................ -- 2006........................................................ -- 2007 and thereafter......................................... 260 ---- Total............................................. $274 ====
In addition, SCS acts as agent for Southern Power and the Operating Companies with regard to natural gas purchases. Natural gas purchases (in dollars) are based on various indices at the actual time of delivery; therefore, only the volume commitments are firm. At December 31, 2001, the committed volumes (in MMBTU) allocated to Southern Power based on projected usage for its units are as follows:
MMBTU ---------- 2002........................................................ 7,997,028 2003........................................................ 13,212,489 2004........................................................ 1,649,892 2005........................................................ 300,471 2006........................................................ 201,550 2007 and thereafter......................................... 87,056 ---------- Total....................................................... 23,448,486 ==========
Purchases of natural gas from SCS were approximately $3.6 million for the period ended December 31, 2001. 5. LONG TERM SERVICE AGREEMENTS Southern Power has entered into several Long-Term Service Agreements ("LTSAs") with General Electric International, Inc. ("GEII") for the purpose of securing maintenance support for its Combined Cycle ("CC") and Combustion Turbine ("CT") generating facilities. In summary, the LTSAs stipulate that for a fee, GEII will perform all planned maintenance on the covered equipment, which includes the cost of all labor and materials. The planned maintenance events are Combustion Inspections, Hot Gas Path Inspections, and Major Inspections. These maintenance events are to take place at intervals outlined in the published recommendations of GEII. GEII is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract. In general, except for the Dahlberg units, these agreements are in effect through the second Major Inspection, which is to occur at approximately 96,000 fired operating hours ("FOH") per unit with a termination option available at 48,000 FOH and in some cases at 72,000 FOH. The Dahlberg agreement is in effect through the first Hot Gas Path Inspection of each unit, which is to occur at approximately 1,200 factored starts on a unit with a cancellation option available after the first Combustion Inspection. Scheduled payments to GEII are made at various intervals based on actual FOH. Total payments to GEII under these agreements are $852 million over the life of the agreements (estimated to be 28 to 30 years per unit) or $370 million if Southern Power terminates the agreement after 48,000 FOH. F-22 Southern Power is obligated to pay the cost of planned maintenance under these agreements at Plant Dahlberg through balloon payments. GEII will bill the balloon payments no earlier than 6 months prior to the scheduled commencement of any planned maintenance. Payments made under this arrangement will be recorded as a prepayment on the consolidated balance sheet. The first outage is scheduled for 2003. At the time of a planned maintenance, these costs will be capitalized or charged to expense based on the nature of the work performed. Any amounts capitalized will be added to the applicable retirement unit and depreciated over the remaining life of the plant. 6. JOINT OWNERSHIP AGREEMENTS Southern Power, through its wholly owned subsidiary SCF, is a 65% owner of Plant Stanton Unit A ("Stanton A"), a combined-cycle project that will total 633 MW upon completion. The unit is co-owned by Orlando Utilities Commission ("OUC") (28%), Florida Municipal Power Agency ("FMPA") (3.5%), and Kissimmee Utility Authority ("KUA") (3.5%). Southern Power has a services agreement with SCS where SCS will be responsible for the operation and maintenance of Stanton A. Additionally, under the terms of the services agreement, SCS will perform overall project management of the construction process. Construction on Stanton A began in October 2001 with an expected completion date of October 1, 2003. At December 31, 2001, Southern Power's share of construction costs for Stanton A of $31.4 million, which are net of joint participant payments, are recorded in construction work in progress. 7. LONG-TERM POWER SALES CONTRACTS Southern Power has also entered into long-term power sales contracts for portions of its generating unit capacity, as follows:
MEGAWATTS CONTRACT PROJECT (MW) TERM - ------- --------- ----------- Dahlberg Units 1-7.......................................... 578 6/00-12/04 Dahlberg Unit 8-10.......................................... 225 6/00-5/05 Goat Rock 1................................................. 571(1) 6/02-5/10 Goat Rock 2................................................. 615(2) 6/02-5/11 Wansley 6 and Wansley 7..................................... 1,134 6/02-12/09 Harris 1.................................................... 618 6/02-5/10 Harris 2.................................................... 618(3) 6/04-5/19
- --------------- (1) 370MW During the first year (2) 400MW During the first year (3) Contract does not begin until second year of operation In addition, in connection with the Stanton A joint ownership agreements (Note 6), Southern Power has entered into a long-term power sale agreement, which provides for payment of fixed capacity and energy for specified periods. OUC, KUA, and FMPA will purchase all of the capacity owned by Southern Power pursuant to purchase power agreements with 10-year terms. These agreements provide OUC, KUA, and FMPA the unilateral option to acquire Southern Power's capacity for up to four extensions, each with five-year terms, to a maximum of 30 years. Such agreements will go into effect upon completion of construction of Stanton A. F-23 Capacity revenues from these power sales agreements amounted to $18.6 million for the period ended December 31, 2001. Future capacity payments to be received under these power sales agreements as of December 31, 2001 are as follows (in millions): 2002........................................................ $ 125.6 2003........................................................ 226.1 2004........................................................ 317.2 2005........................................................ 358.9 2006........................................................ 369.0 2007 and Thereafter......................................... 2,774.8 -------- Total............................................. $4,171.6 ========
Capacity revenues under these power sales agreements are recognized on a levelized basis over the life of the contracts. At December 31, 2001, Southern Power had received $1.7 million more in payments than was recognized in revenues. The amount is recorded in other deferred credits on the accompanying consolidated balance sheets. Additionally, GPC required that certain counterparties to the Dahlberg Purchase Power Agreements make prepayments for operational rights to the units. These prepayments were recorded as liabilities by GPC and were transferred to Southern Power in connection with the Plant Dahlberg transfer. At December 31, 2001, these amounts totaled $4.2 million and are being amortized into income over the life of the agreements. 8. INCOME TAXES Details of the income tax provision (benefit) for the period from inception (January 8, 2001) through December 31, 2001 are as follows (in thousands): Federal: Current................................................... $ 1,402 Deferred.................................................. 3,017 ------- 4,419 ------- State: Current................................................... 240 Deferred.................................................. 517 State manufacturer's tax credits.......................... (2,665) ------- (1,908) ------- Total............................................. $ 2,511 =======
Southern Power recorded a reduction in 2001 tax expense of approximately $2.7 million under the flow-through method of accounting for the State of Georgia manufacturer's tax credits. The State of Georgia provides a tax credit for qualified investment property to manufacturing companies that construct new facilities. The credit ranges from 1% to 5% of construction expenditures depending upon the county in which the new facility is located. Southern Power's policy is to recognize these credits when management believes they are more likely than not to be allowed by the Georgia Department of Revenue. F-24 The tax effects of temporary differences between the carrying amounts of assets in the financial statements and their respective tax bases which give rise to deferred tax assets and liabilities as of December 31, 2001 are as follows (in thousands): Deferred tax liabilities: Accelerated depreciation.................................. $(3,451) Other..................................................... (4,444) ------- Total............................................. (7,895) ------- Deferred tax asset -- book/tax basis difference on asset transfer.................................................. 19,810 ------- Accumulated net deferred income tax assets.................. $11,915 =======
Deferred tax liabilities were primarily the result of property related timing differences and derivative hedging instruments. Deferred tax assets were primarily the result of a deferred tax gain related to the transfer of Plant Dahlberg from GPC. Southern Power has recognized a payable to GPC for GPC's deferred tax liability resulting from this gain of approximately $19.8 million at December 31, 2001, which is recorded in due to affiliates on the accompanying consolidated balance sheet. The provision for income taxes differs from the amount of income taxes determined by applying the applicable federal statutory rate to earnings before income taxes, as a result of the following: Income taxes at statutory rate.............................. 35.0% State taxes, net of federal benefit......................... 4.6 State manufacturer's tax credits, net of federal effect..... (16.2) ----- Total income tax provision........................ 23.4% =====
Southern files a consolidated federal income tax return. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. In accordance with Internal Revenue Service regulations, each company is jointly and severally liable for the tax liability of Southern. 9. CAPITALIZATION AND REVOLVING CREDIT FACILITIES Southern Power has authorized common stock of 1 million shares at $.01 par value per share. One thousand shares have been issued to Southern and are outstanding at December 31, 2001. Southern Power uses both external funds and equity capital from Southern to finance its construction program. Southern, through its equity contribution agreement with Southern Power, has committed to fund directly at least 40% of the construction costs of facilities funded under the revolving credit facility, approximately $677 million. Capital contributions from Southern through December 31, 2001 totaled approximately $452 million. In addition, Southern executed a guarantee of completion of construction of each generating facility that is financed in part by the lenders under the credit facility (the "Completion Guarantee"). Under the terms of the Completion Guarantee, Southern guarantees timely completion of construction of the facilities under the credit facility, agrees to fund any associated construction cost overruns to the extent Southern Power's cash flow is insufficient, and agrees to pay down debt if certain performance standards at completion are not met. Southern is currently authorized by the SEC under the PUHCA to fund the development of Southern Power up to an aggregate amount not to exceed $1.7 billion, which may take the form of purchases or contributions of equity interests, loans and guarantees issued in support of Southern Power's securities or obligations. Southern Power has SEC approval under the PUHCA to issue up to an aggregate amount of $2.5 billion of preferred securities, long and short-term debt and other equity issuances. F-25 During 2001, Southern Power entered into an intercompany note payable with Southern. The note is payable on demand and bears interest at a variable rate. At December 31, 2001, $950 thousand was outstanding with an interest rate of 3.27%. In November 2001, Southern Power entered into an $850 million unsecured syndicated revolving credit facility (the "Facility"). The purpose of the Facility is to finance the acquisition and construction costs related to gas-fired electric generating facilities, general corporate purposes (subject to a $25 million limit) and to pay or back-stop commercial paper used to fund construction of facilities. At December 31, 2001, Southern Power had borrowed approximately $293 million under the Facility leaving an unused borrowing authority of approximately $557 million. Borrowings under the Facility bear interest at Southern Power's option equal to either the Eurodollar rate plus a specified margin ranging from 1.125% to 2.875%, depending on Southern Power's credit rating, or a base rate plus a specified margin. The interest rate and average interest rate on the Facility were 3.44% and 3.61%, respectively, at December 31, 2001 and during the period then ended, based on the Eurodollar rate option. Southern Power is required to pay a commitment fee on the unused balance of the Facility. The commitment fee ranges from 0.3% to 0.45% depending on Southern Power's credit rating. For the period ended December 31, 2001, Southern Power paid approximately $147 thousand in commitment fees. All borrowings outstanding under the Facility are due in November 2004. The Facility contains certain financial covenants relating to Southern Power's debt capitalization which require that additional debt incurred by Southern Power must generally be unsecured and Southern Power must have its ratings reaffirmed at investment grade including the new debt. The Facility also contains restrictions related to the assumption of additional debt, which require a maximum 60% debt ratio. Southern Power is in compliance with such covenants at December 31, 2001. In 2001, Southern Power entered into a financial arrangement with Westdeutsche Landesbank Girozentrale ("WestLB"). Under this agreement, Southern Power may assign up to $125 million in vendor contracts for equipment to WestLB. For accounting purposes, WestLB is the owner of the contracts. Southern Power acts as an agent for WestLB and instructs WestLB when to make payments to the vendors. At December 31, 2001, approximately $47 million of such vendor equipment contracts had been assigned to WestLB. This agreement was terminated on March 22, 2002 and Southern Power repurchased the equipment at original cost, which totaled approximately $61 million, using funds from an intercompany loan with Southern. 10. CONTINGENCIES Southern Power is in mediation with a former contractor who has filed a lien against Plant Wansley Units 6 and 7 for approximately $17.0 million as compensation for cost over-runs in building the plant. Also, the contractor is claiming approximately $10.0 million in additional charges related to construction cost over-runs for Goat Rock Unit 1. The outcome of this matter cannot now be determined. Management believes that the ultimate outcome of this matter will not have a material adverse affect on Southern Power's financial condition or results of operations. Any amounts ultimately paid would be capitalized as a cost of the project. 11. SUBSEQUENT EVENTS In January 2002, GPC transferred to Southern Power the construction work in progress balance for Plant Wansley Units 6 and 7 at net book value of approximately $390 million. In 2002, Southern Power executed three additional long-term sales agreements for the capacity of specific generating facilities. These agreements are still subject to regulatory approval. Also, in 2002, Southern Power executed agreements to coordinate the generating resources and meet the additional capacity requirements of 11 Georgia Electric Membership Corporations. F-26 12. QUARTERLY FINANCIAL DATA (UNAUDITED) Southern Power was created on January 8, 2001. Commercial operations began in August with the transfer of Plant Dahlberg. First and second quarter operating income and net income data reflect start up and organizational costs incurred prior to commercial operations: Operating revenues: First quarter (1/8/01 -- 3/31/01)......................... $ -- Second quarter............................................ -- Third quarter............................................. 14,604 Fourth quarter............................................ 14,697 ------- Fiscal year................................................. $29,301 ======= Operating income (loss): First quarter (1/8/01 -- 3/31/01)......................... $ (107) Second quarter............................................ (1,569) Third quarter............................................. 7,056 Fourth quarter............................................ 5,107 ------- Fiscal year................................................. $10,487 ======= Net income (loss): First quarter (1/8/01 -- 3/31/01)......................... $ (65) Second quarter............................................ (949) Third quarter............................................. 5,957 Fourth quarter............................................ 3,264 ------- Fiscal year................................................. $ 8,207 =======
F-27 INDEPENDENT AUDITORS' REPORT To Southern Power Company: We have audited the accompanying balance sheets of Plant Dahlberg (a wholly owned carve-out entity of Georgia Power Company, an affiliate company) ("Plant Dahlberg") as of July 31, 2001 and December 31, 2000, and the related statements of income for the seven months ended July 31, 2001 and the year ended December 31, 2000, and of cash flows for the seven months ended July 31, 2001 and the years ended December 31, 2000 and 1999. These financial statements are the responsibility of Southern Power Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The accompanying financial statements have been prepared from the separate records maintained by Georgia Power Company and affiliates and may not necessarily be indicative of the conditions that would have existed or the results of operations if Plant Dahlberg had been operated as an unaffiliated company. Portions of certain income and expenses represent allocations made from affiliate company items applicable to the Georgia Power Company and affiliates as a whole. In our opinion, such financial statements referred to above present fairly, in all material respects, the financial position of Plant Dahlberg as of July 31, 2001 and December 31, 2000, and the results of its operations for the seven months ended July 31, 2001 and the year ended December 31, 2000 and its cash flows for the seven months ended July 31, 2001 and the years ended December 31, 2000 and 1999 in conformity with accounting principles generally accepted in the United States of America. /s/ DELOITTE & TOUCHE LLP Atlanta, Georgia May 31, 2002 F-28 PLANT DAHLBERG (A WHOLLY OWNED CARVE-OUT ENTITY OF GEORGIA POWER COMPANY) BALANCE SHEETS
AS OF JULY 31, AS OF DECEMBER 31, 2001 2000 -------------- ------------------ (IN THOUSANDS) ASSETS CURRENT ASSETS: Accounts receivable....................................... $ 7,647 $ 10,861 Fossil fuel stock, at average cost........................ 3,378 3,019 -------- -------- Total current assets.............................. 11,025 13,880 -------- -------- PROPERTY, PLANT, AND EQUIPMENT.............................. 220,112 220,112 LESS ACCUMULATED DEPRECIATION............................... (7,738) (3,723) -------- -------- 212,374 216,389 CONSTRUCTION WORK IN PROGRESS............................... 47,228 42,298 -------- -------- Total property, plant, and equipment, net......... 259,602 258,687 -------- -------- Total assets...................................... $270,627 $272,567 ======== ======== LIABILITIES AND ACCUMULATED EARNINGS CURRENT LIABILITIES: Note payable to Southern (Note 5)......................... $160,404 $157,446 Accrued income taxes payable.............................. 4,345 5,128 -------- -------- Total current liabilities......................... 164,749 162,574 -------- -------- DEFERRED CREDITS AND OTHER LIABILITIES: Deferred income taxes..................................... 4,841 2,774 Other..................................................... 6,770 6,034 -------- -------- Total deferred credits and other liabilities...... 11,611 8,808 -------- -------- Total liabilities................................. 176,360 171,382 -------- -------- DUE TO GEORGIA POWER COMPANY................................ 72,796 89,331 ACCUMULATED EARNINGS........................................ 21,471 11,854 -------- -------- Total Liabilities and Accumulated Earnings........ $270,627 $272,567 ======== ========
See notes to financial statements. F-29 PLANT DAHLBERG (A WHOLLY OWNED CARVE-OUT ENTITY OF GEORGIA POWER COMPANY) STATEMENTS OF INCOME
FOR THE SIX MONTHS FOR THE ENDED SEVEN MONTHS FOR THE JUNE 30, ENDED YEAR ENDED 2001 JULY 31, 2001 DECEMBER 31, 2000 ------------- ------------- ----------------- (UNAUDITED) (IN THOUSANDS) OPERATING REVENUES: Electricity sales: Nonaffiliates................................... $30,311 $36,532 $59,124 Affiliates...................................... 4,114 4,621 10,989 Other revenues..................................... -- 0 3 ------- ------- ------- Total operating revenues................... 34,425 41,153 70,116 ------- ------- ------- OPERATING EXPENSES: Fuel............................................... 5,506 6,762 27,339 Purchased power from affiliates.................... 6,414 7,844 11,923 General and administrative......................... 310 354 299 Operations and maintenance......................... 1,240 1,511 1,088 Depreciation....................................... 3,439 4,015 3,723 Taxes, other than income taxes..................... 629 734 539 ------- ------- ------- Total operating expenses................... 17,538 21,220 44,911 ------- ------- ------- OPERATING INCOME..................................... 16,887 19,933 25,205 INTEREST EXPENSE, NET................................ 3,360 3,904 5,449 ------- ------- ------- INCOME BEFORE INCOME TAXES........................... 13,527 16,029 19,756 INCOME TAXES (Note 4)................................ 5,411 6,412 7,902 ------- ------- ------- NET INCOME........................................... 8,1$16..... $ 9,617 $11,854 ======= ======= =======
See notes to financial statements. F-30 PLANT DAHLBERG (A WHOLLY OWNED CARVE-OUT ENTITY OF GEORGIA POWER COMPANY) STATEMENTS OF CASH FLOWS
SIX MONTHS SEVEN ENDED MONTHS JUNE 30, 2001 ENDED YEAR ENDED YEAR ENDED (UNAUDITED) JULY 31, 2001 DECEMBER 31, 2000 DECEMBER 31, 1999 ------------- ------------- ----------------- ----------------- (IN THOUSANDS) OPERATING ACTIVITIES: Net income....................... $ 8,116 $ 9,617 $ 11,854 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation.................. 3,439 4,015 3,723 Deferred income taxes......... 1,772 2,067 2,774 Changes in current assets and liabilities: Receivables................... 2,755 3,214 (10,861) Fossil fuel stock............. (308) (359) (3,019) Taxes accrued................. (671) (783) 5,128 Prepaid capacity revenues..... (708) (826) 5,674 Other deferred credits........ 1,339 1,562 360 $ -- -------- -------- --------- --------- Net cash provided from operating activities... 15,734 18,507 15,633 -- INVESTING ACTIVITIES: Gross property additions......... (4,226) (4,930) (262,410) (146,566) -------- -------- --------- --------- Net cash used in investing activities... (4,226) (4,930) (262,410) (146,566) FINANCING ACTIVITIES: Changes in due to Georgia Power Company....................... (14,043) (16,535) 89,331 58,626 Notes payable.................... 2,535 2,958 157,446 87,940 -------- -------- --------- --------- Net cash provided by (used in) financing activities............. (11,508) (13,577) 246,777 146,566 NET INCREASE IN CASH AND CASH EQUIVALENTS...................... $ 0 $ -- $ -- $ -- CASH AND CASH EQUIVALENTS, beginning of period.............. -- -- -- -- -------- -------- --------- --------- CASH AND CASH EQUIVALENTS, end of period........................... -- -- -- -- ======== ======== ========= ========= SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid (received) during the year for interest (net of amount capitalized)........... $ -- $ -- $ -- $ -- ======== ======== ========= ========= Cash paid (received) during the year for income taxes (refund)...................... $ -- $ -- $ -- $ -- ======== ======== ========= =========
See notes to financial statements. F-31 PLANT DAHLBERG (A WHOLLY OWNED CARVE-OUT ENTITY OF GEORGIA POWER COMPANY) NOTE TO FINANCIAL STATEMENTS (UNAUDITED) FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 2001 A. The financial statements included herein have been prepared, without audit, pursuant to the rules and regulations of the SEC. In the opinion of management, the information furnished herein reflects all adjustments necessary to present fairly the results of operations for the period ended June 30, 2001. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations, although management believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Therefore, it is suggested that these condensed financial statements be read in conjunction with the financial statements as of July 31, 2001 and December 31, 2000 and for the periods then ended and the notes thereto included herein. F-32 PLANT DAHLBERG (A WHOLLY OWNED CARVE-OUT ENTITY OF GEORGIA POWER COMPANY) NOTES TO FINANCIAL STATEMENTS AS OF JULY 31, 2001, AND DECEMBER 31, 2000 1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation -- The accompanying carve-out financial statements present the financial position and the results of operations of Georgia Power Company's Plant Dahlberg ("Plant Dahlberg"), a component of the competitive contract-based wholesale generation-related business of Georgia Power Company ("GPC"). The financial statements include Plant Dahlberg's financial position as of July 31, 2001 and December 31, 2000, and its results of operations for the period from January 1, 2001 to July 31, 2001 and for the year ended December 31, 2000 and Plant Dahlberg's cash flows for the seven months ended July 31, 2001 and the years ended December 31, 2000 and 1999. GPC began construction of Plant Dahlberg in December 1998, and commercial operations for units 1-8 commenced in June 2000. Units 9-10 were placed into service in 2001. Operations of Plant Dahlberg prior to June 2000 consisted solely of construction related activities. GPC transferred Plant Dahlberg to Southern Power Company ("Southern Power") on July 31, 2001 (the "Transfer"). Southern Power is a wholly owned subsidiary of Southern Company ("Southern"). Southern is the parent company of five operating companies, Southern Company Services ("SCS"), Southern Communications Services ("Southern LINC"), Southern Nuclear Operating Company ("Southern Nuclear"), Southern Power Company, and other direct and indirect subsidiaries. The operating companies, consisting of Alabama Power Company ("APC"), Georgia Power Company ("GPC"), Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company (collectively, the Operating Companies) provide electric service in four southeastern states. Contracts among the Operating Companies and Southern Power, including those related to jointly owned generating facilities, interconnecting transmission lines, and the exchange of electric power, are regulated by the Federal Energy Regulatory Commission ("FERC") and/or the Securities and Exchange Commission ("SEC"). SCS provides, at cost, specialized services to Southern Company and subsidiary companies. Southern Nuclear provides services to Southern's nuclear power plants. Southern is registered as a holding company under the Public Utility Holding Company Act of 1935 as amended ("PUHCA"). Southern, Southern Power, and the Operating Companies are subject to the regulatory provisions of PUHCA. Southern Power is also subject to regulation by the FERC. Plant Dahlberg is not a separate subsidiary, division, or segment of GPC. Such financial information of Plant Dahlberg is not necessarily indicative of the financial position, results of operations or cash flows that would have existed had Plant Dahlberg been an independent company during the periods presented. Certain information in these financial statements relating to the results of operations and financial condition of Plant Dahlberg was derived from the historical financial statements of GPC, which have been prepared in accordance with accounting principles generally accepted in the United States of America ("generally accepted accounting principles"). Various allocation methodologies were employed to separate the results of operations and financial condition of Plant Dahlberg from GPC's historical financial statements prior to the Transfer. Prior to the Transfer, revenues included the generation component of revenue from GPC's operations and any generation-related revenues, such as ancillary services and wholesale energy activity. Expenses, such as energy costs, operations and maintenance and depreciation, and assets, such as property, plant and equipment, and fuel, were specifically identified by function and reported accordingly for Plant Dahlberg's operations. Various allocations were used to disaggregate other common expenses, assets and liabilities between Plant Dahlberg and GPC's regulated generation, transmission and distribution operations. Interest was calculated based upon an allocation methodology that charged Plant Dahlberg with financing costs from GPC in proportion to its share of total net property, plant and equipment. These methodologies use the assumption that Plant Dahlberg had operated as a separate, non-regulated company prior to the Transfer. F-33 Management believes that these allocation methodologies are reasonable. Had Plant Dahlberg actually existed as a separate company, its results could have significantly differed from those presented herein. In addition, future results of operations, financial position and cash flows could materially differ from the historical results presented. Affiliate Transactions -- GPC (including Plant Dahlberg) along with the other Operating Companies and Southern Power are members of and share the benefits and obligations of the Southern system power pool ("Southern Pool"). The Southern Pool is operated by SCS. As a member of the Southern Pool, Plant Dahlberg will be economically dispatched with the generating facilities of the Operating Companies to serve the members' aggregate load requirements. A member of the Southern Pool has the first call on its own generating resources, but if lower cost generation resources are available within the Southern system, a Southern Pool member has the right to purchase that lower variable cost energy to satisfy its obligations. Additionally, if a Southern Pool member is unable to generate sufficient capacity and energy to meet its obligations, it can buy power from the Southern Pool at the marginal energy cost. The Southern Pool is governed by the provisions in the Intercompany Interchange Contract ("IIC"), which has been approved by the FERC. GPC (including Plant Dahlberg) has an agreement with SCS under which certain services are rendered at cost. These services may include Southern Pool operations, construction, general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and pensions, human resources, systems and procedures, and other services with respect to business operations and power pool management. SCS also enters into fuel purchase and transportation arrangements and contracts, financial instruments for purposes of hedging, and wholesale energy purchase and sale transactions for the benefit of GPC. Purchases of natural gas from SCS at market prices were approximately $5.8 million and $26.6 million for the periods ended July 31, 2001 and December 31, 2000, respectively. Plant Dahlberg sells its output under long-term, market-based contracts both to unaffiliated wholesale purchasers as well as the Operating Companies (under power purchase agreements approved by the respective public service commissions). Plant Dahlberg is not included in the Operating Companies' rate bases. GPC provides operation and maintenance services for Plant Dahlberg. These services are provided at cost and are recorded as operations and maintenance expense in the accompanying statements of income. For the period ended July 31, 2001, and the year ended December 31, 2000, these services totaled approximately $1.5 million and $1.1 million, respectively. Revenues -- Revenues include capacity and energy sales, and are recorded based on output and energy delivery. Capacity output is sold at rates specified under contractual terms, and is recognized ratably over the respective contract periods. Energy is generally sold at market-based rates and is recognized as delivered. Significant portions of Plant Dahlberg's revenues have been derived from certain customers. LG&E Energy Marketing Inc. and Dynegy Power Marketing Inc. accounted for approximately 88.7% and 84.3% of revenues, respectively, for the period ended July 31, 2001 and year ended December 31, 2000. Fuel Costs -- Fuel costs are expensed as the fuel is consumed. As of July 31, 2001 and December 31, 2000, there were no long-term fuel commitments for Plant Dahlberg. Depreciation -- Depreciation of the original cost of plants is computed under the straight-line method based on the assets' estimated useful lives. The estimated useful lives are approximately 35 years for plant. Income Taxes -- Plant Dahlberg is not a taxable entity. The accompanying carve-out financial statements reflect Plant Dahlberg tax liabilities as though it was filing a separate return and accordingly, Plant Dahlberg has applied the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Deferred income taxes are reflected for the temporary differences between book and taxable income, resulting primarily from the use of accelerated depreciation for tax purposes. Property, Plant, and Equipment -- Property, plant, and equipment are stated at original cost. Original cost includes materials, direct labor incurred by affiliated companies, minor items of property, and appropriate F-34 administrative costs. Interest is capitalized on qualifying projects during the development and construction period. For the period ended July 31, 2001 and years ended December 31, 2000 and 1999, approximately $1.0 million, $5.8 million and $3.2 million, respectively of interest was capitalized in connection with the development and construction of Plant Dahlberg. Upon commencement of plant operations, capitalized interest is amortized over the estimated useful life of the plant. The cost of maintenance, repairs, and replacement of minor items of property is charged to maintenance expense as incurred. The cost of replacements of property that extend the useful life of the plant, exclusive of minor items of property, is capitalized. Construction work in progress is recorded at cost, which includes, materials, labor, appropriate administrative costs, and the capitalized interest on funds used during construction. Impairment of Long-Lived Assets -- GPC reviews Plant Dahlberg for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared to the carrying value of the assets. If the carrying amount of the asset exceeds the expected future cash flows expected to be generated by the asset, an impairment loss is recognized, and the asset is written down to its estimated fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Use of Estimates -- The process of preparing financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Also, such estimates relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts. In addition to these estimates, see Basis of Presentation for a discussion of the estimates used and methodologies employed to derive Plant Dahlberg's historical financial statements. New Accounting Pronouncements -- Derivatives -- Effective January 1, 2001, Plant Dahlberg adopted Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, and interpreted. SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that companies recognize all derivatives as either assets or liabilities measured at fair value on the statement of financial position. SFAS No. 133 provides an exception for certain contracts that qualify as "normal purchases and sales." To qualify for this exception, certain criteria must be met, including that it must be probable that the contract will result in physical delivery. There were no derivative instruments as of and for the period ended July 31, 2001 and the year ended December 31, 2000. 2. LONG TERM SERVICE AGREEMENTS GPC has entered into a Long-Term Service Agreement ("LTSA") with General Electric International, Inc. ("GEII") for the purpose of securing maintenance support for Plant Dahlberg. In summary, the LTSA stipulates that for a fee, GEII will perform all planned maintenance on the covered equipment, which includes the cost of all labor and materials. The planned maintenance events are Combustion Inspections, Hot Gas Path Inspections, and Major Inspections. These maintenance events are to take place at intervals outlined in the published recommendations of GEII. GEII is also obligated to cover the costs of unplanned maintenance on the covered equipment subject to a limit specified in each contract. The Dahlberg agreement is in effect through the first Hot Gas Path Inspection of each unit, which is to occur at approximately 1,200 factored starts on a unit with a cancellation option available after the first Combustion Inspection. Scheduled payments to GEII are made at various intervals based on actual fired operating hours ("FOH"). Total payments to GEII under these agreements are $852 million over the life of the agreements (estimated to be 28 to 30 years per unit) or $370 million if Southern Power terminates the agreement after 48,000 FOH. F-35 GPC is obligated to pay the cost of planned maintenance through balloon payments. GEII will bill the balloon payments no earlier than 6 months prior to the scheduled commencement of any planned maintenance. Payments made under this arrangement will be recorded as a prepayment on the consolidated balance sheet. The first outage is scheduled for 2003. At the time of a planned maintenance, these costs will be capitalized or charged to expense based on the nature of the work performed. Any amounts capitalized will be added to the applicable retirement unit and depreciated over its remaining life of the plant. GPC pays GEII fixed quarterly payment to cover the costs of continuous monitoring at Plant Dahlberg. Such costs are recorded as operations and maintenance expense as the monitoring service is provided. 3. LONG TERM POWER SALES GPC has entered into long-term power sales contracts for portions of Plant Dahlberg's generating unit capacity, as follows:
MEGAWATTS END PROJECT (MW) DATE - ------- --------- -------- Dahlberg Units 1-7.......................................... 578 12/31/04 Dahlberg Unit 8-10.......................................... 225 5/31/05
Capacity revenues from these power sales agreements amounted to $22.4 million and $20.2 million for the periods ended July 31, 2001 and December 31, 2000, respectively. Future capacity payments from these power sales agreements as of July 31, 2001 are as follows (in millions): 2001 (August -- December)................................... $ 18.6 2002........................................................ 44.9 2003........................................................ 45.6 2004........................................................ 44.3 2005........................................................ 2.6 ------ Total............................................. $156.0 ======
Capacity revenues are recognized on a levelized basis over the life of the contract. At July 31, 2001 and December 31, 2000, Plant Dahlberg had received $1.6 million and $0.4 million more in payments than was recognized in revenues, respectively. These amounts are recorded in other deferred credits on the accompanying consolidated balance sheets. 4. INCOME TAXES Details of the income tax provision (benefit) allocated to Plant Dahlberg for the period from January 1, 2001 to July 31, 2001 and for the year ended December 31, 2000 are as follows (in thousands):
JULY 31, 2001 DECEMBER 31, 2000 ------------- ----------------- Federal: Current payable....................................... $3,824 $4,513 Deferred.............................................. 1,787 2,402 ------ ------ 5,611 6,915 ------ ------ State: Current payable....................................... 521 615 Deferred.............................................. 280 372 ------ ------ 801 987 ------ ------ Total......................................... $6,412 $7,902 ====== ======
F-36 Deferred tax liabilities were primarily the result of property related timing differences, and totaled $2.1 million and $2.8 million at July 31, 2001 and December 31, 2000, respectively. 5. NOTE PAYABLE TO SOUTHERN At July 31, 2001 and December 31, 2000, GPC had no debt financing directly related to Plant Dahlberg. However, because Southern has an equity contribution agreement with Southern Power under which it had committed to fund directly at least 40% of the construction costs of certain projects, the accompanying carve- out financial statements reflect a capital structure of 40% equity (due to Georgia Power Company) and 60% debt. The debt is included in "Note Payable to Southern" on the accompanying financial statements, and is assumed to accrue interest at a rate that is the higher of the average effective interest cost of Southern's outstanding obligation for borrowed money or the applicable Federal Rate for short-term loans published by the Internal Revenue Service. The interest rates on outstanding amounts allocated to Plant Dahlberg were 4.07% and 6.1% at July 31, 2001 and December 31, 2000, respectively. 6. TRANSFER OF PLANT DAHLBERG TO SOUTHERN POWER On July 31, 2001, Plant Dahlberg Units 1 through 10 and related working capital was transferred to Southern Power from GPC. These assets were transferred at book value of $260.1 million. F-37 ANNEX A INDEPENDENT ENGINEER'S REPORT SOUTHERN POWER COMPANY GENERATING FACILITIES [R.W. BECK LOGO] [THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY] ANNEX A INDEPENDENT ENGINEER'S REPORT SOUTHERN POWER GENERATING FACILITIES TABLE OF CONTENTS
PAGE ---- INTRODUCTION.....................................................................................................A-1 THE GENERATING FACILITIES........................................................................................A-5 The Project Sites.............................................................................................A-6 Description of the Facilities.................................................................................A-9 Off-Site Requirements........................................................................................A-11 Fuel Supply...............................................................................................A-11 Water Supply and Treatment................................................................................A-12 Wastewater Disposal.......................................................................................A-13 Electrical Interconnection................................................................................A-13 Review of Technologies.......................................................................................A-15 GE 7FA CT.................................................................................................A-15 GE 7EA CT.................................................................................................A-18 Summary...................................................................................................A-19 Estimated Useful Life........................................................................................A-19 Performance Tests and Guarantees.............................................................................A-19 Operating History............................................................................................A-21 Capacity and Heat Rate.......................................................................................A-22 Availability.................................................................................................A-26 Construction Status..........................................................................................A-28 ENVIRONMENTAL ASSESSMENTS.......................................................................................A-28 Environmental Site Assessments...............................................................................A-28 Status of Permits and Approvals..............................................................................A-31 Regulatory Compliance........................................................................................A-33 PROJECTED OPERATING RESULTS.....................................................................................A-34 Annual Operating Revenues....................................................................................A-35 Revenue from Power Purchase Agreements....................................................................A-35 Other Revenues from Electricity Sales.....................................................................A-38 Annual Operating Expenses....................................................................................A-39 Fuel Costs................................................................................................A-39 Operating and Maintenance Costs...........................................................................A-39 Purchased Power...........................................................................................A-40 Emissions Allowances......................................................................................A-40 General and Administrative and Other Expenses.............................................................A-40 Annual Interest..............................................................................................A-40 Interest Coverage............................................................................................A-40 Sensitivity Analyses.........................................................................................A-41 Summary Comparison of Projected Operating Results............................................................A-41
A-i ANNEX A INDEPENDENT ENGINEER'S REPORT SOUTHERN POWER GENERATING FACILITIES TABLE OF CONTENTS (CONTINUED)
PAGE ---- PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS USED IN THE PROJECTION OF OPERATING RESULTS.....................................................................A-42 CONCLUSIONS.....................................................................................................A-44 EXHIBITS EXHIBIT A-1 Base Case Projected Operating Results.........................................................A-46 EXHIBIT A-2 Sensitivity A - Low Gas Market Price Scenario.................................................A-59 EXHIBIT A-3 Sensitivity B - High Gas Market Price Scenario................................................A-62 EXHIBIT A-4 Sensitivity C - Capacity Overbuild Market Price Scenario......................................A-65 EXHIBIT A-5 Sensitivity D - Reduced Output................................................................A-68 EXHIBIT A-6 Sensitivity E - Reduced Availability..........................................................A-71 EXHIBIT A-7 Sensitivity F - Increased Heat Rate...........................................................A-74 EXHIBIT A-8 Sensitivity G - Increased Operating Expenses..................................................A-77
Copyright (C) 2002 R. W. Beck, Inc. All Rights Reserved A-ii (R.W. BECK LOGO) June 13, 2002 Southern Power Company 2700 Peachtree Street NW Suite 2000 Atlanta, Georgia 30303 Subject: INDEPENDENT ENGINEER'S REPORT ON THE SOUTHERN POWER GENERATING FACILITIES Ladies and Gentlemen: INTRODUCTION Presented herein is the report (the "Report") of our review and analyses of the generating facilities owned by Southern Power Company ("Southern Power"), a wholly-owned subsidiary of The Southern Company ("Southern"). Southern Power intends on issuing $575,000,000 of 6.25% Senior Notes, due July 15, 2012 (the "Notes"). The generating facilities reviewed, totaling 4,777 megawatts ("MW") (net), are summarized in Table 1 and consist of the 810 MW (net) Dahlberg simple-cycle power plant in operation near Athens, Georgia consisting of ten units (the "Dahlberg Facility"); the 1,186 MW (net) Goat Rock combined-cycle power plant in Lee County, Alabama consisting of two units ("Goat Rock 1" and "Goat Rock 2", and, collectively, the "Goat Rock Facility"); the 1,236 MW (net) Harris combined-cycle power plant in Autauga County, Alabama consisting of two units ("Harris 1" and "Harris 2", and, collectively, the "Harris Facility"); Southern Power's 65 percent ownership interest in the 633 MW (net) Stanton combined-cycle power plant in Orlando, Florida (the "Stanton Facility"); and the 1,134 MW (net) Wansley combined-cycle power plant in Heard County, Georgia consisting of two units ("Wansley 6" and "Wansley 7", and, collectively, the "Wansley Facility" and, together with the Dahlberg, Goat Rock, Harris and Stanton Facilities, the "Generating Facilities"). Dahlberg 1-8 have been operational since May 2000. Dahlberg 9-10 have been operation since May 2001. Goat Rock 1 entered into commercial operation on June 1, 2002 and Goat Rock 2 is under construction and scheduled to be completed in June 2003. Harris 1 and 2 are under construction and are assumed to enter into commercial operation in June 2003. The Stanton Facility is under construction and is scheduled to enter into commercial operation in October 2003. The Wansley Facility entered into commercial operation on June 1, 2002. Southern Power was formed to develop, construct and own electric power generation facilities that provide power predominantly to Southern's regulated utilities: Alabama Power Company ("Alabama Power"), Georgia Power Company ("Georgia Power"); Gulf Power Company ("Gulf Power"); Mississippi Power Company ("Mississippi Power"); and Savannah Electric and Power Company ("Savannah Electric"). The Generating Facilities will sell power to these entities, as well as others, under the various terms of individual power purchase agreements (collectively, the "Power Purchase Agreements"). Southern Power intends to derive at least 80 percent of operating cash flow under long-term power purchase agreements. A-1 - ------------------------------------------------------------------------------- 1125 Seventeenth Street, Suite 1900 Denver, CO 80202-2615 Phone (303) 299-5200 Fax (303) 297-2811 FIGURE A-1 SOUTHERN POWER GENERATING FACILITIES SITE LOCATIONS [MAP] A-2 Southern, through its subsidiary Southern Company Services, Inc. ("SCS"), is overseeing the design, procurement, and construction of the Generating Facilities, with the exception of units 1 through 8 at the Dahlberg Facility, which were constructed and completed on a turnkey basis by GE Power Systems, Inc. ("GE"). SCS has developed a standard design for combined-cycle facilities ("CCs"). Certain of the Generating Facilities are based on SCS's second generation standard design ("Gen 2") while others are based on their third generation design ("Gen 3"). The combustion turbine generators ("CTs") for the Generating Facilities are to be supplied by GE. To control the formation of oxides of nitrogen ("NO(x)"), the CTs are equipped with dry low-NO(x) combustors. Construction of the Generating Facilities is being funded through a construction loan from a syndicate of commercial banks (the "Commercial Construction Revolver"). Southern Power is issuing the Notes to pay off the portion of the Commercial Construction Revolver associated with the Dahlberg Facility, Goat Rock 1 and the Wansley Facility, as well as general corporate purposes. Under the terms of the Commercial Construction Revolver, Southern is guaranteeing the completion and the performance of the Generating Facilities. The completion guarantee from Southern includes: (a) that Southern will cover any construction cost over-runs and related interest expense; and (b) Southern is obligated to repay the portion of the Commercial Construction Revolver allocated to one of the Generating Facilities if such facility fails to achieve completion or if the guaranteed capacity and heat rate are not achieved. A portion of the output of the Dahlberg Facility is sold to LG&E Energy Marketing, Inc. ("LEM") through December 31, 2004 under two Purchased Power Agreements assigned to Southern Power by Georgia Power effective July 31, 2001 (the "1998 LEM Power Purchase Agreement" and the "1999 LEM Power Purchase Agreement", and, collectively, the "LEM Power Purchase Agreements"). The remainder of the output is sold to Dynegy Power Marketing ("Dynegy") through May 31, 2005 under a Purchased Power Agreement dated March 2, 2000 (the "Dynegy Power Purchase Agreement"). The output of the Goat Rock Facility will be sold to Georgia Power through May 31, 2010 for Goat Rock 1 and May 31, 2011 for Goat Rock 2 under the terms of a Power Purchase Agreement dated March 30, 2001 (the "Goat Rock Power Purchase Agreement"). The Harris 1 output will be sold through May 31, 2010 to Alabama Power under the terms of a Power Purchase Agreement dated June 1, 2001 (the "Harris 1 Power Purchase Agreement"). The Harris 2 output will be sold through May 31, 2019 to Georgia Power under the terms of a Power Purchase Agreement dated August 6, 2001 (the "Harris 2 Power Purchase Agreement" and, together with the Harris 1 Power Purchase Agreement, the "Harris Power Purchase Agreements"). Southern Power's share of the output of the Stanton Facility will be sold to the Orlando Utilities Commission ("OUC"), Kissimmee Utility Authority ("KUA"), and Florida Municipal Power Authority ("FMPA") through, assuming an effective date of October 1, 2003, October 31, 2013 under the terms of three similar Power Purchase Agreements dated March 19, 2001 (the "Stanton Power Purchase Agreements"). Southern Power is participating in the Stanton Facility with OUC, KUA and FMPA through its subsidiary, Southern Company Florida, LLC ("Southern Company Florida"), under the terms of an Construction and Ownership Participation Agreement dated March 19, 2001 (the "Stanton Ownership Agreement"). The output of the Wansley Facility will be sold to Georgia Power and Savannah Electric through December 31, 2009 under two Contracts for the Purchase of Firm Capacity and Energy dated July 31, 2001 (the "Wansley Power Purchase Agreements"). Georgia Power will operate and maintain the Dahlberg, Goat Rock, and Wansley Facilities pursuant to the terms and conditions of an Amended Operating Agreement dated January 18, 2002, with Southern Power. Alabama Power will operate and maintain the Harris Facility pursuant to the terms and conditions of an Operating Agreement with Southern Power dated June 30, 2001. SCS, on behalf of Southern Company Florida, will operate and maintain the Stanton Facility under the terms of a Service Agreement between Southern Power and SCS dated January 10, 2001. Georgia Power and Alabama Power provide similar services for their respective utility power A-3 generation facilities. Southern Power has entered into Long Term Service Agreements ("LTSAs") with General Electric International, Inc. ("GEI") for the maintenance and overhaul of the CTs at all the Generating Facilities and the steam turbine generators ("STs") at Goat Rock 1 and the Wansley Facility. A summary of general information related to the Generating Facilities is presented in Table 1. TABLE 1 SOUTHERN POWER GENERATING FACILITIES GENERAL INFORMATION
TOTAL COMMERCIAL TERM FUEL UNIT CAPACITY DISPATCH OPERATION OF FACILITY LOCATION TYPE TYPE (MW)(1) TYPE POWER PURCHASER DATE PPA -------- -------- ---- ---- -------- -------- --------------- ---------- ----- Dahlberg 1-7 Athens, GA Oil/ Natural Gas CT 567 Peaking LEM 5/00 2004 Dahlberg 8 Athens, GA Oil/ Natural Gas CT 81 Peaking Dynegy 5/00 2004 Dahlberg 9-10 Athens, GA Oil/ Natural Gas CT 162 Peaking Dynegy 5/01 2005 Goat Rock 1 Lee County, AL Natural Gas CC 571 Intermediate Georgia Power 6/02 2010 Goat Rock 2 Lee County, AL Natural Gas CC 615 Intermediate Georgia Power 6/03 2011 Harris 1 Autauga County, AL Natural Gas CC 618 Intermediate Alabama Power 6/03 2010 Harris 2 Autauga County, AL Natural Gas CC 618 Intermediate Georgia Power 6/03 2019 Stanton Orlando, FL Oil/ Natural Gas CC 411(2) Intermediate OUC/KUA/FMPA 10/03 2013 Wansley Heard County, GA Natural Gas CC 1134 Intermediate Georgia Power/ 6/02 2009 Savannah Electric Total 4,777
-------------------- (1) Represents guaranteed new and clean summer rating with duct firing and steam injection (as described later in the Report), with the exception of the Stanton Facility which is based on an average ambient temperature of 70(Degree)F. (2) Represents Southern Power's 65 percent ownership interest in the Stanton Facility. During the preparation of this Report, we reviewed the various agreements related to the construction, operation, maintenance and management of the Generating Facilities to which Southern Power is a party. These agreements and documents set forth the obligations of each of the parties with respect to the construction, testing, operation, maintenance and management of the Generating Facilities. As Independent Engineer, we have made no determination as to the validity and enforceability of these agreements; however, for the purposes of this Report, we have assumed these agreements will be fully enforceable in accordance with their terms and that all parties will comply with the provisions of their respective agreements. In addition, we have reviewed: (1) the status of permits and approvals and reviewed the status of permit compliance for the Dahlberg Facility, the only plant with significant operating history; (2) geotechnical reports and environmental assessment reports with respect to the sites of the Generating Facilities; (3) the historic and projected levels of production of the Generating Facilities; (4) the historic and projected operating and maintenance expenses of the Generating Facilities; (5) the projected revenues of the Generating Facilities; (6) historical operating records of the Generating Facilities, and (7) operating programs and procedures. Based on our review, we have prepared a projection of revenues and expenses of the Generating Facilities and interest coverage ratios, which are attached as Exhibits A-1 through A-8 to this Report (the "Projected Operating Results"). During the course of our review, we visited and made general field observations of the Generating Facilities and the sites of the Generating Facilities. The general field observations were visual, above-ground examinations of selected areas which we deemed adequate to comment on the existing condition of the sites but which were not in the level of detail necessary to reveal conditions with respect to geological or environmental conditions, the internal physical condition of any equipment, or the conformance with agreements, codes, permits, rules, or regulation of any party having jurisdiction with respect to the sites. A-4 Following the terrorist attacks of September 11, 2001, increased emphasis has been placed on addressing security measures for the infrastructure systems and facilities in the United States. Terrorist activities aimed at the Generating Facilities could interfere with the ability of Southern Power to generate revenues. Additionally, terrorist activities have the potential to affect organizations, other than Southern Power, that are critical to the continuing operation of the Generating Facilities. We have not conducted any independent evaluations or on-site reviews to ascertain the effectiveness of the measures Southern Power has undertaken to address the security issues. In developing the Projected Operating Results, we have relied upon a report by PA Consulting, Inc. ("PA Consulting") attached as Annex B to the Confidential Offering Circular, of which this Report is a part, for projections of the Generating Facilities' electricity sales, market electricity prices when the Power Purchase Agreements are not in effect, fuel costs, and emissions allowance prices. We have not reviewed PA Consulting's methodology and approach in its development of these projections but instead have based our reliance upon their previous experience developing similar projections. THE GENERATING FACILITIES The Dahlberg Facility is an 810 MW peaking, simple-cycle facility consisting of ten PG7121EA ("GE 7EA") CTs. The CTs are dual-fuel units (natural gas and No. 2 fuel oil) and incorporate dry low-NO(x) technology to control the formation of NO(x). The Goat Rock Facility is a 1,186 MW (net) combined-cycle power plant consisting of two gas-fired electric generating plants. Goat Rock 1 is a 571 MW combined-cycle plant based on the SCS Gen 2 design, which incorporates two GE PG7241FA ("GE 7FA") CTs, two Vogt-NEM ("Vogt") heat recovery steam generators ("HRSGs"), and a GE ST. Goat Rock 1 includes duct firing ("full-pressure mode") and steam injection ("power augmentation") capabilities to help increase power output when compared to normal base load operation. Goat Rock 2 is a 615 MW combined-cycle plant based on the SCS Gen 3 design, which incorporates two GE 7FA CTs, two Deltak HRSGs, and an Alstom Power, Inc. ("Alstom") ST. Goat Rock 2 also includes duct firing and steam injection capabilities. The Harris Facility is a 1,236 MW (net) combined-cycle power plant consisting of two SCS Gen 3 gas-fired electric generating units, Harris 1 and 2, each consisting of two 618 MW GE 7FA CTs, two Deltak HRSGs, and an Alstom ST. The Harris Facility includes duct firing and steam injection capabilities. The Stanton Facility is a 633 MW (net) combined-cycle power plant consisting of an SCS Gen 3 combined-cycle power generation plant consisting of two dual-fuel (natural gas and No. 2 fuel oil) GE 7FA CTs, two Deltak HRSGs, and an Alstom ST. Southern Power has a 65 percent ownership interest in the Stanton Facility, or 411 MW. The Stanton Facility includes duct firing and steam injection capabilities. The Wansley Facility is a 1,134 MW (net) combined-cycle power plant consisting of two 567 MW SCS Gen 2 combined-cycle power generation plants, Wansley 6 and 7, each consisting of two GE 7FA CTs, two Vogt HRSGs, and a GE ST. The Wansley Facility includes duct firing and steam injection capabilities. A-5 TABLE 2 SOUTHERN POWER GENERATING FACILITIES MAJOR EQUIPMENT AND CHARACTERISTICS
TOTAL CAPACITY HEAT RATE FACILITY SCS DESIGN CT HRSG ST (MW)(1) (BTU/KWH)(2) -------- ---------- ------ ---- ------ -------------- ------------ Dahlberg N/A (3) GE 7EA N/A N/A 810(4) (4) Goat Rock 1 Gen 2 GE 7FA Vogt GE 571 6,711 Goat Rock 2 Gen 3 GE 7FA Deltak Alstom 615 6,728 Harris 1 Gen 3 GE 7FA Deltak Alstom 618 6,730 Harris 2 Gen 3 GE 7FA Deltak Alstom 618 6,730 Stanton Gen 3 GE 7FA Deltak Alstom 411(5) 6,756 Wansley(6) Gen 2 GE 7FA Vogt GE 1,134 6,706
-------------------- (1) Represents new and clean summer rating guaranteed by Southern with duct firing and steam injection, except for the Stanton Facility which is based on an average ambient temperature of 70(Degree)F. (2) Represents new and clean full-load heat rate guaranteed by Southern in British thermal units per kilowatt-hour ("Btu/kWh") on a higher heating value basis. (3) Dahlberg 1-8 were constructed on a turnkey basis by GE. The design and construction of Dahlberg 9-10 was managed by SCS. (4) Southern guarantee does not apply to the Dahlberg Facility. (5) Represents Southern Power's 65 percent ownership interest in the Stanton Facility. (6) Southern guarantees the Wansley Facility as one plant rather than individual units. THE PROJECT SITES THE DAHLBERG PROJECT SITE The Dahlberg Facility is located on a continuous parcel of land totaling approximately 270 acres in an unincorporated area of Jackson County, in northeast Georgia, approximately 15 miles northwest of Athens, Georgia, and approximately 65 miles northeast of Atlanta, Georgia (the "Dahlberg Project Site"). Highway access to the Dahlberg Project Site is convenient over national highways, state routes and city and county roads. THE GOAT ROCK PROJECT SITE The Goat Rock Facility property is a continuous parcel of land totaling 709 acres located in an unincorporated area of Lee County, in east central Alabama near the Georgia border, approximately one mile west of the Chattahoochee River, about 30 miles northwest of Columbus, Georgia and 10 miles northeast of Auburn, Alabama (the "Goat Rock Project Site"). The Goat Rock Dam is located on the Chattahoochee River. Highway access to the Goat Rock Project Site is convenient over national highways, state routes and city and county roads. Southern Geotech performed the subsurface investigation and prepared a report titled Goat Rock Units 1-4 Geotechnical Investigation, Report for Combined Cycle Foundations (the "Goat Rock Geotechnical Report") dated May 2000. The Goat Rock Geotechnical Report included the Goat Rock 2 power block. Southern Geotech performed the subsurface investigation in four phases starting in June 1999 and concluding in February 2000. The initial phase of the investigation included test borings to determine site acceptability followed by supplementary phases focusing on borrow material availability and determination of depth to top of rock. The final phase included a detailed drilling program focusing on transition areas where individual foundations were and are to be located. These transition areas are defined as critical locations where the subsurface conditions change from soil to rock. The investigations conducted by Southern Geotech indicated that the Goat Rock Project Site is characterized as having three subsurface conditions: an upper zone consisting of reddish-brown silty and sandy plastic clay several feet thick; a middle zone of highly to moderately weathered rock of gray-olive-tan silt and clay with varying amounts of rock fragments; and a lower zone of metamorphic unweathered rock which when tested in the A-6 laboratory yielded break strength (unconfined compression test) results of about 7,500 psi up to 25,000 psi which indicates a very hard, tight rock formation. Southern Geotech noted that groundwater was not identified in soil borings during drilling or in select borings 24 hours after drilling. They did note, however, that water was observed in the rock-cored section of select boreholes at elevations less than the recommended subgrade. Because of the complexity of the subsurface conditions, Southern Geotech developed foundation recommendations for each individual piece of major equipment. Auger-cast piles with H-piles at select locations were recommended for the Goat Rock 2 ST while recommendations for a concrete mat bearing directly on the exposed rock were made for both CTs in the Goat Rock 2 power block. For the cooling towers, foundations placed on engineered backfill were recommended as well as requirements for moisture conditioning, placing, and compacting the backfill material such that a 2,000 pounds per square foot ("psf") bearing capacity can be achieved. Differential settlement and total settlement, estimated by Southern Geotech and as reported in the Goat Rock Geotechnical Report, are consistent with settlement estimations we have seen on other similar projects. During construction, if Southern Power encounters subsurface conditions that are materially different from that which is indicated in the Goat Rock Geotechnical Report, and if these conditions impact the construction cost or schedule, then such impacts and associated costs will be borne by Southern Power and covered under the Southern completion guarantee. THE HARRIS PROJECT SITE The Harris Facility property is a contiguous piece of land totaling 759 acres, located in Autauga County, Alabama, approximately three miles west of Autaugaville, Alabama, and approximately 20 miles northwest of Montgomery, Alabama (the "Harris Project Site"). The Harris Project Site is located in an unincorporated area of Autauga County, in central Alabama directly north of the Alabama River. Highway access to the Harris Project Site is convenient over national highways, state routes and county roads. Southern Geotech performed the subsurface investigation and prepared a report titled Autaugaville Units 1 and 2 Combined Cycle Facility Geotechnical Investigation Report dated January 2001 (the "Harris Geotechnical Report"). The Harris Geotechnical Report included the evaluation of two power block areas for Harris 1 and Harris 2. Southern Geotech performed the subsurface investigation in three phases. The initial phase was conducted in September 1999 and February 2000 to assess the feasibility of constructing the Harris Facility at the present location. The second phase was performed in May and June of 2000 to further characterize the soils and their suitability for foundations. The third investigation was conducted during August and September 2000. The Harris Geotechnical Report summarizes the soil data pertaining to the latest investigation and the configuration of major equipment as described in other sections of this Report. Because Southern Power is self-performing the construction of the Harris Facility, they are assigned the subsurface risk. During construction, if Southern Power encounters subsurface conditions that are materially different from the conditions indicated in the Harris Geotechnical Report, and if these conditions impact the construction cost or schedule, then the differing conditions and resulting budget impacts are to be borne by Southern Power. It is our understanding that any associated cost overrun and schedule delay are covered under the Southern completion guarantee. According to the Harris Geotechnical Report the subsurface soil conditions encountered at the boring locations generally consisted of layers of clays in the upper strata, medium dense sand in the middle strata, and very dense clayey fine- to medium-grained sand in the lower strata. Marine sands of the Eutaw Formation underlie the terrace materials at the northern edge of the Harris Project Site and floodplain deposits were located at the southern edge of the property, which are associated with the historical meandering patterns of the Alabama River. Southern A-7 Geotech notes that the lower strata is considered to be the marker bed across the Harris Project Site and that rock formations were not encountered during the investigation. Based on groundwater observations taken during the subsurface investigation, Southern Geotech indicated that perched groundwater could be encountered during site preparation activity in the areas where the deepest cuts will be required. Southern Geotech further contended that groundwater should not pose a problem to foundation construction for the main power block equipment, as they are located south of the deep cut areas. Groundwater was encountered between elevations 129.5 feet mean sea level ("msl") and 139.5 feet msl in August 2000. Due to saturation softening of the soils on-site, Southern Geotech recommended that surface water control measures be enforced to minimize ponding effects on the finished grade. Based on their geotechnical analysis, Southern Geotech indicates that shallow foundations should provide adequate support for the cooling towers, generator step-up transformers, condensate water storage tank, water treatment plant building, switchyard foundations, pipe support structures, and balance of plant equipment provided that earthwork and site preparation activities are performed as recommended by its report. Auger-cast piles are recommended for the power block equipment with an allocation for use of H-piles to support the equipment where deemed necessary by the foundation design engineer. The Harris Geotechnical Report includes criteria for site preparation and grading, erosion protection for cut slopes, surface water control, construction of the foundations including subgrade preparation, engineered fill classifications, allowable bearing pressure on structural fill, and soil properties for dynamic analysis of the machine foundations. Southern Geotech also provided settlement estimates for the cooling towers and the condensate water storage tank. The anticipated amount of settlement is within the range we would expect for the given structures. The Harris Geotechnical Report did not provide recommendations for additional geotechnical investigations prior to or during the detailed design of the Harris Facility. THE STANTON PROJECT SITE The Stanton Facility is being constructed on property totaling approximately 60 acres just north of the two existing Stanton Energy Center ("SEC") coal-burning units owned and operated by the OUC. The Stanton Facility is located in Orange County, Florida, approximately 10 miles east of Orlando, Florida (the "Stanton Project Site"). The Stanton Project Site is located in an area zoned A-2 with a special exemption consistent with that of the existing SEC. Highway access to the Stanton Facility is convenient over national highways, state routes and county roads. Southern Power reports that upgrades to the existing access road will not be required to facilitate ingress and egress to and from the Stanton Project Site and the existing road should be adequate to support delivery of the Stanton Facility's equipment not requiring heavy haul facilities. Southern Power noted that delivery of the Stanton Facility's heavy equipment is to be made via the existing rail spur that services the SEC. Southern Power anticipates no additional improvements will be required to the rail spur to facilitate delivery of the large equipment. Southern Geotech performed a subsurface investigation and prepared a report titled Stanton Energy Center Combined Cycle Unit A Subsurface Investigation Report dated July 17, 2001 (the "Stanton Geotechnical Report"). The Stanton Geotechnical Report included summaries of the investigation; compilation of select laboratory results used for compaction recommendations; and provided recommendations for development work, foundations and foundation systems, allowable bearing capacities for equipment foundations; and provided guidance on estimated settlement of foundations due to static and dynamic loading. Based on their geotechnical analysis, Southern Geotech recommends that pile foundations support the Stanton Facility's more heavily loaded equipment, including the ST, CTs, and HRSGs. Southern Geotech further recommends that piles in areas located proximate to the silty clay to soft plastic clay layer (at approximately 52 feet to 74 feet below ground surface) be founded on the deeper, very dense sand layer (at approximately 100 feet to 110 feet below ground surface according to the Stanton Geotechnical Report.) Southern Geotech further indicated that shallow A-8 foundations may be considered for the demineralized water storage tank, the fuel oil tank, the cooling tower, the electrical building, transformers, the warehouse and administration building, and other miscellaneous foundations. The Stanton Geotechnical Report includes criteria for site development, compaction, allowable bearing pressure, and surface and ground water control. Southern Geotech also provided settlement estimates for the equipment to be installed on shallow foundations. Information provided by Southern Power noted that two additional borings and further evaluations of settlement potential were conducted at the Stanton Facility. Results of this further investigation and analysis yielded smaller settlement estimations for the tanks and cooling tower. Southern Power noted that the settlement estimations reported above were reviewed by and deemed acceptable to the tank suppliers contingent upon proper construction practices. With respect to the demineralized water storage tank, we note that the Stanton Geotechnical Report states, based on their experience with similar tank structures, Southern Geotech considers these magnitudes of settlement tolerable, provided the pipe connections are properly accounted for. Finally, the remainder of the settlement estimations presented in the Stanton Geotechnical Report appear to be within the range we would expect for the given structures. We note that no foundation recommendations were made for the structures located within the switchyard; however, we understand that a detailed investigation has been completed for the switchyard. Based on information from Southern Power, it is our understanding that there are no additional foundation requirements for the switchyard structures. The Stanton Geotechnical Report did not provide recommendations for additional geotechnical investigations prior to or during the detailed design of the Stanton Facility nor did it provide information relating to corrosion potential and resistivity of the soils. However, subsequent investigations were conducted, including additional borings, evaluations of soil corrosion potential, and resistivity testing. According to Southern Power, no additional recommendations were made as a result of these subsequent investigations. THE WANSLEY PROJECT SITE The Wansley Facility was constructed on land totaling approximately 25 acres, located in Heard County, Georgia near Carrollton, Georgia and approximately 30 miles southwest of Atlanta (the "Wansley Project Site"). The Wansley Project Site is located in an incorporated area of Heard County, in western Georgia directly north of the Chattahoochee River. Highway access to the Wansley Project Site is convenient over national highways, state routes, and county roads. SUMMARY Based on our review, we are of the opinion that, provided Southern Power takes into account the recommendations in the geotechnical reports by Southern Geotech, the sites for the Generating Facilities are suitable for the construction and operation of the Generating Facilities. DESCRIPTION OF THE FACILITIES The following section describes the equipment and systems either in place or proposed for the respective Generating Facilities. Our review of the technical aspects of the equipment included in the Generating Facilities is included in the section entitled "Review of Technology," presented later herein. The Goat Rock, Harris, Stanton and Wansley Facilities are combined-cycle facilities. Each will incorporate GE 7FA CTs. The CTs are to be base-mounted units equipped with dry low-NO(x) combustors to control the formation of NO(x) emissions and an evaporative cooling system to improve performance during the summer months. All units are single-fueled (natural gas) with the exception of the Stanton Facility, which can also burn No. 2 oil. Each CT is designed to deliver in the range of 172 to 176 MW of electric power at 95(degree)F and approximately 45 percent relative humidity at approximate site elevations and corresponding barometric pressures with the inlet evaporative cooler and power augmentation operational. An inlet air filtration system is provided to remove particles in the inlet airstream. An inlet evaporative cooling system is provided to cool the inlet airstream and improve CT performance. NO(x) emissions are guaranteed by GE to 9 parts per million volume, dry basis corrected to 15 percent oxygen ("ppmvd") at the CT exhaust, over an ambient temperature range from 0(degree)F to 105(degree)F and over a range of A-9 50 percent to 100 percent of base load by the use of dry low-NO(x) combustors without power augmentation. With power augmentation, NO(x) emissions are guaranteed by GE to 12 ppmvd at base load. Carbon moNO(x)ide ("CO") emissions are guaranteed by GE to 9 ppmvd between base load and 50 percent of base load without power augmentation for the Harris and Stanton Facilities when firing natural gas. With power augmentation, CO emissions are guaranteed by GE to 15 ppmvd for the Goat Rock, Harris, Stanton, and Wansley Facilities. The CT control and instrumentation system senses, computes, records and displays pertinent CT operational information for use by plant operators and control systems. It also provides protection to the CT against potentially dangerous operating conditions. The high-pressure ("HP") superheated steam from each HRSG will be delivered to an ST to generate additional electricity. The STs for the Goat Rock 2, Harris, and Stanton Facilities are combined, double flow turbines, operating at 3,600 RPM, with reheat, and are single-shaft condensing machines with separate HP, intermediate pressure ("IP"), and low pressure ("LP") sections, and are each nominally rated at 282 MW. The STs for the Goat Rock 1 and Wansley Facilities are reheat, multi-stage, axial exhausting condensing STs suitable for sliding inlet pressure operation, and are each nominally rated at 190 MW. The manufacturers of the HRSGs and STs include Deltak, Vogt, Alstom, and GE. Exhaust gas from each CT is directed to an HRSG, where the energy in the exhaust gas is converted into steam. HP steam is produced by the HRSG and piped to the HP section of the ST. The HP steam is also piped to the CT for power augmentation. The HP ST exhaust is combined with IP steam from the HRSG and returned to the reheat section of the HRSG where it is reheated and then returned to the IP/LP section of the ST. LP steam is produced by the HRSG and supplied to the LP section of the turbine. There, the steam is further expanded and exhausted to a surface condenser. The CTs are equipped with dry low-NO(x) 2.6 ("DLN-2.6") combustors for control of NO(x) emissions. Dry low-NO(x) technology premixes fuel and air to provide a lean flame with a more uniform and lower burning temperature than a conventional burner. Additionally, the dry low-NO(x) combustor has a shorter, lower residence time flame. Both lower temperature and shorter time contribute to NO(x) emissions equal to or lower than that achieved by conventional steam and water injection. Each HRSG is to be equipped with selective catalytic reduction ("SCR") to further reduce the NO(x) emissions from the CTs and the HRSG duct burners. Anhydrous ammonia is vaporized and sprayed into the exhaust gas of the CT in the HRSGs upstream of the SCR and reacts with the exhaust gas in the presence of the catalyst to form nitrogen ("N2") and water vapor. The Dahlberg Facility is designed to be an 810 MW nominal simple-cycle power generation facility consisting of ten separate simple-cycle units. The term "simple-cycle" refers to the Brayton cycle, in which hot combustion gases are expanded through a gas turbine-generator. The major equipment components of the Dahlberg Facility include ten GE PG 7121EA CTs and other typical and necessary auxiliary equipment. In the simple-cycle arrangement, natural gas is fired in the CT for production of power output. Hot exhaust gas from each CT is passed through the exhaust ducting and out through its own stack. The CTs do not use fuel gas heaters to preheat the natural gas for performance enhancements. The CTs are provided with inlet cooling using an evaporative cooling system to improve performance during the summer months. As the CT is a constant volume machine, it is subject to variation in output depending on the density of the air, as affected by temperature and humidity. Output will decrease in warm weather and will increase in cold weather. The CTs are base mounted, dual fuel (natural gas and No. 2 fuel oil) units equipped with dry low NO(x)-I ("DLN-I") combustors for dry control of NO(x) emissions when burning natural gas and incorporate water injection for control of NO(x) emissions when burning No. 2 distillate fuel oil. Each CT is designed to deliver approximately 75 MW (nominal base load) of electric power at 95(degree)F, 14.32 psia and 45 percent relative humidity with evaporative cooling when burning natural gas. In the peak operation mode, the output of each CT increases to 81 MW. Each CT burns natural gas as its primary fuel and No. 2 distillate A-10 fuel oil as its backup fuel. An inlet air filtration system is provided to remove particles in the inlet airstream. Air inlet silencing features are included to control far field sound levels. NO(x) emissions are guaranteed to 9 ppmvd (at 95(degree)F, 14.32 psia, and 45 percent relative humidity) by the use of dry low-NO(x) combustors while burning natural gas. NO(x) emissions while burning No. 2 distillate fuel oil are guaranteed to 42 ppmvd (at 95(degree)F, 14.32 psia, and 45 percent relative humidity) by the use of water injection. Operation on fuel oil is limited to no more than 1,000 hours per year per turbine and only during times that natural gas is unavailable. The CTs are equipped with DLN-I combustors for control of NO(x) emissions while burning natural gas. Traditional control for CTs was comprised of water injection into the combustors to cool the flame and inhibit NO(x) formation, whereas dry low-NO(x) technology premixes fuel and air to provide a lean flame with a more uniform and lower burning temperature than a conventional burner. Additionally, the dry low-NO(x) combustor has a shorter, lower residence time flame. Both lower temperature and shorter time contribute to NO(x) emissions equal to or lower than that achieved by conventional steam and water injection. Control of NO(x) while burning No. 2 distillate fuel oil is performed by injection of demineralized water into the combustion chamber. OFF-SITE REQUIREMENTS FUEL SUPPLY The Dahlberg Facility is located approximately two miles east of a pipeline owned by Transcontinental Gas Pipe Line Corporation ("Transco"). Georgia Power has constructed a 20-inch diameter by 2-mile lateral connecting to the Transco line. Although Georgia Power has reimbursed Transco for the construction of the tap facilities, Transco owns and operates these facilities. Gas transportation service is supplied on a seasonal or daily basis through the Transco line. The lateral is of sufficient capacity to support the ten simple-cycle units at the Dahlberg Facility. In the event of an interruption in natural gas, the Dahlberg Facility has a 3.6 million-gallon, No. 2 fuel oil storage tank on the site. The tank is of sufficient capacity to operate all ten units at base load for over 2 days. Natural gas fuel for the Goat Rock Facility is to be delivered to the Goat Rock Project Site through a 20-inch pipeline lateral extending from the SNG main line located approximately 5.5 miles south of the Goat Rock Project Site. Construction of the 20-inch lateral was completed in September 2001. Southern Power will own and operate the meter station which is to be located adjacent to the pipeline tap location. SCS will purchase natural gas from Gulf Coast for delivery to the Goat Rock Facility. The natural gas pipeline to the Harris Project Site will be 24 inches in diameter and approximately 12 miles in length. The pipeline is to be constructed by Southern and run parallel to the existing 500 kV power transmission line. The pipeline will tie into an existing pipeline owned and operated by Southern Natural Gas ("SNG"), a company that is not affiliated with Southern. SCS will purchase natural gas from Gulf Coast Natural Gas for delivery by SNG to the plant. A metering station will be constructed adjacent to the pipeline tap location and a gas conditioning station will be constructed on-site. The natural gas pipeline to the Stanton Facility is to be 16 inches in diameter and approximately 5.2 miles in length. The pipeline will tie into an existing pipeline owned and operated by Florida Gas Transmission Company. All the gas delivered to the Stanton Facility will be filtered, metered and reduced in pressure at the gas conditioning area, located at the property boundary. The gas will be preheated and flow through a final filter/separator prior to use in the CTs. No. 2 oil is the standby fuel to permit operation in the event of an interruption in the supply of natural gas. No. 2 oil is stored in a tank that will hold approximately 1.7 million gallons of fuel. This is enough fuel for approximately 2.5 days of operation with both CTs at full load output. The fuel oil system includes three truck unloading stations, a storage tank, forwarding pumps and filter. The natural gas pipeline to the Wansley Facility is 30 inches in diameter and will be owned by Southern Power. The gas pipeline connects to the existing Transco system located approximately 6.5 miles south of the Wansley Facility. Southern Power is to reimburse Transco for the construction of the tap and metering facilities A-11 and Transco will retain ownership and operation responsibilities for the newly installed system in accordance with the Interconnect, Reimbursement and Operating Agreement. SCS will purchase Gulf Coast natural gas supplies for delivery of the Wansley Facility's projected peak day gas requirements. Additionally, Southern Power has executed a gas storage contract with Petal Gas Storage Company ("Petal"), to provide fuel storage for all of the Generating Facilities except the Stanton Facility. This contract provides 700,000 million British thermal units ("MMBtu") per day up to a total of 7,000,000 MMBtu for up to ten days if gas flow is interrupted. WATER SUPPLY AND TREATMENT The Jackson County Water and Sewage Authority (the "Water Authority") supplies potable water for use by the Dahlberg Facility personnel for drinking and sanitary purposes. The Dahlberg Facility is limited to a maximum water take of 0.5 million gallons per day ("mgd") at a flow rate of 450 gallons per minute ("gpm") and a pressure of 100 psi until termination of the contract on June 30, 2019. Upon completion of a new reservoir for Jackson County, which has been completed and is expected to be in service by July 1, 2002, the Water Authority will be capable of providing a flow rate of 900 gpm. Demineralized water is supplied by trailer-mounted mobile units through an agreement with Ecolochem, Inc. ("Ecolochem"). Demineralized water is stored in a 2.4 million-gallon storage tank on-site. This storage capacity provides approximately 1.4 days of full load operation while firing No. 2 fuel oil. Primary water usage for the Goat Rock Facility will be for the cooling water system and steam cycle makeup. Expected major water usages during continuous operation include: cooling tower blowdown, cooling tower evaporation, CT evaporative cooler evaporation, CT evaporative cooler blowdown, HRSG blowdown, CT on-line compressor wash water, and CT steam injection losses (during power augmentation operations only). The cooling water system has the greatest water need of all the systems. Raw water will be taken from the Chattahoochee River via an existing unused penstock located within the Goat Rock Dam. Wastewater will be discharged in the tailrace of the same dam. Demineralized water for the Goat Rock Facility will be provided by Water & Power Technologies. The raw water needs of the Goat Rock Facility will be supplied through the existing Goat Rock Dam located approximately one mile east of the plant. The water supply for the Harris Facility will be obtained from two different locations. The primary source of process water is the Alabama River located at the southern edge of the property and will be used for cooling water, makeup water, and fire protection water. The second source of water will be from a nearby municipal water supply system and will be the sole source for the Harris Facility's potable and sanitary water needs. An on-site water treatment system will prepare the river water for use by the plant. Primary uses of the plant's process water will be for the cooling water system and steam cycle makeup. Southern Power estimates a total water demand of approximately 9.5 mgd (which corresponds with the quantity of water Southern Power has applied for withdrawal from the Alabama River), based on an annual average including plant makeup water, for the two power blocks. Filtered water will be used for fire protection purposes and the source for the Harris Facility's demineralized water needs. Demineralized water will be used for on-line CT compressor wash water, steam injection, and general steam cycle makeup. The Harris Facility will include a 1.0 million-gallon demineralized water storage tank and a 300,000-gallon filtered water storage tank. The raw water supply for the Stanton Facility cooling tower makeup is to be pumped, via the installation of new raw water pumps, from OUC's existing makeup pond located at the Stanton Project Site to a distribution system. Demineralized water will be used for on-line CT compressor wash water, water injection during operation on No. 2 fuel oil, source for steam injection (power augmentation), and general steam cycle makeup. Demineralized water is to be provided by OUC from the demineralizer at the SEC coal unit. The SEC demineralized water plant is to be expanded to accommodate the Stanton Facility's anticipated demineralized water requirements. A 1.6 million-gallon tank is to be constructed to provide the necessary storage requirements. Potable water, which is to be used for domestic, washdown, and sanitary purposes is to be provided via an extension of the existing potable water system at the SEC, which is supplied from a nearby municipal potable water system. A-12 The water supply for the Wansley Facility is obtained from the Plant Wansley reservoir located northeast of the Wansley Project Site. A new 60-inch suction header has been installed at the existing reservoir to supply water to the Wansley Facility via an expanded pumping station located at the toe of the reservoir embankment approximately 2 miles northeast of the Wansley Facility. As a result of the proximity of the reservoir to the Wansley Facility, the need for an on-site raw water storage tank is eliminated. Southern Power entered into a ten-year extended term agreement with Ecolochem to build, own, operate, and maintain a water treatment facility for the Wansley Facility. Ecolochem is to supply all water production, filtered and demineralized, for the project. The water treatment system has been sized to accommodate water usage requirements of the Wansley Facility. Two demineralized water storage tanks have been constructed at the Wansley Facility, each one with storage capacity of a million gallons. It should be noted that there are some discrepancies between the water quality requirements set forth in the Wansley Facility LTSA and HRSG contract with respect to total organic carbon ("TOC"). SCS noted that the TOC levels cited for makeup water, feedwater, and steam purity are consistent with industry standards and that TOC is to be removed from the system via HRSG blowdown. Based on discussions with SCS, the anticipated TOC concentration in the make-up water, and the effects dilution will have on the overall TOC concentration, it is our understanding that the anticipated TOC concentration levels will satisfy the LTSA and HRSG water quality requirements. WASTEWATER DISPOSAL Treated wastewater will be conveyed from the Goat Rock Project Site to the tailrace of the Goat Rock Dam via a piping system installed along the transmission tower corridor. The ultimate disposition of the treated wastewater is the Chattahoochee River. Surface water will be channeled directly to an on-site retention pond where it will be allowed time to settle and equalize prior to discharge to the surrounding environment. Process wastewater is pumped to the tailrace of the Goat Rock Dam for discharge. Southern Power notes that while some dilution effects will be realized by the discharge to the tailrace, a specifically-designed dilution system will not be included as part of the wastewater system, which is consistent with the approved water discharge permit for the Goat Rock Facility. The Harris Facility's plant wastewater drains are to be pumped to a wastewater holding pond. HRSG blowdown is to be drained by gravity to the cooling tower basin along with ST start-up drain tank effluent. Wastewater collected in drains throughout the plant that has the potential for containing oil contamination will be collected and treated through an oil/water separator. Surface water from storm events will be collected in an on-site retention pond where it will be allowed to overflow to the Alabama River. Plant wastewater drains at the Stanton Facility are collected in sumps and pumped to a low volume sump, which drains to the SEC existing recycle basin. HRSG blowdown is sent to the cooling tower basin. Wastewater collected in drains throughout the plant that has the potential for containing oil contamination will be collected and treated through an oil/water separator. Surface water from storm events will be directed to the existing facilities at the SEC. Wastewater from the Wansley Facility is to be transferred to the existing ash pond located approximately one mile directly north of the plant. The wastewater will intermingle with the Plant Wansley wastewater discharge in the ash pond. The ash pond was originally constructed to allow for settling of fine particulates prior to discharge to the retention pond. From the outlet of the ash pond, the wastewater gravity feeds to a retention pond located south of the Wansley Project Site where it overflows to the Chattahoochee River. Surface water will be channeled directly to the retention pond and then to the Chattahoochee River. ELECTRICAL INTERCONNECTION The Dahlberg 230 kV Switchyard consists of one bus with five step-up transformer positions and one ongoing transmission line position. An approximate one-mile, two-conductor 230 kV transmission line connects the switchyard to Georgia Power's Center Substation. The Goat Rock 230 kV Switchyard consists of a single bus, single breaker arrangement with three transformer positions each for Goat Rock 1 and 2, and one transmission line position. The Goat Rock 230 kV A-13 Switchyard is to be interconnected via a transmission line to the Southern transmission system at the existing ring bus arranged 230 kV Goat Rock Substation, located approximately 1.5 miles from the Goat Rock Project Site. The Harris 1 230 kV plant switchyard is a single bus, single breaker arrangement with three transformer positions and one transmission line position. The Harris 2 500 kV plant switchyard is a single bus, single breaker arrangement with three transformer positions and one transmission line position. Short transmission lines for Harris 1 and 2 of approximately 0.15 and 0.5 miles in length, respectively, are to be routed from the plant switchyards to new Alabama Power 230 kV and 500 kV switchyards. The 230 kV switchyard at the Stanton Facility consists of a single bus, single breaker arrangement with three transformer positions for generator step-up transformers and one transmission line position. The 230 kV switchyard is to be interconnected to the OUC transmission system at the existing bay, breaker-and-a-half, Stanton Substation No. 17, located approximately one mile from the Stanton Project Site. The Wansley 500 kV Switchyard consists of a single bus, single breaker arrangement with three transformer positions for Wansley 6, three transformer positions for Wansley 7, and one transmission line position. The 500 kV switchyard is to be interconnected to the Georgia Power transmission system at the existing four-bay, breaker-and-a-half Wansley 500 kV Switchyard, located approximately one mile from the Wansley Project Site. We have reviewed interconnection studies for Goat Rock 2 and the Harris Facility. The interconnection studies performed by SCS consisted of two parts, one part to identify modifications and system improvements for the interconnection, and the other to evaluate the capability of the respective transmission systems to receive the output of Goat Rock 2 and the Harris Facility, assuming the power is utilized within the Southern Control Area. The interconnection studies assumed some transmission network improvements. The results of the interconnection study for Goat Rock 2 indicate no stability problems exist for the addition of Goat Rock 2 generation provided particular relaying and breaker upgrades for the interconnection are implemented. The interconnection study assumed transmission improvements with scheduled in-service dates in 2002 and 2003. Southern Power reports that, due to the classification of Goat Rock 2 as a "Native Load Resource," it will make the required improvements to meet the scheduled service dates. The results of the interconnection study for the Harris Facility indicate that the plant does not cause any thermal or voltage problems at the point of interconnection, assuming the new 230 kV Autaugaville-County Line Road transmission line is in place. To maintain stability, the interconnection study recommended that, among other breaker and relaying upgrades, the County Line Road Substation and that the Monty Substation 230 kV lines not be adjacent to the Alabama Power 230 kV switchyard. The analysis performed as part of the interconnection study noted that a 500 kV system improvement is required, and without such improvement, additional transmission service beyond current confirmed transmission service on the South Bessemer-Snowdoun line would be limited. The interconnection study also recommended power system stabilizers for the Harris Facility generators. Although a formal interconnection study was not conducted for the Stanton Facility, OUC performed a series of studies to evaluate the impact of interconnecting the Stanton Facility to the OUC 230-kV transmission system. The studies performed included a short circuit study to identify system improvements required for purposes of the interconnection and a study to evaluate the capability of the transmission system to receive the output from the Stanton Facility. The results of the short circuit study indicated that with the Stanton Facility connected, the available fault current levels at the SEC and several other OUC substations would equal or exceed the interrupting capacity rating of the circuit breakers. As an alternative to replacing the circuit breakers, OUC conducted a separate study to evaluate splitting the bus of the modified OUC Stanton Substation. This would create two separate 230 kV breaker-and-one-half substations tied together by breakers with one substation connected to OUC's existing generation at the SEC site and the other connected to the Stanton Facility. OUC has verbally committed that this work will be completed prior to initial synchronization of the Stanton Facility. The study performed to evaluate the capability of the OUC transmission system identified only one upgrade that was required to an existing 230 kV transmission line. This upgrade required the removal of several swing brackets on the steel structures of the existing line. Southern Power has submitted a request for OUC to perform a stability study to determine whether the integration of the Stanton Facility causes any stability problems on the OUC system. OUC has indicated that it intends to perform the stability study A-14 prior to initial synchronization of the Stanton Facility. The stability impacts of the integration of the Stanton Facility on the OUC transmission system will be determined by the stability study. REVIEW OF TECHNOLOGIES The following section contains a discussion of our review of the critical areas of the Generating Facilities' design and the ability of the equipment and design to meet the projected performance, operating cost, and environmental permit requirements. CT and ST technology has been used in electrical generation and energy recovery for over four decades. The development and operating histories of the specific models utilized by the Generating Facilities are described herein to promote an understanding of the risks associated with these models. GE 7FA CT The Goat Rock, Harris, Stanton, and Wansley Facilities utilize the GE Frame 7241FA CT (the "7241FA"), which represents the fourth technology/operational improvement in the Frame 7F evolution since its introduction to the market in June 1987. The Frame 7F engine design was based on its successful predecessor, the Frame 7E/EA, which has over 775 units installed and has accrued over 15 million operating hours. While the Frame 7F/FA is considered mature technology with over 300 units installed, 3.1 million fired hours, and over 78,000 fired starts fleet-wide, of the 220 7241FA units currently in operation as of April 2002, the fleet leader has only accumulated approximately 16,000 fired hours and 480 fired starts. The GE Frame 7F/FA CT, including the 7241FA, is a two-bearing machine, using a single rotor comprised of a compressor and turbine sections with cold end (compressor side) electric generator drive. Each section consists of a series of discs or wheels and spacers held together with tie bolts. The following discussion presents an overview of the technical development of the 7241FA and identifies the potential risks and risk mitigation strategies for that model. This is followed by a description of serial problems that the 7F/FA fleet has experienced or that GE is in the process of correcting in the last three years, which have the potential to apply to the 7241FA and consequently affect the Projected Operating Results ("Certain Operational Issues"). TECHNICAL DEVELOPMENT Since the market inception of the GE Frame 7F in 1987, there have been five product offerings within the Frame 7F family, based on technology or operational changes. The fourth of these is the 7241FA used by the Goat Rock, Harris, Stanton, and Wansley Facilities. GE's approach to CT development has traditionally followed the philosophy of evolution of designs, by making incremental changes from one frame or model designation to the next. Using this design philosophy in combination with component and full-scale engine shop and field testing, GE is able to retain its previously designed products' most successful attributes, while exercising the full performance capabilities of its new design. It is through full-scale engine testing that GE was able to recognize the potential of the Frame 7F/FA compressor and the impacts of raising the firing temperature to its current level, each of which resulted in developments incorporated into the 7241FA design. PERFORMANCE CHARACTERISTICS In general, GE has improved the performance of its engines with airflow and firing temperature increases, as well as implementing improvements in turbine cooling, and compressor and turbine sealing. Firing temperature refers to rotor inlet temperature, which is experienced at the upstream side of the row one turbine blades. GE also uses advances in material technology throughout the entire CT to enable the performance improvements sought, and to increase the engine reliability by employing materials that are more robust at the temperatures and operational characteristics of the given design. Table 3 compares the major operational characteristics and hours of operation of the Frame 7F evolution through the 7241FA, as of April 2002. A-15 TABLE 3 FRAME 7 F/FA OPERATIONAL CHARACTERISTICS
7191F 7221FA 7231FA 7241FA ------ ------ ------ ------ ISO Output (MW) 150 159 167.8 171.7 ISO Heat Rate (LHV)(Btu/kWh) 9,880 9,500 9,380 9,360 Firing Temperature(degree)F 2,300 2,350 2,400 2,420 Pressure Ratio 13.5:1 15.1:1 14.9:1 15.5:1 Units in Service(1) 16 44 30 220 Fleet Leader Operating Hours(1) 53,000+ 68,000+ 33,000+ 16,000+ Fleet Leader Commercial Operation Date 1991 1993 1997 1999
-------------------- (1) As of April 2002. KEY FEATURES The specific changes made to the 7231FA model design that result in the 7241FA designation are the following: (1) firing temperature increase from 2,400(o)F to 2,420(degree)F; (2) increase in compressor airflow and pressure ratio by modulating the compressor inlet guide vanes to a new position; (3) the use of directionally-solidified row one turbine blades; (4) new thermal barrier coatings on the first stage turbine vanes and blades; and (5) the use of improved cooling and sealing throughout the hot gas path. In addition to changes (1) through (5) delineated above, GE has modified the compressor section of all 7241FA CTs, which have been shipped after September 12, 2000 (which include the CTs utilized by the Goat Rock, Harris, Stanton, and Wansley Facilities) by incorporating the following features: (a) the outer diameters of the first five stages of compressor blades have been flared to a slightly larger diameter, adding 0.35 inches to the radius of the first stage compressor blade, tapering to a zero inch increase by the stage six blade; (b) the compressor casing and stage one through stage five compressor vanes, also referred to in the industry as diaphragms, have been modified to accommodate the flaring in the first five stages of compressor blading; and (c) the inlet casing (the casing upstream of the compressor section's inlet guide vane) and the inlet guide vane aerodynamics have been further optimized to reduce inlet aerodynamic losses. GE reports that modifications (a), (b), and (c) have been made to increase commonality with the GE 7251FB (GE's newest Frame 7F product offering). This allows GE to better optimize its manufacturing production cycles. These modifications have not resulted in a re-rating of the 7241FA's base thermodynamic performance, as compared to the 7241FAs shipped prior to September 12, 2000. GE further reports that modifications (a), (b), and (c) have been tested at full-speed-no-load at its Greenville, South Carolina manufacturing facility, and have been successfully operated in the field at several commercial facilities. Though the 7241FA fleet leader has operated in excess of 16,000 fired hours, the effects of long-term operational issues related to most of these changes have not yet been validated by field experience. COMBUSTION SYSTEM The Goat Rock, Harris, Stanton, and Wansley Facilities utilize the GE DLN-2.6 combustion system as the primary emissions control mechanism. The DLN-2.6 is the latest development in the GE low emissions combustion technology, and the third major technology and operational change made in the dry low-NO(x) evolution at GE. The DLN-2.6 is a can-annular design (containing 14 individual combustor baskets and transition pieces on the 7241FA), which has six premixed fuel nozzles per combustor, five on the periphery and one in the center. For the 7241FA, GE offers a standard NO(x) guarantee of 9 parts per million ("ppm") when firing natural gas fuel over a range of 50 percent to 100 percent of base load. The DLN-2.6 is an incremental technology improvement over its predecessor the DLN-2.0, which lacks the sixth premixed fuel nozzle in the center of each combustor. The DLN-2.0 design was first operated in commercial service in February 1994, and the DLN-2.6 was placed into service in March 1996. As of April 2002, GE reports over 380 units operating with its dry low-NO(x) technology with over 4.7 A-16 million fired hours, of which 1,000,000 hours were on Frame 7F machines. DLN-2.6 in all its applications has almost accumulated 895,000 fired hours. Of the DLN-2.6 systems currently operating at 2,420(degree)F, the nominal firing temperature of the 7241FA, the fleet leader has in excess of 16,000 fired hours as of April 2002. The sixth fuel nozzle in the center of the DLN-2.6 combustor design was added to the DLN-2.0 design to allow 9 ppm NO(x) control from 100 percent down to 50 percent of base load, which was unachievable over that entire range without the change. In addition, the DLN-2.6 operates over the entire load range without the requirement of a diffusion flame, whereas the DLN-2.0 utilizes a diffusion flame at low loads. This allows GE to maintain the four fuel manifold system of the DLN-2.0, whereas a diffusion flame stage in the DLN-2.6 would have necessitated a fifth manifold. Though the DLN-2.6 has demonstrated 9 ppm NO(x) between 50 and 100 percent of base load during recent 7241FA commissioning, GE's long-term parts life projections for the DLN-2.6 related to the firing temperature increase and the addition of the sixth fuel nozzle have not yet been confirmed by long-term operation. OPERATIONAL ISSUES In the last three years, GE Frame 7F/FA machines have experienced certain operational problems or GE is in the process of correcting prior problems in its compressor and combustion sections for that Frame. Some of these problems are related to characteristics of the earlier Frame 7F/FA designs, and GE reports that all 7241FA machines will include the appropriate changes to prevent these problems found on earlier model 7F/FA machines from reoccurring on the 7241FAs utilized by the Goat Rock, Harris, Stanton, and Wansley Facilities. A brief description of the problems and the subsequent resolutions are given below. Compressor Section. In the first quarter of 2001, failed seventeenth stage diaphragms were discovered in two 7241FAs at one project while inspecting the CTs during a boroscope inspection following high vibration levels in one of the CTs. GE reported that the root cause of the cracking was high aerodynamic stresses caused by a flow separation downstream of a recessed area in the diaphragm. GE explained that the recessed areas were machined into the diaphragms for bolting the four seventeenth stage compressor segments of the diaphragms together. GE further reported that the aerodynamic stresses were exacerbated by high mass flows through the compressor at the site where the cracking was found, as the cracking is believed to have occurred while commissioning the plant during cold temperatures. GE reported that its permanent remedy to this issue involves covering the bolt hole recession with a blank of the same contour as the diaphragm to eliminate the aerodynamic separation which GE reports excited the compressor diaphragms. GE reported that its interim solution is to utilize inlet bleed heat at a higher temperature than it had employed for such heating prior to this issue being encountered. Inlet bleed heating is the process of diverting intra-stage compressor air to the compressor's inlet to blend the incoming cold ambient air with the warmer compressor intra-stage air. GE believes that these remedies have mitigated the flow separation issue that led to the high aerodynamic stresses, and that similar issues should not occur on subsequent units that include these remedies. On August 23, 2001, GE reported to its customers via a Technical Information Letter, that the first row (referred to as Row 0 by GE) and possibly several other of the first few stages of its 7F/FA and 9F/FA compressors are susceptible to erosion, cracking, and potentially failure due to the effects of performing online compressor water washes. Many operators utilize online water washing of the compressor as a time effective process for reducing the thermodynamic performance effects of compressor fouling, since this type of cleaning may be performed when a unit is at load, selling its power to the grid. Through this Technical Information Letter, GE has limited its customers to less than 100 hours of online water washing, prior to a GE service representative performing an inspection of the given unit, at which point the service representative may either allow the given unit to resume online water washing, or may prescribe some remediation to affected blades, if any exist. GE reported that a failure in the first stage blade of a 9FA compressor was the result of excessive use of the online water washing system (i.e., operation not commensurate with the GE operations and maintenance manuals). GE has additionally reported that it is currently designing a modified water washing system that would help reduce the erosion that occurs due to online water washing under prescribed methods for operations and maintenance, as well as making it less likely to result in damage to the compressor under conditions where an owner chooses to A-17 operate the machine in a manner inconsistent with such methods. GE reported that it is confident that if the owners of 7F/FA and 9F/FA machines operate the water washing system in accordance with the operations and maintenance manuals that excessive erosion and/or cracking of the compressor blades would not likely result; however, a risk potentially exists that maintenance of the first few stages of the compressor blades may be required more frequently than predicted by typical GE maintenance intervals for such parts if the facilities expect to regularly utilize its online water washing system. GE did not state when it expects to either remove the limitations imposed by the Technical Information Letter or provide an alternative water washing system that minimizes the likelihood of damage to 7F/FA and 9F/FA compressors. DLN-2.6 Combustion System. Flashback has occurred in some Frame 7F/FAs, and to a greater degree in Frame 9F/FA combustors. Flashback occurs when the flame moves backward into the fuel nozzle premix zone (an area not designed to tolerate high temperatures), thus overheating and subsequently damaging the nozzle tips. GE formed a task force to identify all of the causes of flashback and to determine solutions to the problem, and has tested various combustor configurations to reduce the risk of flashback. GE deduced that one cause of flashback was recirculation zones that allowed flame to attach just downstream of the fuel nozzle premix zone during transient conditions (e.g., load changes). Since then, GE has selected a dry low-NO(x) fuel-air-staged, faired nozzle combustor design, and is equipping all of its current and future Frame 7F/FA units with this design, including the Goat Rock, Harris, Stanton, and Wansley Facilities. GE reports no flashback events since installation of the faired nozzle design, which has accumulated over 485,000 fired hours in Frame 7F/FA machines as of April 2002. In addition, GE is recommending installation of its on-site monitoring service to assist the user in monitoring the occurrence of flashback, which enables GE to alert the customer if a flashback incident has occurred so that corrective action can be taken. Condensation of liquid hydrocarbons in gas fuel has been identified as another cause of flashback. To mitigate this potential problem, the design of the Goat Rock, Harris, Stanton, and Wansley Facilities incorporates a heater in the gas supply line to raise the temperature of the incoming fuel gas above the liquid dewpoint, before the gas enters the feed lines to the CT. GE 7EA CT The Dahlberg Facility utilizes a GE 7EA CT set equipped with dry low-NO(x) combustors. The 7EA is a 3,600-rpm heavy-duty CT with a 17-stage axial flow compressor and a 3-stage power turbine designed to serve the 60 Hz power generation needs for utility and industrial service. TECHNOLOGY EVOLUTION GE's approach to CT development is discussed in the GE 7FA CT section of this Report. As mentioned in that section, over 775 GE Frame 7E/EA units are in operation worldwide, and have accumulated over 15 million hours of operation since the initial introduction in the 1970s. The 7EA product offering first achieved commercial operation in the mid-1980s. While the 7EA, an upgrade of the GE 7E CT, has evolved during its approximate 20-year operating history, the base design of the current 7EA is largely unchanged from its predecessors. Some of the key features utilized in the current 7EA CT are a 2,035(Degree)F firing temperature, certain improved hot gas path part alloys, better sealing, increased compressor massflow, and the use of thermal barrier coatings. Additionally, the Dahlberg Facility CTs utilize GE dry low-NO(x) combustion technology. GE has reported that its GE 7EA dry low-NO(x) combustion system has consistently achieved 9 ppmvd NO(x) control while operating on natural gas at the nominal GE 7EA firing temperature of 2,035(Degree)F. OPERATING EXPERIENCE The 7EA is a heavy-duty gas turbine designed for 60 Hz applications. GE reports that over 775 units are currently in service and the Frame 7 models have accumulated more than 15 million hours of service. A-18 Based on information provided by the Operational Reliability Analysis Program ("ORAP") data system, which is owned and managed by Strategic Power Systems, Inc., Table 4 summarizes the simple-cycle plant level availability and starting reliability of the 7EA units for the period 1994 through 1999. TABLE 4 SIMPLE-CYCLE PLANT AVAILABILITY AND STARTING RELIABILITY
1994 1995 1996 1997 1998 1999 ---- ---- ---- ---- ---- ---- Number of Units Reporting 38 39 41 46 53 54 Availability 96.5 93.3 96.1 94.5 97.0 97.1 Starting Reliability(%) 97.7 96.5 96.1 96.5 97.4 97.9
In general, CT availability should be considered over the typical 6-year maintenance cycle of units in base load service. In addition, other business factors, including dual-fuel operation and emphasis on seasonal or daily peak operation, can influence expected availability. Overall, the GE availability values support an expectation of availability approaching 95 percent for a frame 7EA based facility. SUMMARY Based on our review, we are of the opinion that, based on GE's previously demonstrated capability to address the issues similar to those related to the Frame 7FA described herein, the power generation technologies proposed for the Generating Facilities are sound, proven methods of energy recovery. If constructed, operated and maintained as proposed by Southern Power, the Generating Facilities should be capable of meeting the requirements of the Power Purchase Agreements and the currently applicable environmental permit requirements. Furthermore, all off-site requirements of the Generating Facilities have been adequately provided for, including fuel supply, water supply, wastewater disposal, and electrical interconnection. In addition, the proposed method of design, construction, operation, and maintenance of the Generating Facilities has been developed in accordance with generally accepted industry practice and has taken into consideration the current environmental, license and permit requirements that the Generating Facilities must meet. ESTIMATED USEFUL LIFE We have reviewed the quality of equipment installed at the Generating Facilities and the general plans for operating and maintaining the Generating Facilities. Based on our review and provided that: (a) the units are operated and maintained by the operators in accordance with the policies and procedures as presented by Southern Power, (b) all required renewals and replacements are made on a timely basis as the units age, and (c) gas and oil burned by the units are within the expected range with respect to quantity and quality, we are of the opinion that the Generating Facilities should have useful lives of at least 20 years. PERFORMANCE TESTS AND GUARANTEES The Goat Rock, Harris, Stanton, and the Wansley Facilities were or are being constructed under an owner construction management approach rather than having a turnkey, engineer, procure, and construct ("EPC") type contractor provide the respective services. Under the construction management approach, Southern Power accepts more responsibility for ensuring that these projects are engineered, designed, constructed, and commissioned properly. The construction management approach also requires Southern Power to be more responsible for contract interface issues and the associated impacts on project cost and schedule. Under a traditional EPC contract, an owner of a project would place all these responsibilities on the EPC contractor, which increases the contract cost to account for the added risk exposure the contractor assumes. Southern Power, through SCS, is assuming this responsibility for the performance of the Goat Rock, Harris, Stanton, and the Wansley Facilities. A description of the performance tests and Southern completion guarantees for these units are presented below. A-19 Table 5 indicates the performance guarantees provided by Southern for Goat Rock, Harris, Stanton, and the Wansley Facilities, as set forth in Credit Agreement for the Commercial Construction Revolver dated November 1, 2001 (the "Construction Revolver Credit Agreement"). Goat Rock 1 and the Wansley Facility declared commercial operation under their respective Power Purchase Agreements on June 1, 2002. Southern Power reports that: (1) the Wansley Facility has completed its initial net plant output test under the Wansley Power Purchase Agreements; and (2) Goat Rock 1 underwent a preliminary net plant output test sufficient to demonstrate the initial capacity to be sold under the Goat Rock Power Purchase Agreement, but approximately 10 MW less than the guaranteed output under the Construction Revolver Credit Agreement. Southern Power plans to retest Goat Rock 1 in the near future and believes it has identified the cause of the lower than guaranteed performance. TABLE 5 SOUTHERN PERFORMANCE GUARANTEES
OUTPUT HEAT RATE (MW)(1) (BTU/KWH)(2) ------- ------------ Goat Rock 1(3) 571 6,711 Goat Rock 2 615 6,728 Harris 1 618 6,730 Harris 2 618 6,730 Stanton 633(4) 6,756 Wansley(3) 1,134 6,706
-------------------- (1) Represents net output at summer peak conditions, except for the Stanton Facility which is based on an average ambient temperature of 70(Degree)F. (2) Represents base mode heat rate guarantee on a higher heating value basis and at rated conditions, based on site characteristics. (3) Recently entered into commercial operation. Initial net plant output test complete for the Wansley Facility, but only preliminary testing completed on Goat Rock 1. (4) Represents full output of the Stanton Facility. Southern Power owns 65 percent of the Stanton Facility. As a result of Southern Power's construction management approach to engineering, design, procurement and construction of the Generating Facilities (instead of hiring a turnkey contractor), the only performance test program to verify project output and heat rate are the performance tests Southern Power is required to perform in the Power Purchase Agreements and the Construction Revolver Credit Agreement. Under the terms of the Construction Revolver Credit Agreement, the heat rate and output tests are to be conducted in accordance with the guidelines established in the applicable American Society of Mechanical Engineer's Power Test Codes, prudent utility practices, and routine operating conditions. Emissions testing is to be performed in accordance with the air permit and CT and HRSG purchase agreements. Successful demonstration of emissions with air permit requirements is part of achieving Substantial Completion as defined in the Construction Revolver Credit Agreement. The equipment manufacturers (GE, Deltak, and Vogt) offer certain emissions guarantees for their respective equipment. These guarantees, in some cases, are not consistent with the emission limits set forth in the air permits. Notwithstanding the apparent inconsistencies in the guarantees, the design of each of the Generating Facilities includes provision for the installation of an oxidation catalyst should one be required to comply with air permit limits for CO and volatile organic compounds ("VOCs"). The performance test program that Southern Power is to perform includes a 7-day reliability test which is intended to demonstrate that the facilities are capable of continuous, reliable operation at various load points. The reliability test is to be conducted during a continuous 168-hour period during which the relevant project shall, among other things, achieve an equivalent availability factor of 97 percent, operate for at least 24 hours in the Summer Peak Output mode for such project (providing ambient conditions allow for such operation and, in any event, at least 6 A-20 continuous hours of operation in that mode is required), and operate for an additional 100 hours in either the "Base Mode Heat Rate" mode or the "Summer Peak Output" mode (or at a point between these two operating modes). During the reliability test, the facility is to be operated in accordance with prudent utility practice and all laws, permits and regulations applicable to such project including all emissions requirements imposed by the air permit. The Power Purchase Agreements for the Goat Rock, Harris, and Wansley Facilities require the facilities to be capable of "producing energy and delivering same to the Transmission System through the Interconnection Point on a reliable basis." The Power Purchase Agreements do not address how Southern Power is to demonstrate a reliable basis prior to entering into commercial operation. Based on discussions with Southern Power, it is our understanding that SCS determines when a respective plant is ready for commercial operation based on the success of the commissioning program, CT and HRSG component tests, and overall plant performance tests. Southern Power represented that once they have completed the commissioning program, including the reliability test discussed above, that most of the potential reliability problems should have been identified and corrected, and that it should be able to produce and deliver energy to the transmission system of the power purchaser on a reliable basis. Individual CT, ST, and HRSG component tests are typically not conducted on projects constructed using a turnkey approach. SCS has included such tests in the respective equipment purchase orders/agreements. As such, the commissioning program SCS is to perform on the facilities incorporates more equipment testing than what is typically provided for on turnkey projects. Based on our review, we are of the opinion that the performance guarantees proposed for the Generating Facilities under construction, if all the equipment contract guarantees are considered in their entirety, are similar to the performance tests of turnkey projects with which we are familiar. OPERATING HISTORY Dahlberg 1-8 have been in operation since May 2000 and Dahlberg 9-10 have been in operation since May 2001. A summary of the Dahlberg Facility operating history is presented below. Goat Rock 1 and the Wansley Facility declared commercial operation under their respective Power Purchase Agreements on June 1, 2002. As such, no operating results are available for these facilities. Table 6 provides operating history for the Dahlberg Facility from the period of May 1, 2000 through April 1, 2002. A-21 TABLE 6 DAHLBERG OPERATING HISTORY(1)
NET ACTUAL STARTS EAF GENERATION HEAT RATE NET CAPACITY / ATTEMPTED UNIT (%) (MWH) (BTU/KWH)(2) FACTOR(%)(3) STARTS ---- ----- ---------- ------------ ------------ ------------- Dahlberg 1 92.51 98,227 12,178 7.22 213/213 Dahlberg 2 85.84 95,635 12,390 7.03 195/195 Dahlberg 3 86.86 97,848 12,231 7.19 208/208 Dahlberg 4 77.03 95,474 12,278 7.02 209/209 Dahlberg 5 94.98 101,739 12,141 7.48 211/211 Dahlberg 6 93.77 97,144 12,108 7.14 193/193 Dahlberg 7 61.21 73,494 12,081 5.40 137/137 Dahlberg 8 89.37 89,951 12,311 6.61 169/169 Dahlberg 9 94.34 16,858 13,264 2.19 45/45 Dahlberg 10 95.64 19,596 12,940 2.55 46/46
-------------------- (1) From May 1, 2000 through April 1, 2002 for Dahlberg 1-8 and from May 1, 2001 through April 1, 2002 for Dahlberg 9-10. (2) On a Higher Heating Value ("HHV") basis. (3) Based on a peak output rating of 81 MW per unit. CAPACITY AND HEAT RATE Each of the respective Power Purchase Agreements includes specific capacity designation and testing criteria as described below. The capacity payments included in the Projected Operating Results presented later herein are based upon the contractual capacity requirements in the Power Purchase Agreements through their respective terms. Based on these capacity values, PA Consulting has estimated the energy generation and fuel consumption of the Generating Facilities based upon its projection of seasonal operation at various load levels and modes of operation. THE DAHLBERG FACILITY Under the terms of the LEM Power Purchase Agreements, the Dahlberg Facility is required to provide a total contract capacity of 577.5 MW during the summer months and 646.8 MW when firing natural gas during the winter months. Energy payments are based on a heat rate of 12,300 Btu/kWh during the summer months and 11,931 Btu/kWh when firing natural gas during the winter months. These output and heat rate values are subject to degradation as set forth in the LEM Power Purchase Agreements. Under the terms of the Dynegy Power Purchase Agreement, the Dahlberg Facility is required to provide a total contract capacity of 225 MW. Energy payments are based on a heat rate of 12,500 Btu/kWh during the summer months and 12,100 Btu/kWh during the winter months. Based on information provided by Southern Power, we have estimated the long-term annual average capacity to be 401 MW for Dahlberg 1-5, 160 MW for Dahlberg 6-8, and 241 MW for Dahlberg 9-10. This estimate includes a levelized allowance for long-term degradation. Under the terms of the LEM Power Purchase Agreements, fuel is purchased by Southern Power and reimbursed by LEM according to the summer and winter heat rate curves in the LEM Power Purchase Agreements. Heat rate degradation is provided for in the LEM and Dynegy Power Purchase Agreements. Dynegy is responsible for purchasing fuel under the terms of the Dynegy Power Purchase Agreement. Based on information provided by Southern Power, we have estimated the long-term, full-load heat rate, including a levelized allowance for long-term degradation, to be 12,352 Btu/kWh for the Dahlberg Facility. For the purposes of the Projected Operating Results, we A-22 have assumed that the heat rate of the Dahlberg Facility will be in accordance with the heat rate curves in the LEM and Dynegy Power Purchase Agreements and no heat rate penalties will be incurred or bonuses achieved. THE GOAT ROCK FACILITY The monthly capacity payments under the Goat Rock Power Purchase Agreement are based on the "Designated Capacity" for that annual period. The Designated Capacity is adjusted by a monthly capacity payment factor of 0.15 for the months of June through September and 0.05 for all other months. The Designated Capacity is defined as the output nominated by Southern Power at the reference conditions or "Rated Conditions," which are 95(degree)F and 45 percent relative humidity. The Demonstrated Capability is determined by test upon commercial operation as the amount of capacity Goat Rock 1 and 2 are able to provide at each mode of operation corrected to "Rated Conditions" of 95(degree)F and 45 percent relative humidity: "normal mode", "full-pressure mode", and "full-pressure mode with power augmentation". Southern Power cannot nominate more than the Demonstrated Capability at "full-pressure mode with power augmentation" as the Designated Capacity. All capacity testing will be adjusted to the Rated Conditions using correction curves supplied by SCS. The Demonstrated Capability of the Goat Rock Facility will be measured by the installed metering system. No test tolerances or measurement uncertainties are to be permitted. All auxiliary equipment must be operated in a normal manner consistent with prudent utility practices. On the date of the capacity tests, Southern Power is to bring the Goat Rock Facility to maximum normal capability. The tests will be scheduled between the weekday hours of 11:00 a.m. and 7:00 p.m. and will be conducted over an eight consecutive hour period, or less, at the respective power purchaser's request. The capacity test will establish the Demonstrated Capability and will be based on the average demonstrated net hourly output, corrected to Rated Conditions, by use of correction curves supplied by SCS. The Demonstrated Capability of the unit will be the average net output over the test period corrected to Rated Conditions. In the event that the Goat Rock Facility is unable to supply the Designated Capability, Southern Power may supply the requested output from alternate resources. The Demonstrated Capability will be determined prior to degradation of the Goat Rock Facility; therefore, we have assumed that Southern Power will nominate a Designated Capacity equal to the Demonstrated Capability in full-pressure mode with power augmentation less allowances for non-recoverable degradation, fouling, and other operational factors that make it difficult to achieve tested values on a day-to-day basis. Based on information provided by Southern Power, we have estimated the long-term Demonstrated Capability to be 564 MW for Goat Rock 1 and 595 MW for Goat Rock 2. This estimate includes a levelized allowance for long-term degradation. Southern Power has reported that Goat Rock 1 underwent a preliminary net plant output test sufficient to demonstrate the initial capacity to be sold under the Goat Rock Power Purchase Agreement, but approximately 10 MW less than the guaranteed output under the Construction Revolver Credit Agreement. Southern Power plans to retest Goat Rock 1 in the near future and believes it has identified the cause of the lower than guaranteed performance. Southern Power has 90 days from June 1, 2002 to retest Goat Rock 1 and establish its initial capacity under the terms of the Goat Rock Power Purchase Agreement. For the purpose of the Projected Operating Results, we have assumed that retesting of Goat Rock 1 will demonstrate conformance with the guaranteed output. Under the terms of the Goat Rock Power Purchase Agreement, fuel is purchased by Georgia Power. Southern Power guarantees summer and winter heat rate curves in the Goat Rock Power Purchase Agreement and will reimburse Georgia Power if these guarantees are not met. The demonstrated normal-mode and full-pressure mode capabilities will determine the breakpoints at which the heat rates will be applied to the various operating modes. Heat rate degradation is provided for in the Goat Rock Power Purchase Agreement. Based on information provided by Southern Power, we have estimated the long-term, full-load heat rate, including a levelized allowance for long-term degradation, to be 6,919 Btu/kWh for Goat Rock 1 and 6,858 Btu/kWh for Goat Rock 2. For the purposes of the Projected Operating Results, we have assumed that the heat rate of the Goat Rock Facility will be in accordance with the heat rate curves in the Goat Rock Power Purchase Agreement and no heat rate penalties will be incurred or bonuses achieved. A-23 THE HARRIS FACILITY The monthly capacity payments under the Harris Power Purchase Agreements are based on the "Designated Capacity" for that annual period. The Designated Capacity is adjusted by a monthly capacity payment factor of 0.15 for the months of June through September and 0.05 for all other months. The Designated Capacity is defined as the output nominated by Southern Power at the reference conditions or "Rated Conditions," which are 95(degree)F and 45 percent relative humidity. The Demonstrated Capability is determined by test upon commercial operation as the amount of capacity Harris 1 and 2 are able to provide at each mode of operation corrected to "Rated Conditions" of 95(degree)F and 45 percent relative humidity: "normal mode", "full-pressure mode", and "full-pressure mode with power augmentation." Southern Power cannot nominate more than the Demonstrated Capability at "full-pressure mode with power augmentation" as the Designated Capacity. All capacity testing will be adjusted to the Rated Conditions using correction curves supplied by SCS. The Demonstrated Capability of the Harris Facility will be measured by the installed metering system. No test tolerances or measurement uncertainties are to be permitted. All auxiliary equipment must be operated in a normal manner consistent with prudent utility practices. On the date of the capacity tests, Southern Power is to bring the Harris Facility to maximum normal capability. The tests will be scheduled between the weekday hours of 11:00 a.m. and 7:00 p.m. and will be conducted over an eight consecutive hour period, or less, at the respective power purchaser's request. The capacity test will establish the Demonstrated Capability and will be based on the average demonstrated net hourly output, corrected to Rated Conditions, by use of correction curves supplied by SCS. The Demonstrated Capability of the unit will be the average net output over the test period corrected to Rated Conditions. In the event that the Harris Facility is unable to supply the Designated Capability, Southern Power may supply the requested output from alternate resources. The Demonstrated Capability will be determined prior to degradation of the Harris Facility; therefore, we have assumed that Southern Power will nominate a Designated Capacity equal to the Demonstrated Capability in full-pressure mode with power augmentation less allowances for non-recoverable degradation, fouling, and other operational factors that make it difficult to achieve tested values on a day-to-day basis. Based on information provided by Southern Power, we have estimated the long-term Demonstrated Capability to be 595 MW for Harris 1 and 595 MW for Harris 2. This estimate includes a levelized allowance for long-term degradation. Under the terms of the Harris Power Purchase Agreements, fuel is purchased by Alabama Power and Georgia Power. Southern Power guarantees summer and winter heat rate curves in the Harris Power Purchase Agreements and will reimburse Alabama Power and Georgia Power if these guarantees are not met. The demonstrated normal-mode and full-pressure mode capabilities will determine the breakpoints at which the heat rates will be applied to the various operating modes. Heat rate degradation is provided for in the Harris Power Purchase Agreements. Based on information provided by Southern Power, we have estimated the long-term, full-load heat rate, including a levelized allowance for long-term degradation, to be 6,871 Btu/kWh for Harris 1 and Harris 2. For the purposes of the Projected Operating Results, we have assumed that the heat rate of the Harris Facility will be in accordance with the heat rate curves in the Harris Power Purchase Agreements and no heat rate penalties will be incurred or bonuses achieved. THE STANTON FACILITY Under the terms of the Stanton Power Purchase Agreements, the capacity payment is the product of the "Demonstrated Capability" times the Annual Capacity Charge. The "Designated Capability" is defined as the net capacity of the project, determined by a periodic capacity test, adjusted to 70(degree)F and 45 percent relative humidity. On the date of the capacity tests, Southern Power is to bring the Stanton Facility to maximum normal capability. The tests will be scheduled between the weekday hours of 11:00 a.m. and 7:00 p.m. and will be conducted over an eight consecutive hour period, or less, at the respective power purchaser's request. The capacity test will establish the Demonstrated Capability and will be based on the average demonstrated net hourly output, corrected to A-24 Rated Conditions, by use of correction curves supplied by SCS. The Demonstrated Capability of the unit will be the average net output over the test period corrected to Rated Conditions. Based on information provided by Southern Power, we have estimated the long-term Demonstrated Capability to be 621 MW for the Stanton Facility. This estimate is based on the output at an ambient temperature of 70(degree)F and includes a levelized allowance for long-term degradation. The long-term output at the average annual temperature, including an allowance for degradation, is estimated to be 606 MW. Under the terms of the Stanton Power Purchase Agreements, fuel is purchased by OUC and reimbursed by the power purchasers at cost. The demonstrated normal-mode and full-pressure mode capabilities will determine the breakpoints at which the heat rates will be applied to the various operating modes. Heat rate degradation is provided for in the Stanton Power Purchase Agreements. Based on information provided by Southern Power, we have estimated the long-term, full-load heat rate, including a levelized allowance for long-term degradation, to be 6,936 Btu/kWh for the Stanton Facility. For the purposes of the Projected Operating Results, we have assumed that the heat rate of the Stanton Facility will be in accordance with the heat rate curves in the Stanton Power Purchase Agreements and no heat rate penalties will be incurred or bonuses achieved. THE WANSLEY FACILITY The monthly capacity and fixed operating and maintenance ("O&M") payments under the Wansley Power Purchase Agreements are based on the "Contract Capacity Rating" for that annual period. The Contract Capacity Rating will be based on the actual demonstrated capability following performance testing corrected to 95(Degree)F and 45 percent relative humidity. The Contract Capacity Rating is to be declared each year thereafter. The capacity dedicated to Georgia Power is to be 82.33 percent of the Contract Capacity Rating, with the remaining output dedicated to Savannah Electric. Also to be declared is the minimum normal capability, the maximum normal capability, over-pressure mode (similar to full-pressure mode on the other Generating Facilities) capability and capability in over-pressure mode with power augmentation. During the months of June through September, the capability in over-pressure mode with power augmentation is not to be less than the Contract Capacity Rating. In the event that the Wansley Facility is unable to supply the Contract Capacity Rating, Southern Power may supply the requested output from alternate resources. The demonstrated capability will be determined prior to degradation of the Wansley Facility; therefore, we have assumed that Southern Power will nominate a Contract Capacity Rating equal to the demonstrated capability in over-pressure mode with power augmentation less allowances for non-recoverable degradation, fouling, and other operational factors that make it difficult to achieve tested values on a day-to-day basis. Based on information provided by Southern Power, we have estimated the long-term Contract Capacity Rating to be 1,123 MW for the Wansley Facility. This estimate includes a levelized allowance for long-term degradation. Under the terms of the Wansley Power Purchase Agreements, fuel is purchased by Southern Power and reimbursed by Georgia Power and Savannah Electric according to the summer and winter heat rate curves in the Wansley Power Purchase Agreements. Fuel payments are based on the "Contract Heat Rate", which is based on the delivered output for each unit in each hour. The Contract Heat Rate is determined pursuant to heat rate curves included in the Wansley Power Purchase Agreements for normal operation with the actual output to fall between the minimum normal capability and the maximum normal capability. Summer (May through September) and winter (October through April) heat rate curves are included which specify the heat rate at any given output. If the output is between the maximum normal capability and the over-pressure mode capability, the unit output is to be calculated assuming a 50 MW block at a heat rate of 9,100 Btu per kWh, plus the remaining output calculated using the heat rate curves. If the output is between the over-pressure mode capability and the capability in over-pressure mode with power augmentation, the unit output is to be calculated assuming a 25 MW block at a heat rate of 13,000 Btu per kWh plus the 50 MW block of over-pressure output at 9,100 Btu per kWh plus the remaining output using the heat rate curves. Power augmentation is not available at temperatures below 59(Degree)F and is limited to 1,000 hours per year. Based on information provided by Southern Power, we have estimated the long-term, full-load heat rate, including a levelized allowance for long-term degradation, to be 6,923 Btu/kWh for the Wansley Facility. For the purposes of the Projected A-25 Operating Results, we have assumed that the heat rate of the Wansley Facility will be in accordance with the heat rate curves in the Wansley Power Purchase Agreements and no heat rate penalties will be incurred or bonuses achieved. SUMMARY Based on our review, we are of the opinion that, if operated and maintained as currently proposed by the operators of the Generating Facilities, the Generating Facilities should be capable of achieving the annual average output in full-pressure mode with power augmentation and the average annual net plant heat rates assumed in the Projected Operating Results. These estimates include allowance for corrections to reference conditions and long-term degradation of output and heat rate. These assumptions represent the average long-term performance over the term of the Notes. There may be years when the actual performance is above or below the average performance stipulated herein. However, for the purpose of the Projected Operating Results, we have utilized these average performance assumptions. AVAILABILITY A number of the Power Purchase Agreements include contractual availability requirements which impact the level of capacity payments under those contracts, as discussed below. In general, the definitions of contractual availability exclude scheduled maintenance, which reduced the actual availability of the Generating Facilities. We have performed an analysis of Southern Power's proposed operations and maintenance plan through the operating agreements with the respective operators, taking into consideration the planned outages, as well as actual industry operating experience regarding forced outage rates as reported by various major equipment vendors, plant operators, and industry monitoring sources (including NERC Generating Availability Data System) selected for applicability to the Generating Facilities. THE DAHLBERG FACILITY Under the terms of the LEM Power Purchase Agreements, Southern Power will receive bonus payments in the event that the Dahlberg Facility achieves contract availabilities in excess of certain levels. Southern Power can meet this contract availability through energy from alternate resources. Southern Power can earn an annual availability bonus for Dahlberg 1-5 ranging from $100,000 for a contract availability of 98.6 percent to $1,000,000 for a contract availability of 100 percent. Southern Power can earn an annual availability bonus for Dahlberg 6-7 of $200,000 for a contract availability of 100 percent. No bonus is available for Dahlberg 6-7 for contract availability levels below 100 percent. There are no minimum availability levels in the LEM Power Purchase Agreements. In the event that the Dahlberg Facility is unable to meet the requirements of the LEM Power Purchase Agreements, Southern Power must provide the requested energy from other resources. The Dynegy Power Purchase Agreement does not set a required availability level, but instead requires that, when unavailable, Southern Power either provide an alternative resource, pay specified replacement costs, or declare an excused non-delivery hour. Southern Power is allowed approximately 600 excused non-delivery hours per year. THE GOAT ROCK FACILITY Under the terms of the Goat Rock Power Purchase Agreement, an availability adjustment is made to the amount paid for Designated Capacity. The adjustment can result in either an increase or decrease in the capacity payments. The availability adjustment is based upon a "Capacity Adjustment Factor" adjusted by a factor of 0.15 for the months of June through September and 0.05 for all other months. The Capacity Adjustment Factor is based on a contract availability factor called the "Seasonal Availability Factor", which excludes scheduled maintenance and allows Southern Power to replace the undelivered energy from another resource. The Capacity Adjustment Factor results in a reduction in capacity payments in the event that the Goat Rock 1 and 2 contract availabilities are less than 96.5 percent. The capacity payments can increase by 1.0 to 3.5 percent of the annual capacity payments for a contract availability ranging from 96.5 to 99.5 percent. Southern Power can meet this contract availability through energy from alternate resources. A-26 THE HARRIS FACILITY Under the terms of the Harris Power Purchase Agreements, an availability adjustment is made to the amount paid for Designated Capacity. The adjustment can result in either an increase or decrease in the capacity payments. The availability adjustment is based upon a "Capacity Adjustment Factor" adjusted by a factor of 0.15 for the months of June through September and 0.05 for all other months. The Capacity Adjustment Factor is based on a contract availability factor, called the "Actual Demand Availability" in the Harris 1 Power Purchase Agreement and the "Seasonal Availability Factor" in the Harris 2 Power Purchase Agreement, which excludes scheduled maintenance and allows Southern Power to replace the undelivered energy from another resource. The Capacity Adjustment Factor results in a reduction in capacity payments in the event that the Harris 1 and 2 contract availability factors are less than 96 and 96.5 percent, respectively. The capacity payments can be increased by 1.5 to 4.0 percent of the annual capacity payments for a contract availability ranging from 97.0 to 99.0 percent for Harris 1 and by 1.0 to 3.5 percent of the annual capacity payments for a contract availability ranging from 96.5 to 99.5 percent for Harris 2. Southern Power can meet these contract availabilities through energy from alternate resources. THE STANTON FACILITY Under the terms of the Stanton Power Purchase Agreements, an availability adjustment is made to the amount paid for the Demonstrated Capacity. If the availability of the Stanton Facility is less than the guaranteed availability, capacity payments are reduced by the "Availability Damages". Availability Damages are calculated as the difference between the actual availability and 97 percent times the sum of the capacity payment for the appropriate period, adjusted by one-half for the off-peak period. The Stanton Facility will also be entitled to an availability incentive payment of 3 percent of the peak period capacity payments for a contract availability in excess of 99 percent and 1.5 percent of the off-peak capacity payments for an off-peak contract availability in excess of 99 percent. The Stanton Facility will also be penalized by 2 percent of the peak period capacity payments for a peak contract availability of 95 percent and an additional 1 percent for each percentage of contract availability less than 95 percent. The off-peak contract availability penalty is 1 percent of the off-peak capacity payments for an off-peak contract availability of 95 percent and an additional 0.5 percent for each percentage of off-peak contract availability less than 95 percent. THE WANSLEY FACILITY Under the terms of the Wansley Power Purchase Agreements, an availability adjustment is made to the amount paid for the Contract Capacity Rating. The adjustment can result in either an increase or decrease in the capacity payments. The adjustment is based on a contract availability factor called the "Seasonal Availability Factor", which excludes scheduled maintenance and allows Southern Power to replace the undelivered energy from another resource. A reduction in capacity payments results in the event that the Seasonal Availability Factor is less than 96.5 percent. The capacity payments can increase by 1.0 to 3.5 percent of the annual capacity payments for a contract availability ranging from 96.6 to 99.5 percent. Southern Power can meet this contract availability through energy from alternate resources. SUMMARY Based on our review, we are of the opinion that the Generating Facilities should be capable of achieving the required average annual contract availabilities under the Power Purchase Agreements ranging from 96.5 to 97 percent, which exclude scheduled maintenance and allow Southern Power to replace the undelivered energy from another resource, and should also be capable of achieving an average annual availability of 92 percent, which includes provision for forced and scheduled maintenance. The stipulated availability factors represent the projected average availabilities over the term of the Notes. There may be years when the actual availability factors are above or below the average availability factors stipulated herein. For the purpose of the Projected Operating Results, Southern Power has assumed that it will provide energy from alternate resources in order to achieve the contract availabilities required to obtain the maximum amount of capacity payments under the Power Purchase Agreements. A-27 CONSTRUCTION STATUS We were provided summary schedules comprised of engineering, procurement, construction, and turnover activities to support the assumed commercial operations dates of Goat Rock 2, the Harris Facility, and the Stanton Facility. In addition, we have been provided an estimated cost to complete these facilities. The estimated remaining construction cost of these facilities is expected to be funded from the Commercial Construction Revolver and Southern equity. Commercial operation of Goat Rock 2 is currently scheduled for June 1, 2003. According to the schedule provided, construction was approximately 26 percent complete as of March 31, 2002, with the first fire of the first CT and synchronization of the generator to the power grid scheduled to take place in January 2003. The total construction cost is estimated by Southern Power to be $246 million. Commercial operation of both Harris 1 and 2 is currently scheduled for May 1, 2003 and June 1, 2003, respectively; however, for the purposes of the Projected Operating Results, we have assumed both units would begin commercial operation on June 1, 2003. According to the schedule provided, as of April 1, 2002, overall engineering was approximately 81 percent complete, procurement was 90 percent complete, and construction was approximately 24 percent complete. Erection of the HRSGs was in progress and the first CT and both STs have been delivered to the site. First fire of the CTs is scheduled to take place in December 2002, with synchronization of the generator to the power grid to take place in February 2003. The total construction cost is estimated by Southern Power to be $513 million. Commercial operation of the Stanton Facility is currently scheduled for October 1, 2003. According to the schedule, overall engineering was approximately 79 percent complete as of May 9, 2002, and work continues with the placement of equipment foundations and erection of the HRSGs. The ST is scheduled to arrive on site July 1, 2002. First fire of the first CT and synchronization of the generator to the power grid are scheduled to take place in May 2003. The total construction cost is estimated by Southern Power to be $262 million, of which Southern Power's share is 65 percent. ENVIRONMENTAL ASSESSMENTS ENVIRONMENTAL SITE ASSESSMENTS THE DAHLBERG FACILITY We have reviewed the "Environmental Property Assessment" regarding the Dahlberg Project Site completed August 4, 1997, by Georgia Power and the "Phase I Environmental Site Assessment, Plant Dahlberg" dated April 20, 2001, prepared for SCS by URS Corporation ("URS"). The approximately 270-acre subject property has historically been used for agricultural and silvicultural activities. At the time of Georgia Power's 1997 assessment, the property was undeveloped woodlands and farm fields, with some use for silvicultural activities with an overhead electric transmission line traversing the property. Historical aerial photos (1944-1980) showed several structures related to residential and agricultural purposes located on the property. According to information provided by Southern Power, Dames & Moore's "Phase I Environmental Survey, Wetland Delineations, and Threatened and Endangered Species Survey" dated January 9, 1995, prepared for Georgia Power, Dames & Moore did not identify any environmental concerns at the Dahlberg Facility regarding site contamination during their 1995 investigation. During their 1997 site visit, Georgia Power did not identify any signs of spills, stained soils, waste disposal, chemical storage, tanks, drums, or other indicators of potential site-contamination issues. At the time of URS's April 2001 site visit, construction of eight CT units (and associated equipment and amenities) at the Dahlberg Facility had been completed, and additional construction of Units 9 and 10 was near completion. The power plant area occupies approximately 75 acres of the Dahlberg Facility Project Site. Georgia Power and URS determined that the property was not documented on any state or federal environmental database that lists known or suspected contaminated sites or hazardous waste activity. Neither Georgia Power's nor URS's assessments identified any potential impacts to the property from adjoining properties. As a result of their 1997 investigation, Georgia Power concluded, "there were no significant environmental concerns identified which would prohibit the purchase of the property." During their A-28 April 2001 site visit, URS examined several areas of fuel storage and use of other hazardous substances, but reported no soil stains or other observable concerns associated with these areas. URS reported an accidental release of 16,900 gallons of No. 2 fuel oil within the bermed area for the 3.5 million-gallon fuel tank (as well as three other minor historical fuel/hydraulic oil releases associated with plant construction and operations). URS provided documentation that all of the spill areas had been cleaned-up and contaminated soils had been disposed of at a permitted landfill. URS concluded that their investigation revealed no on-site recognizable environmental concerns. THE GOAT ROCK FACILITY We have reviewed the "Environmental Property Assessment" regarding the Goat Rock Project Site completed August 31, 1998, by Alabama Power and the "Phase I Environmental Site Assessment (Revised)" dated May 3, 2001, prepared for Alabama Power by TTL, Inc. ("TTL"). The approximately 709-acre subject property has historically been used for hunting and silvicultural activities. At the time of Alabama Power's 1998 assessment, the property was undeveloped timberland and fields, with prior land use for hunting and silvicultural activities. During their 1998 site visit, Alabama Power encountered no substantial structures on the property, and did not identify any signs of spills, stained soils, waste disposal, chemical storage, tanks, drums, or other indicators of potential site-contamination issues. At the time of TTL's April 2001 site visit, the subject property was undeveloped, with the exception of power plant construction activity on the northeast corner of the site. TTL observed an 8,000-gallon above-ground storage tank for diesel fuel with no evidence of fuel releases, observed minor areas of debris that they described as benign, and encountered a small on-site cemetery. TTL reported no issues of concern associated with the power plant construction area. Alabama Power and TTL determined that the property was not documented on any state or federal environmental database that lists known or suspected contaminated sites or hazardous waste activity. Neither Alabama Power's nor TTL's assessments identified any potential impacts to the property from adjoining properties. As a result of their 1998 investigation, Alabama Power concluded, "there were no significant environmental concerns identified, which would prohibit the purchase of the property." TTL's conclusions did not indicate any issues of significant environmental concern for the subject property. THE HARRIS FACILITY We have reviewed the following: (1) the "Environmental Property Assessment" regarding the Harris Project Site completed February 18, 2000, by Alabama Power; (2) the "Phase I Environmental Site Assessment (Revised), Autaugaville Site" dated May 3, 2001, prepared for Alabama Power by TTL; and (3) the "Phase I Environmental Site Assessment, Approximate 291.37-acre Parcel" dated May 18, 2001, prepared for Alabama Power by TTL. These reports cover the 467.66-acre and 291.37-acre contiguous parcels for the Harris Facility, totaling approximately 759 acres. According to TTL, the subject properties have been historically used for agricultural purposes and timber production. At the time of Alabama Power's February 2000 assessment, the properties were undeveloped farmland and wooded tracts. At the time of TTL's April/May 2001 site visits, initial construction activities for the Harris Facility had begun on the 468-acre parcel and construction of a substation was underway on the 291-acre parcel. TTL observed temporary trailers at the power plant construction site and above-ground storage tanks for diesel fuel on both construction sites. TTL reported no spills or stained soils of regulatory consequence associated with the fuel storage. During their site reconnaissance of the two properties, TTL observed abandoned rusting vehicles, several debris sites, abandoned houses/barn/sheds, and several former domestic wells. Alabama Power and TTL determined that the subject properties were not documented on any state or federal environmental database that lists known or suspected contaminated sites or hazardous waste activity. Neither Alabama Power's nor TTL's assessments identified any potential impacts to the Harris Project Site from adjoining properties. Alabama Power concluded that their assessment "revealed no environmental conditions which would preclude the purchase of this property." With the exception of solid waste disposal on various portions of the properties, TTL reported no other conditions of potentially significant concern during their site reconnaissance. TTL recommended: (1) properly abandoning the domestic wells (on the 291-acre parcel) by filling them with cement and clay; (2) that debris/trash piles on the 468-acre property be removed and disposed of off-site, followed by sampling and analysis of soil beneath the debris piles; (3) removal and off-site disposal of Trash Area No. 1 from the 291-acre property, followed by soils sampling if staining was observed during the removal process; and (4) citing the presence of potentially hazardous materials such as oil containers, oil filters, and car batteries, TTL recommended removal and off-site disposal of Trash A-29 Area No. 2 from the 291-acre property, followed by soil sampling to evaluate baseline environmental conditions in this area. In accordance with their normal practices, Alabama Power has reported their intent to abandon the aforementioned domestic wells by filling the wells with appropriate materials. Further, Alabama Power indicates that the various debris piles and trash areas will be removed and evaluated for proper disposal, depending on the content of the piles. After debris removal, Alabama Power plans to assess the areas and conduct soil sampling and additional soil removal, as necessary, if such areas have been severely impacted. THE STANTON FACILITY We have reviewed the Phase I Environmental Site Assessment, Stanton Energy Plant dated April 2001, prepared for OUC by Environmental Consulting & Technology, Inc. ("ECT") and the Limited Phase II Environmental Site Assessment, Stanton Energy Center dated June 29, 2001, prepared for OUC by ECT. The environmental site assessments were conducted on a 7-acre portion of the 60 acres leased to Southern Power Florida, OUC, and FMPA. According to ECT, the 7-acre property has been used historically as a construction laydown yard during construction of the adjacent SEC power plant and as a fueling facility for fleet vehicles. At the time of their March-May 2001 site visits, the property contained two small structures, a concrete foundation for a former structure, an out-of-service electrical substation, and an active fueling facility. Areas adjacent to the property included citrus groves to the north, the SEC to the south, and OUC's fleet vehicle maintenance facility also located to the south. ECT observed disposed sand blasting material on the south side of the property; a storage building with discarded industrial batteries (with evidence of the concrete floor stained by battery acid); a storage building at the fueling facility containing five above-ground tanks for gasoline and diesel (with no evidence of releases) and associated above-ground piping and fuel dispenser; and several on-site piles of solid waste/construction debris (containing concrete, scrap wood, steel glass piping, metal grating, and miscellaneous railroad debris). With the exception of stained gravel beneath a transformer (labeled non-PCB) at the out-of-service substation, ECT observed no evidence of stained soils at the property. ECT concluded that their assessment revealed no evidence of recognized environmental conditions except the aforementioned issues associated with possible releases to soil or groundwater at the out-of-service substation, the fueling facility, and discarded sand blasting material located on the property; and the vehicle maintenance facility located south of the property. ECT recommended removal of the solid waste/debris areas, sand blasting materials, and discarded batteries (at the substation); and limited soil and groundwater testing at the site. During May 2001, ECT collected a sample of the sand blasting materials for laboratory analysis of metals by toxicity characteristic leaching procedure ("TCLP") and conducted limited sampling of soil and groundwater at the property including selected analyses of VOCs, polynuclear aromatic hydrocarbons, ("PAHs"), total petroleum hydrocarbons, metals, and pH. Soil and groundwater samples from four temporary monitoring wells were installed near the battery storage building, in the sand blasting materials area, at the fueling facility, and at the south property boundary bordering the OUC vehicle maintenance facility. Metals were not detected in the TCLP sample of sand blasting materials. Fuel related compounds were detected in soil associated with the fueling facility and the south boundary sampling location (north of the off-site vehicle maintenance facility), but none of the concentrations in any of the soil samples exceeded the applicable cleanup standards promulgated by the Florida Department of Environmental Protection ("FDEP"). Fuel related compounds and metals were detected in groundwater samples associated with the sand blasting area, the fueling facility, or the boundary sampling location, but none of the concentrations in any of the samples exceeded the applicable cleanup standards with the exception of one groundwater sample at the fueling facility. Benzene at 2.2 parts per billion ("ppb") and total xylenes at 50 ppb exceeded the FDEP regulatory standard for groundwater cleanup of 1 ppb and 20 ppb, respectively at the fueling facility. Due to the elevated levels of benzene and xylenes at the fueling facility, ECT recommended additional investigations consisting of installation of piezometers (to determine groundwater flow direction) and installation of permanent groundwater monitoring wells for analysis of fuel related organic compounds. We have not reviewed any additional reports regarding this issue and we have not received any documentation from Southern Power addressing disposal of potentially contaminated groundwater from dewatering activities. However, pursuant to the Stanton Ownership Agreement, OUC is responsible for any pre-construction environmental issues. The environmental site assessments were conducted on a 7-acre portion of the 60 acres leased to Southern Power Florida, OUC, and FMPA. We are of the opinion that the environmental site assessment investigations performed by ECT for the 7-acre power plant construction site were conducted in a manner consistent A-30 with industry standards, using comparable industry protocols for similar studies with which we are familiar. Although we have not reviewed any environmental site assessments for the remaining 53 acres of the 60-acre leased area, under the Stanton Ownership Agreement, OUC is responsible for any pre-construction environmental issues that would need to be addressed on the entire 60-acre leased area. We have not been provided with any information regarding the status of the site's environmental condition since issuance of ECT's most recent report in June 2001. If groundwater remediation is ever required at the Stanton Project Site in the future to address the exceedances of groundwater contaminants identified by ECT's investigations; such remediation activities would not likely significantly impact the ability of the Stanton Facility to conduct normal operations. THE WANSLEY FACILITY We have reviewed the "Phase I Environmental Site Assessment" dated April 20, 2001, prepared for SCS by URS and the "Plant Wansley Petroleum Release and Remediation Summary" dated May 7, 2001, prepared for SCS by Williams Environmental Services ("Williams"). According to URS, the Wansley Project Site and construction laydown area were previously used by Georgia Power as a support and maintenance facility for Georgia Power operations. Prior to 1970, the subject property was wooded and agricultural, and was reportedly occupied by homesteads, a church, and several cemeteries. Development at the subject property after 1970 included a railcar maintenance shop, a concrete plant, and two warehouses. At the time of URS's April 2001 site visit, the Wansley Facility was under construction, with demolition of historical structures either completed, underway, or scheduled. Structural debris was in the process of being removed subsequent to demolition of one of the warehouses. The coal-fired Units 1 and 2 of Plant Wansley are immediately adjacent to the Wansley Project Site. URS did not identify the existing coal-fired Plant Wansley or any other adjacent areas as having any potential to impact the Wansley Project Site. URS observed several above-ground fuel storage tanks and 55-gallon drums on the subject property, as well as storage areas for machinery, parts, and miscellaneous equipment and materials. URS also observed staging areas for scrap wood and waste construction materials, but did not observe any generation of hazardous waste. URS noted that several temporary fuel storage tanks and drums were without secondary containment. Southern Power has provided a lined secondary containment storage area for the temporary fuel storage tanks that are being used during construction. URS identified two areas on the property with soil staining, particularly in the vicinity of fuel tank and drum storage areas. URS recommended excavation and disposal of the stained soils, followed by confirmatory soil sampling. URS also recommended sediment sampling in a ditch, which had potential to receive stormwater runoff from soil stained areas. In April/May 2001, Williams was contracted to complete the soil excavations recommended by URS. The two areas of soil staining (including a one-foot perimeter buffer) identified by URS were excavated and disposed of off-site. While we note that the soil sampling recommended by URS for the ditch was not conducted, confirmatory soil sampling from the two excavated areas by Williams indicated that removal of the contaminated soils was completed. SUMMARY Based on our review, we are of the opinion that the environmental site assessments performed by TTL, URS, ECT, and Williams related to the sites of the Generating Facilities were conducted in a manner consistent with industry standards, using comparable industry protocols for similar studies with which we are familiar. STATUS OF PERMITS AND APPROVALS The Generating Facilities must be operated in accordance with applicable environmental laws, regulations, policies, codes and standards. Table 8 identifies the key permits and approvals required for the operation of the Generating Facilities. Based on our review, we are of the opinion that Southern Power has identified the major permits and approvals necessary for the construction and operation of the Generating Facilities. While all of the required permits and approvals have not yet been obtained, we did not identify any technical or engineering circumstance that would prevent the issuance of the remaining permits and approvals. A-31 TABLE 8 STATUS OF KEY PERMITS AND APPROVALS REQUIRED FOR OPERATION
================================================================================================================================== DAHLBERG GOAT ROCK HARRIS STANTON WANSLEY PERMIT/APPROVAL FACILITY FACILITY FACILITY FACILITY FACILITY ================================================================================================================================== 1. Air Construction Issued 8/9/99 by Issued 4/10/00 Issued 1/8/01 by Issued 9/21/01 by Issued 7/28/00 Permits Georgia by Alabama ADEM. FDEP. by GEPD; Environmental Department of finalized Protection Environmental 11/6/00. Division ("GEPD"). Management ("ADEM"), revised 4/6/01. - ---------------------------------------------------------------------------------------------------------------------------------- 2. Title IV Acid Issued 8/31/99 by Issued 5/7/01 by Application Application Issued 7/28/00 Rain Permits GEPD. ADEM. submitted deemed complete by GEPD; 12/14/00 to 4/24/02. finalized ADEM; permit 11/6/00. pending. - ---------------------------------------------------------------------------------------------------------------------------------- 3. Title V Application Application to Application to Application Issued 7/28/00 Operating Permits submitted 3/5/01 be submitted to be submitted to submitted. by GEPD; to GEPD; permit ADEM within 12 ADEM within 12 finalized pending. months of the months of the 11/6/00; amended start of start of 2/4/02 to remove operations. operations. future units. - ---------------------------------------------------------------------------------------------------------------------------------- 4. National N/A Final NPDES Issued 12/20/01; Not required. Issued 7/31/00 Pollutant Permit issued effective 1/1/02. by GEPD. Discharge 12/27/00 by ADEM. Elimination System ("NPDES") Permits for Wastewater Discharges - ---------------------------------------------------------------------------------------------------------------------------------- 5. Notice of Submitted 8/11/00 Issued 12/17/99 Issued 12/1/00 Submitted to FDEP Submitted Intent/General to GEPD (only by ADEM. by ADEM. 6/2/02. 8/10/00 to GEPD. Permits- covers Units 9 Construction and 10). Stormwater Discharges - ---------------------------------------------------------------------------------------------------------------------------------- 6. Notice of Not required. To be obtained Not required - To be obtained To be obtained Intent/NPDES prior to the stormwater prior to start of prior to the General start of discharges operations. start of Permits-Operational operations. covered under operations. Activities NPDES Wastewater Stormwater Discharge Permit. Discharges - ---------------------------------------------------------------------------------------------------------------------------------- 7. Clean Water Act Wetlands Issued 1/12/00 Issued 11/4/00 Issued 11/6/01 Issued 4/21/00 Section 404 Delineation for the for gas for the for gas line Permits- Corps Survey 2/24/99. construction of pipeline; issued construction of crossing river; of Engineers A Project natural gas 12/20/00 for the substation also, a Stream ("COE") Completion Report pipeline. intake and expansion, the Buffer Variance was submitted to discharge electric from GEPD was COE on 7/20/01. structures. transmission issued 10/5/00 line, and the gas for construction pipeline. of gas pipeline. - ----------------------------------------------------------------------------------------------------------------------------------
A-32 TABLE 8 STATUS OF KEY PERMITS AND APPROVALS REQUIRED FOR OPERATION ================================================================================================================================== DAHLBERG GOAT ROCK HARRIS STANTON WANSLEY PERMIT/APPROVAL FACILITY FACILITY FACILITY FACILITY FACILITY ================================================================================================================================== 8. Water Withdrawal N/A Issued 4/30/00 Certificate of Water to be Issued 10/31/00 Permits by GEPD to Beneficial Use provided by OUC by GEPD; withdraw water from the Alabama pursuant to petition filed from Goat Rock Department of agreement OUC has against Permit; Reservoir. Economic and with Orange appeals hearing Also, the Community County, Florida. began 7/16/01; Federal Energy Affairs to be OUC's plan is Administrative Regulatory obtained prior currently under Law Judge issued Commission to the start of review by an amended order issued approval operations. St. John's River 4/24/02. GEPD on 10/10/00 to Southern Power Water management is in process of withdraw submitted District. re-issuing additional water Declaration of permit in through an Beneficial Use accordance with existing on 3/29/01. amended order. penstock in Goat Rock Dam. - ---------------------------------------------------------------------------------------------------------------------------------- 9. Federal Aviation Issued 7/15/99; Issued 4/25/00. On 5/30/01, FAA Not required. Issued 12/12/00. Administration extended 7/19/00. issued a ("FAA") Notice determination of Construction that the stacks or Alteration are not a hazard Permits for to navigation. Stacks - ---------------------------------------------------------------------------------------------------------------------------------- 10. Order of N/A N/A N/A Issued 9/11/01 by N/A Certification the State of Florida Siting Board. - ---------------------------------------------------------------------------------------------------------------------------------- 11. Spill Prevention Finalized on To be prepared To be prepared Existing plan to To be modified. Control and 9/27/00. within six within six be amended to Countermeasure months after months after include new unit. ("SPCC") Plan start of start of operation. operation. ==================================================================================================================================
REGULATORY COMPLIANCE We note the following circumstances relative to compliance with permits and approvals and other regulatory requirements that could have an impact on future operations: - In 1998, the United States Environmental Protection Agency ("USEPA") promulgated the "NO(x) State Implementation Plan ("SIP") Call Rule" for the purpose of controlling NO(x), a precursor to ozone, and a pollutant of concern. As required by the USEPA rules, Alabama and Georgia are subject to the NO(x) SIP Call, which will impose NO(x) allowance obligations on certain emission sources. The USEPA has approved Alabama's SIP that includes the Goat Rock and Harris Facilities. As such, each facility will be required to obtain allowances to cover annual NO(x) emissions starting in 2004. Calculations performed by the Alabama Department of Environmental Management ("ADEM") propose 35 tons of NO(x) allocations to each Harris Facility CT train for a total of 140 tons for the four trains and 33 tons of NO(x) allocations to each Goat Rock Facility CT train for a total of 264 tons for the eight trains (note there are two CT trains per unit) for 2004 through 2006, with subsequent allocations recalculated every three years (e.g., calculated in 2004 for the years 2007-2009). Based on the March 3, 2000, decision by the U.S. Court of Appeals for the District of Columbia Circuit ("Court"), certain portions of the USEPA rules that affect the entire state of Georgia were remanded. The Court found that USEPA's modeling demonstrated that the entire state of Georgia should not be included in the SIP Call. In response to the Court, the USEPA proposed revisions to their rules to include a NO(x) budget for Georgia for the northern portion of the state. Based on the USEPA proposed amended rules the state is required to submit a SIP by no later than April 1, 2003 with a May 1, 2005 compliance date. As such, the Georgia Environmental Protection Division ("GEPD") has not yet amended Georgia's SIP. GEPD is still considering options for revising their SIP and determining future allocations. It is anticipated that the A-33 Dahlberg and Wansley Facilities will be included within the area that will be subject to the NO(x) SIP Call Rule. Since the manner in which the NO(x) allocations will be structured has not been determined by GEPD, we are unable to accurately estimate the likely number of allowances that may be allocated to the Dahlberg and Wansley Facilities. The exact number of allowances to be required in the future will depend on the utilization of the units in the future and the finalization of the SIP. For the purposes of the Projected Operating Results, we have assumed that the Generating Facilities would be allocated allowances based on the Alabama SIP and no allowances were assumed for the Dahlberg and Wansley Facilities, both located in Georgia. The future cost of NO(x) allowances will be market dependent and could be lower or higher than the current values for such allowances. The allowance costs assumed in the Projected Operating Results are presented later in this Report. - The Generation Facilities are subject to Title IV of the Clean Air Act (Acid Rain Provisions) whereby each unit must possess sulfur dioxide ("SO(2)") allowances to cover its emissions beginning in 2000. The future cost of SO(2) allowances will be market dependent and could be lower or higher than the current values for such allowances. The exact number of allowances to be required in the future will depend on the utilization of the units. The allowance costs assumed in the Projected Operating Results are presented later in this Report. Since the facilities will operate primarily on natural gas, the actual cost for purchasing allowances should be relatively small. In addition, since the facilities are operated on natural gas, they are not subject to the NO(x) requirements under the Acid Rain Program. - For the purpose of estimating NO(x) and SO(2) allowance costs in the Projected Operating Results, actual emissions testing results have been assumed for the Dahlberg Facility, and air permit limits have been assumed for the other Generating Facilities with no significant operating history. Based on firing natural gas, a NO(x) emission level of 0.24 lb/MMBtu was used for the Dahlberg Facility and 0.013 lb/MMBtu was assumed for the other Generating Facilities. An SO(2) emission level of 0.001 lb/MMBtu was assumed for all of the Generating Facilities while firing natural gas. - Southern Power has reported that there have been no Notices of Violation issued by regulatory agencies against any of the Facilities. - There are a number of potential future regulations that, if promulgated, could increase capital expenditures and O&M costs at the Generating Facilities. Such potential regulations include mercury control, particulate matter of 2.5 microns or less ("PM(2.5)"), regional haze, regional visibility, water intake structure regulations, and potential ratcheting of SO(2) allowances beyond 2009. The schedule and specific regulations to be promulgated are not presently known; therefore, the impact of such potential regulations has not been incorporated into the Projected Operating Results. Since the Generating Facilities are primarily fired on natural gas, the impact of these potential future regulations is not expected to be significant. PROJECTED OPERATING RESULTS We have reviewed the historical operating information, estimates and projections of electrical generating capacity, fuel consumption, and capital and operating costs of the Generating Facilities made available to us by Southern Power. On the basis of such data, we have prepared the Projected Operating Results. Southern Power will sell electricity generated from the Generating Facilities to various entities under the terms of the Power Purchase Agreements, which vary in term. For the purposes of the Projected Operating Results, we have assumed that all of the Power Purchase Agreements will expire at the end of their respective initial terms and will not be renewed. After expiration of the Power Purchase Agreements, Southern Power intends on entering into long-term power purchase agreements at prices reflective of then-current market rates in the Southeastern Electric Reliability Council ("SERC") and Florida Reliability Coordinating Council ("FRCC") markets. For the purpose of the Projected Operating Results, we have assumed that the prices under these long-term contracts will be equivalent to the projected market prices for those markets as projected by PA Consulting. PA Consulting was also responsible for providing monthly dispatch hours, starts per month for each unit, monthly heat rates per unit and projected natural gas prices. Expenses for the plants consist primarily of the delivered costs of fuel, including transportation, as estimated by PA Consulting, and operations and maintenance expenses, as estimated by Southern Power. During the terms of the respective Power Purchase Agreements, the cost of fuel is reimbursed by, or purchased directly by, the power purchasers. Emissions A-34 allowances are also the responsibility of the power purchasers. The interest on the Notes and future debt issuances by Southern Power, as described herein, has been estimated by Lehman Brothers and Salomon Smith Barney (the "Representatives of the Initial Purchasers"). The Notes mature on July 15, 2012. Southern Power has assumed that the Notes will be refinanced upon maturity; therefore, the Projected Operating Results are presented for each calendar year beginning June 1, 2002 through December 31, 2022, a period approximately ten years beyond the term of the Notes. Projected revenues and expenses have been set forth in the Projected Operating Results presented in Exhibit A-1. The "Base Case" Projected Operating Results have been prepared using assumptions and considerations set forth in this Report and the footnotes to Exhibit A-1. ANNUAL OPERATING REVENUES REVENUE FROM POWER PURCHASE AGREEMENTS All of the Generating Facilities have Power Purchase Agreements that have various terms and conditions. Several facilities have more than one Power Purchase Agreement, as they apply to specific units. Most of the Power Purchase Agreements provide payment for capacity, start-up charges and variable O&M charges. The power purchasers and terms for each individual Power Purchase Agreement are presented in Table 9. TABLE 9 POWER PURCHASE AGREEMENTS
TOTAL CONTRACT POWER CAPACITY CAPACITY POTENTIAL UNIT(S) PURCHASER(S) (MW)(1) (MW)(2) START DATE END DATE EXTENSION ------- ------------ -------- -------- ---------- -------- --------- Dahlberg 1-7 LEM 561(3) 578(3) June 1, 2000 December 31, 2004 December 31, 2009 Dahlberg 8 Dynegy 80(3) 75(3) June 1, 2000 May 31, 2005 N/A Dahlberg 9-10 Dynegy 160(3) 150(3) June 1, 2001 May 31, 2005 N/A Goat Rock 1 Georgia Power 564 564(4) June 1, 2002 May 31, 2010 N/A Goat Rock 2 Georgia Power 595 595(4) June 1, 2003 May 31, 2011 N/A Harris 1 Alabama Power 595 595 June 1, 2003 May 31, 2010 N/A Harris 2 Georgia Power 595 595 June 1, 2004 May 31, 2019 N/A Stanton OUC, KUA, FMPA 394(5) 404 October 1, 2003 October 31, 2013 October 31, 2033 Wansley Georgia Power 925 925 June 1, 2002 December 31, 2009 N/A Wansley Savannah Electric 198 198 June 1, 2002 December 31, 2009 N/A
-------------------- (1) Represents annual average output with duct firing and steam injection with an allowance for long-term degradation. (2) Represent annual capacity nomination assumed to be set at annual average output including long-term degradation, except for the Stanton Facility for which the contract capacity is based on an average ambient temperature of 70(Degree)F. (3) The contract capacity for the Dahlberg Facility can be met by any of the units. (4) Represents maximum contract output. Initial years of contract include lower contract output. (5) Represents Southern Power's 65 percent ownership interest. Lower than contract capacity since the contract capacity is based on an average ambient temperature of 70(Degree)F. THE DAHLBERG FACILITY Dahlberg 1 through 5 are currently in operation and are realizing revenue under the terms of the 1998 LEM Power Purchase Agreement. LEM has the right to extend the term of this 1998 LEM Power Purchase Agreement to December 31, 2009; however, we have assumed for the purposes of the Projected Operating Results that this 1998 LEM Power Purchase Agreement will expire December 31, 2004. Southern Power will receive revenues from Dahlberg 1 through 5 for capacity, start-up and variable operations from LEM. The monthly capacity revenues range from $1,878,033 to $2,045,013 during the applicable portion of the initial term of the 1998 LEM Power Purchase Agreement. Start-up charges range over the term of the 1998 LEM Power Purchase Agreement from $3,292/start to $3,585/start for starts in excess of 750 over the initial term of the 1998 LEM Power Purchase Agreement. The variable O&M payment ranges from $3.36 per MWh to $3.66 per MWh of energy delivered to LEM during the initial term of A-35 the 1998 LEM Power Purchase Agreement. These prices are provided in the 1998 LEM Power Purchase Agreement. Based on our discussion with Southern Power and the review of the plant design and technology, we have assumed that Southern Power will achieve its contract capacity of 412.5 MW by utilizing peak firing and power from the other Dahlberg Facility units. Additional capacity payments are available for contract availability above 98.6 percent. Southern Power has indicated that it would provide energy from alternate resources in order to receive the maximum capacity payment under the 1998 LEM Power Purchase Agreement. We have assumed the contract availability is equal to 100 percent based upon the purchase of replacement energy from the market, resulting in additional capacity payments of $1,000,000 per year. Dahlberg 6 and 7 are currently in operation and are realizing revenue under the terms of the 1999 LEM Power Purchase Agreement. As with the 1998 LEM Power Purchase Agreement, LEM has the right to extend this contract; however, we have assumed for the purposes of the Projected Operating Results that the 1999 LEM Power Purchase Agreement will expire on December 31, 2004. Revenues from operations of these units include capacity payments, start-up charges and variable operations payments. Capacity payments range from monthly charges of $709,500 to $732,600 during the initial term of the 1999 LEM Power Purchase Agreement. Start-up payments range from $51.50 to $56.28 per MW per start. Variable O&M payments range from $3.36 per MWh to $3.66 per MWh of energy delivered to LEM during the initial term of the 1999 LEM Power Purchase Agreement. These prices are provided in the 1999 LEM Power Purchase Agreement. Based on our discussion with Southern Power and the review of the plant design and technology, we have assumed that Southern Power will achieve its contract capacity of 165 MW by utilizing peak firing and power from the other Dahlberg Facility units. Additional capacity payments are available for contract availability of 100 percent. Southern Power has indicated that it would provide energy from alternate resources in order to receive the maximum capacity payment under the 1999 LEM Power Purchase Agreement. We have assumed the contract availability is equal to 100 percent based upon the purchase of replacement energy from the market, resulting in additional capacity payments of $200,000 per year. Under the terms of the Dynegy Power Purchase Agreement, power from Dahlberg 8-10 will be sold in three 75 MW blocks. The Dynegy Power Purchase Agreement expires on May 31, 2005. The Monthly Capacity Payment is adjusted by a monthly adjustment factor that is weighted such that approximately 63 percent of the payments occur in the months of June through September. Monthly capacity payments, before adjustment, range from $1,136,250 to $888,750. Start-up charges range from $3,851 to $4,172 per block per start. Variable O&M payments range from $1.34 per MWh to $1.45 per MWh of energy delivered to Dynegy. These prices are provided in the Dynegy Power Purchase Agreement. THE GOAT ROCK FACILITY The Goat Rock Power Purchase Agreement includes provisions for selling capacity and associated energy from Goat Rock 1 and Goat Rock 2 to Georgia Power. The term associated with Goat Rock 1 is June 1, 2002 to May 31, 2010. The term associated with Goat Rock 2 is June 1, 2003 to May 31, 2011. For Goat Rock 1 and Goat Rock 2, the annual average projected capacities are 564 and 595 MW, respectively. Average contract capacity values range from 370 MW (for the first year) to 564 MW for Goat Rock 1 and from 400 MW to 595 MW for Goat Rock 2. The excess energy generation has been assumed to be sold to the market as forward contracts and spot market sales, as discussed later herein. The annual contract capacity price is $74.40 per kW-year for Goat Rock 1 and $76.20 per kW-year for Goat Rock 2 for the term of the Goat Rock Power Purchase Agreement. These capacity prices are weighted such that 60 percent of the payments occur in the summer months. Additional capacity payments are available for contract availability above 96.5 percent. Southern Power has indicated that it would provide energy from alternate resources in order to receive the maximum capacity payment under the Goat Rock Power Purchase Agreement. We have assumed the contract availability is equal to 99.5 percent based upon the purchase of replacement energy from the market, resulting in an increase in capacity payments of 3.5 percent. Variable O&M charges are $2.80 per MWh for Goat Rock 1 and $2.60 per MWh for Goat Rock 2 in 2001, indexed to 1999 Gross Domestic Product - Implicit Price Deflator ("GDP-IPD"). We have assumed GDP-IPD will increase at 2.7 percent from 2002. Start-up charges are per unit per start and range from $6,000 for starts 1 through 50, to $20,000 for starts 51 through 100 and $50,000 for starts greater than 100. Under the terms of the Goat Rock Power Purchase Agreement, the start-up charges are indexed to both the January 1, 1999 U.S. City Average Consumer Price Index for All Urban A-36 Consumers ("CPI") and $2.25 per MMBtu as a base to the "Daily Price Survey" midpoint as published in Gas Daily. For the purposes of the Projected Operating Results, we have assumed that CPI will escalate at 2.7 percent after January 1, 2002 and the midpoint in the "Daily Price Survey" will be as projected by PA Consulting in their delivered fuel forecast. THE HARRIS FACILITY Harris 1 and 2 are to sell power under separate Power Purchase Agreements to Alabama Power and Georgia Power with terms beginning on June 1, 2003 and June 1, 2004 and ending on May 31, 2010 and May 31, 2019, respectively. Prior to commencement of the Harris 2 Power Purchase Agreement, Southern Power has assumed that electricity from Harris 2 will be sold on a merchant basis at quantities and prices estimated by PA Consulting. Annual average contract capacity is equal to 595 MW per unit. Monthly revenues are generated from a capacity payment of $79.80 per kW-year and $85.56 per kW-year for each of Harris 1 and 2, respectively, which is adjusted by a monthly capacity payment factor that is weighted such that 60 percent of the payment occurs during the summer months. Additional capacity payments are available for contract availability above 97.0 percent for Harris 1 and 96.5 percent for Harris 2. Southern Power has indicated that it would provide energy from alternate resources in order to receive the maximum capacity payment under the Harris Power Purchase Agreements. We have assumed the contract availability is equal to 99.0 percent for Harris 1 and 99.5 percent for Harris 2 based upon the purchase of replacement energy from the market, resulting in additional capacity payments of 4.0 and 3.5 percent, respectively. Revenues are also generated from a variable O&M charge of $2.65 per MWh for Harris 1 and $2.60 per MWh for Harris 2 indexed to 1999 GDP-IPD. We have assumed that GDP-IPD and all inflation-related indices will increase at 2.7 percent from 2002, based on a March 10, 2002 projection prepared by Blue Chip Economic Indicators. The start-up charge is equal to $6,000 per start for the first 50 starts, $20,000 per start for the next 50 starts, and $50,000 for all starts in excess of 100 starts. Under the terms of the Harris 1 and 2 Power Purchase Agreements, the start-up charges are indexed to both the January 1, 1999 CPI and $2.25 per MMBtu as a base to the "Daily Price Survey" midpoint as published in Gas Daily. For the purposes of the Projected Operating Results, we have assumed that CPI will escalate at 2.7 percent after January 1, 2002 and the midpoint in the "Daily Price Survey" will be as projected by PA Consulting in their delivered fuel forecast. THE STANTON FACILITY Under the terms of the Stanton Power Purchase Agreements, 52 percent of the Stanton Facility's generation is allocated to OUC, 6.5 percent of the generation is allocated to KUA, and the remaining 6.5 percent is allocated to FMPA. Sale of power under the Stanton Power Purchase Agreements commences upon commercial operation of the Stanton Facility. For the purposes of the Projected Operating Results, we have assumed that the Stanton Power Purchase Agreements will have an effective date of October 1, 2003 and will expire on October 31, 2013. Each of the agreements has similar terms and conditions. Southern Company Florida will receive capacity, energy and start payments. OUC is the fuel agent and is responsible for the delivery of fuel. The power purchasers will be obligated for the payment of fuel used to produce energy. OUC, KUA, and FMPA shall have the irrevocable right to jointly reduce the total of their combined capacity nominations beginning with the sixth contract year and ending with the tenth contract year. OUC, KUA, and FMPA can reduce their nominations in 25 MW blocks; however, no reduction can total more than 50 MW in any given year and 200 MW in the aggregate. The decrease in capacity nominations will be effective through the initial term and any subsequent extensions. For the purposes of the Projected Operating Results, we have assumed that OUC, KUA, and FMPA will not elect to reduce their capacity nominations. The capacity payment during each month of the operating period shall be an amount equal to the product of the purchasers' annual capacity nomination multiplied by the annual capacity charge of $77.85 per kW-year. The Stanton Facility will also be entitled to an availability incentive payment of 3 percent of the peak period capacity payments for a contract availability in excess of 99 percent and 1.5 percent of the off-peak capacity payments for an off-peak contract availability in excess of 99 percent. The Stanton Facility will also be penalized by 2 percent of the peak period capacity payments for a peak contract availability of 95 percent and an additional 1 percent for each A-37 percentage of contract availability less than 95 percent. The off-peak contract availability penalty is 1 percent of the off-peak capacity payments for an off-peak contract availability of 95 percent and an additional 0.5 percent for each percentage of off-peak contract availability less than 95 percent. For the purpose of the Projected Operating Results, we assumed an annual, peak, and off-peak contract availability of 99.01 percent, based upon the purchase of replacement energy from the market, resulting in additional capacity payments of 2.375 percent. The capacity payment will increase or decrease by $0.42 per kW-year for every $350,000 increase or decrease in "BOP Capital Cost Range" or "Fixed Amount" as referenced in the Stanton Ownership Agreement. For the purposes of the Projected Operating Results, we have assumed that there will be no increase or decrease in the BOP Capital Cost Range and Fixed Amount. The variable energy charge will consist of three components: (1) a variable O&M charge of $0.73 per MWh; (2) an hourly variable O&M charge while firing natural gas of between $986 and $7,149 per hour, based on the annual capacity factor; and (3) an hourly variable O&M charge while firing No. 2 oil of three times the corresponding rate while firing natural gas. The annual capacity factor is defined as the annual scheduled hours divided by the period hours minus the outage hours. Outage hours include both the 58 hours of allowable scheduled maintenance and the total hours of forced outages. Each component is indexed to the CPI for January 1, 2003, and contractually escalated each January 1 at the rate of change in the CPI. For the purposes of the Projected Operating Results, we have assumed that the rate of change of CPI will be 2.7 percent per year. The Stanton Facility will receive the applicable variable O&M components and cost of fuel for any energy delivered from an alternate resource. The Stanton Facility will also receive a start charge for each unit start over 65 starts. For each start between 65 and 99, the start charge is equal to $9,783 per start. For each start greater than 99, the start charge is equal to $16,307 per start. The start charges are indexed to the CPI for January 1, 2003 and contractually escalated each January 1 at the rate of change in CPI. For the purposes of the Projected Operating Results, we have assumed that the rate of change of CPI will be 2.7 percent per year. THE WANSLEY FACILITY The Wansley Power Purchase Agreements include provisions for selling capacity and associated energy generated by Wansley to Georgia Power and Savannah Electric. Under the terms of the Wansley Power Purchase Agreements, energy sales start on June 1, 2002 and expire December 31, 2009. Contract capacity and associated energy from Wansley are sold as blocks, each rated at 561.5 MW. The contract capacity equals the projected annual average capacity. Capacity pricing varies by month with 60 percent of the annual capacity payment occurring during June-September and 40 percent occurring in the months remaining. Capacity pricing includes a capacity charge, a fixed O&M charge and a transmission interconnection charge. Additional capacity payments are available for contract availability above 96.6 percent. Southern Power has indicated that it would provide energy from alternate resources in order to receive the maximum capacity payment under the Wansley Power Purchase Agreements. We have assumed the contract availability is equal to 99.5 percent based upon the purchase of replacement energy from the market, resulting in an increase in capacity payments of 3.5 percent. The annual capacity charge, without the bonus, averages approximately $72 per kW-year. Start-up charges are $20,000 per start per unit in excess of 50 starts per year indexed to 1999 GDP-IPD. We have assumed that GDP-IPD will increase at 2.7 percent from 2002. Variable O&M payments are $2.39 per MWh and are also indexed to 1999 GDP-IPD. OTHER REVENUES FROM ELECTRICITY SALES Southern Power has assumed that a portion of the capacity and associated energy from Goat Rock 1, Goat Rock 2, and Harris 2 will be sold into the market before initiation of their respective Power Purchase Agreements. Market prices have been estimated by PA Consulting in 2001 dollars and have been adjusted for inflation. For the purposes of the Projected Operating Results, the general inflation rate has been assumed to be 2.7 percent per year. PA Consulting also provided monthly dispatch hours for each of these facilities during this period. In addition to the market sales by the Goat Rock Facility before initiation of the Goat Rock Power Purchase Agreement, a portion of the output from Goat Rock 1 and Goat Rock 2 is to be sold to third parties pursuant to contracts entered into by Southern Power. During the period from 2002 to 2003, net revenues associated with these A-38 third-party contract sales are approximately $14,900,000 based on the executed contracts as reported by Southern Power. After the expiration of the Power Purchase Agreements, Southern Power intends on entering into long-term power purchase agreements representing at least 80 percent of its cash flow at prices reflective of then-current market rates. For the purposes of the Projected Operating Results, we have utilized a projection of market prices prepared by PA Consulting as an estimate of those contract rates. Market prices include separate charges for capacity and electricity sold into the SERC and FRCC markets, as estimated by PA Consulting. PA Consulting also provided monthly dispatch hours for each of the Generating Facilities. ANNUAL OPERATING EXPENSES FUEL COSTS Substantially all of the commodity component of the fuel costs associated with the terms of the respective Power Purchase Agreements are the obligation of the buyer of the energy and have not been included in the Projected Operating Results as expenses to Southern Power. Commodity fuel costs are incurred during periods of market sales, either before the Power Purchase Agreements begin, after they expire, or at times when annual average capacity is greater or less than contract capacity. Commodity fuel cost projections have been estimated by PA Consulting based upon the appropriate annual average heat rate for each unit, or group of units, for the respective Generating Facility. For the purposes of the Projected Operating Results, we have assumed fuel prices equal to the projections prepared by PA Consulting in 2001 dollars and adjusted for inflation at the assumed rate of 2.7 percent per year. Non-commodity fuel charges, related to transportation and storage, are the obligation of the buyer of the energy during the term of the Power Purchase Agreements. These costs are incurred by Southern Power after the expiration of the Power Purchase Agreements. These charges have been estimated by Southern Power, as derived from their fuel plans for the Goat Rock, Harris, and Wansley Facilities. OPERATING AND MAINTENANCE COSTS For the purposes of developing the Projected Operating Results, operating and maintenance expenses for the Generating Facilities have been estimated by Southern Power. These estimates include annual costs for payroll, materials and supplies, outside services, including contractors, and variable operating and maintenance expenses. All operation and maintenance expenses have been provided in 2001 dollars and have been assumed to escalate at the general rate of inflation. PA Consulting has projected that the Generating Facilities will operate in the full-pressure mode with power augmentation over the course of the year, resulting in additional water costs. Major maintenance expenses were estimated by Southern Power and include major maintenance, "recurring" capital expenditures, and LTSA charges. These expenses vary annually and have been assumed to escalate with the rate of inflation. Under the terms of the LTSAs, the cost of maintenance of the Generating Facilities increases if the Generating Facilities are operated in certain types of steam injection modes. The full-pressure mode with power augmentation assumed by Southern Power is not classified by GEI as a type of steam injection that would result in increased maintenance compared to base-load operation. As such, we have assumed no impact on the LTSA charges due the assumed mode of operation projected by PA Consulting. We have reviewed the combined projection of operating and maintenance expenses and major maintenance costs in comparison to the costs of similar plants with which we are familiar. Based on our review, we are of the opinion that Southern Power's estimates of the costs of operating and maintaining the Generating Facilities, including provision for major maintenance, are within the range of the costs of similar plants with which we are familiar. A-39 PURCHASED POWER In order to maximize the capacity payments under the Power Purchase Agreements, Southern Power has indicated that it will provide replacement energy from alternate resources. We have assumed the replacement energy will be purchased from the market. Purchased power has been assumed to be available at market prices estimated by PA Consulting. EMISSIONS ALLOWANCES Southern Power has acquired or has been allocated the SO(2) and NO(x) allowances associated with the Generating Facilities. We have included the cost of allowances as an additional operating expense for the Generating Facilities. In the event that excess allowances are available for sale, we have assumed that Southern Power will sell the allowances at market prices. The deficit or excess of allowances has been estimated based on the assumed emission rates as estimated by Southern Power, the capacity factors projected by PA Consulting, and the allocated SO(2) and NO(x) allowances. In the event of a shortfall during the term of any of the various Power Purchase Agreements, the emissions allowance expense would be the contractual obligation of the buyer of the electricity, but excess allowances could be sold by Southern Power. The market NO(x) and SO(2) emissions allowance prices have been projected by PA Consulting in 2001 dollars and have been adjusted for the assumed rate of inflation. GENERAL AND ADMINISTRATIVE AND OTHER EXPENSES Southern Power has estimated certain general and administrative costs which have been included in the Projected Operating Results. These costs include, among other things, support services such as power marketing, computer systems and services, human resources, and accounting. These expenses have been assumed to increase at the general rate of inflation. In addition, Southern Power has estimated other expenses, which have also been included in the Projected Operating Results. Property taxes have been estimated by Southern Power for 2001 and have been assumed to escalate at the rate of inflation. Southern Power has also estimated annual financing costs of $270,000 per year. ANNUAL INTEREST We have included interest on the Notes and Southern Power's projection of an additional debt issuance which is assumed to pay off the balance of the Commercial Construction Revolver upon commercial operation of Goat Rock 2, the Harris Facility, and the Stanton Facility. In addition to the Notes, Southern Power has assumed that it will issue additional long-term debt of $650,000,000 on June 1, 2003 (together with the Notes, the "Debt"). We have included interest payments on the principal amount of the Debt at interest rates estimated by the Representatives of the Initial Purchasers resulting in a weighted average interest rate on the Debt over the term of the Notes of approximately 7.2 percent per year. The scheduled amortization of the Notes consists of a single payment due on July 15, 2012. Interest payments on the Notes are due each July 15 and January 15 beginning January 15, 2003. Southern Power has assumed that the Debt will be refinanced upon maturity at the same principal amounts and interest rates. No additional costs of issuance have been included. No amortization of the Debt has been assumed. INTEREST COVERAGE Interest coverage has been calculated as the cash available for debt service during the calendar year divided by interest on all Southern Power debt due on July 15 of that calendar year and January 15 of the next calendar year. On the basis of our studies and analyses of the Generating Facilities and the assumptions set forth in this Report, we are of the opinion that, for the Base Case Projected Operating Results, the projected revenues from the sale of electricity are adequate to pay annual operating and maintenance expenses (including major maintenance), fuel expense, and other operating expenses. Such revenues provide an annual interest coverage on the Debt of at least 3.28 times the annual interest requirement in each year during the term of the Notes and a weighted average coverage of 3.61 times the annual interest requirement on the Debt over the term of the Notes. There is insufficient cash available after the payment of interest to repay the entire principal due on the Debt upon maturity. Southern Power has assumed that the Debt will be refinanced upon maturity. The weighted average interest coverage has been calculated as the total A-40 net operating revenues, as shown in Exhibit A-1, over the term of the Notes divided by the total interest payments on the Debt over the term of the Notes. Annual interest coverages are presented in Exhibit A-1. SENSITIVITY ANALYSES Due to the uncertainties necessarily inherent in relying on assumptions and projections, it should be anticipated that certain circumstances and events may differ from those assumed and described herein and that such will affect the results of our Base Case Projected Operating Results for the Generating Facilities. In order to demonstrate the impact of certain circumstances on the Base Case Projected Operating Results, certain sensitivity analyses have been developed. It should be noted that other examples could have been considered and those presented are not intended to reflect the full extent of possible impacts on the Generating Facilities. The sensitivities are not presented in any particular order with regard to the likelihood of any case actually occurring. In addition, no assurance can be given that all relevant sensitivities have been presented, that the level of each sensitivity is the appropriate level for testing purposes, or that only one (rather than a combination of more than one) of such variations or sensitivities could impact the Generating Facilities in the future. These sensitivity analyses present the Projected Operating Results assuming, respectively, that: (a) the market prices, energy sales, and fuel prices are reduced according to the "Low Gas Price" scenario prepared by PA Consulting; (b) the market prices, energy sales, and fuel prices are reduced according to the "High Gas Price" scenario prepared by PA Consulting; (c) the market prices, energy sales, and fuel prices are reduced according to the "Capacity Overbuild" case prepared by PA Consulting; (d) the output of the Generating Facilities is reduced by 5 percent; (e) the availability of the Generating Facilities is reduced by 5 percentage points; (f) the heat rates of the Generating Facilities are 5 percent higher than that assumed in the Base Case; and (g) the non-fuel related operating expenses of the Generating Facilities are 10 percent higher than that assumed in the Base Case. The sensitivity analyses are presented as Exhibits A-2 through A-8 to this Report. For the purposes of (a) and (b), PA Consulting has prepared additional projections of dispatch and market prices. Based on discussions with PA Consulting, market sales and market prices have been assumed to be the same as the Base Case for the purposes of (d), (e), (f) and (g). SUMMARY COMPARISON OF PROJECTED OPERATING RESULTS A summary of the interest coverages for the Base Case Projected Operating Results and each sensitivity case is presented in Table 10. A-41 TABLE 10 PROJECTED INTEREST COVERAGE (1)
BASE CASE SENSITIVITY CASES A B C D E F G ---- ---- ---- ---- ---- ---- ---- CAPACITY YEAR LOW GAS HIGH GAS OVERBUILD INCREASED ENDING MARKET PRICE MARKET PRICE MARKET PRICE REDUCED REDUCED INCREASED OPERATING DEC 31, SCENARIO SCENARIO SCENARIO OUTPUT AVAILABILITY HEAT RATE EXPENSES ---------- ------------ ------------ ------------ ------- ------------ --------- --------- 2002 5.05 4.91 5.29 5.05 4.84 4.96 4.81 4.91 2003 3.30 3.19 3.28 3.19 3.13 3.26 3.18 3.21 2004 3.40 3.34 3.41 3.35 3.23 3.35 3.26 3.31 2005 3.33 3.08 3.36 3.22 3.14 3.19 3.16 3.23 2006 3.31 3.00 3.43 3.23 3.12 3.14 3.12 3.20 2012 4.24 4.23 4.16 3.72 3.96 4.10 4.01 4.11 2017 4.31 4.45 4.14 4.16 4.01 4.18 4.11 4.18 2022 4.86 5.01 4.66 4.76 4.52 4.77 4.66 4.72 Minimum (2) 3.28 2.97 3.28 3.19 3.09 3.10 3.07 3.16 Average (3) 3.61 3.42 3.65 3.37 3.41 3.47 3.42 3.50
- --------------- (1) Interest coverages beyond 2012 assume the refinancing of the Notes at the same interest rates, as estimated by the Representatives of the Initial Purchasers. (2) Represents minimum interest coverage on the Debt during any year over the term of the Notes assuming no principal repayment. (3) Represents the weighted average interest coverage on the Debt over the term of the Notes assuming no principal repayment. PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS USED IN THE PROJECTION OF OPERATING RESULTS In the preparation of this Report and the opinions that follow, we have made certain assumptions with respect to conditions which may exist or events which may occur in the future. While we believe these assumptions to be reasonable for the purpose of this Report, they are dependent upon future events, and actual conditions may differ from those assumed. In addition, we have used and relied upon certain information provided to us by sources which we believe to be reliable. While we believe the use of such information and assumptions to be reasonable for the purposes of our Report, we offer no other assurances thereto and some assumptions may vary significantly due to unanticipated events and circumstances. To the extent that actual future conditions differ from those assumed herein or provided to us by others, the actual results will vary from those projected herein. This Report summarizes our work up to the date of the Report. Thus, changed conditions occurring or becoming known after such date could affect the material presented to the extent of such changes. The principal considerations and assumptions made by us in developing the Base Case Projected Operating Results and the principal information provided to us by others include the following: 1. As Independent Engineer, we have made no determination as to the validity and enforceability of any contract, agreement, rule, or regulation applicable to the Generating Facilities and its operations. However, for purposes of this Report, we have assumed that all such contracts, agreements, rules, and regulations will be fully enforceable in accordance with their terms and that all parties will comply with the provisions of their respective agreements. 2. Our review of the design of the Generating Facilities was based on information developed by SCS and Southern Power and provided by Southern Power. 3. Southern Power, SCS, Alabama Power, and Georgia Power will maintain the Generating Facilities in accordance with good engineering practice, will perform all required major maintenance in a timely manner, and will not operate the equipment to cause it to exceed the equipment manufacturers' recommended maximum ratings. A-42 4. The operators will employ qualified and competent personnel and will generally operate the Generating Facilities in a sound and businesslike manner. 5. Inspections, overhauls, repairs and modifications are planned for and conducted in accordance with manufacturers' recommendations, and with special regard for the need to monitor certain operating parameters to identify early signs of potential problems. 6. All licenses, permits and approvals, and permit modifications necessary to operate the Generating Facilities have been, or will be, obtained on a timely basis and any changes in required licenses, or permits and approvals will not require reduced operation of, or increased costs to, the Generating Facilities. 7. The CPI, GDP-IPD, general inflation and all inflation-related indices will increase at a rate of 2.7 percent per year based on a March 10, 2002 projection prepared by Blue Chip Economic Indicators. 8. Retesting of Goat Rock 1 will demonstrate an additional 10 MW over that demonstrated during the preliminary net output test and will conform to the guaranteed output under the Construction Revolver Credit Agreement. 9. The actual performance of the Generating Facilities in each year will be equal to the long-term average estimates included in the Projected Operating Results. 10. The Generating Facilities will sell the quantities of electricity pursuant to the Power Purchase Agreements as projected by PA Consulting, at prices determined in accordance with the relevant Power Purchase Agreements. After the term of the Power Purchase Agreements, Southern Power will enter into long-term power purchase agreements at prices equivalent to the market electricity prices projected by PA Consulting and will sell the quantities of electricity as projected by PA Consulting. 11. The Goat Rock Facility will earn the revenue from contract sales to third parties in 2002 and 2003 as reported by Southern Power. 12. Certain of the Generating Facilities will achieve contract availabilities under their respective Power Purchase Agreements sufficient to receive the maximum capacity payments by purchasing additional energy from the market at prices estimated by PA Consulting. 13. Except for during the term of the Power Purchase Agreements when the energy purchaser is responsible for the cost of fuel, the cost of fuel will be as projected by PA Consulting. 14. Southern Power will operate the Generating Facilities at the load levels projected by PA Consulting, resulting in the annual average heat rates assumed in the Projected Operating Results, resulting in no additional fuel cost under the Power Purchase Agreements. 15. The non-fuel operating and maintenance expenses, including the cost of major maintenance, will be consistent with the projection provided by Southern Power in 2001 dollars, and will increase at the assumed change in the general inflation rate, except for a portion of the administrative and general expenses. 16. The assumed quantity of emissions allowances will be allocated to Southern Power through the term of the Notes. The price of NO(x) and SO(2) emissions allowances will be as projected by PA Consulting, as adjusted for the assumed rate of inflation. 17. There will be no additional capital improvements to the Generating Facilities other than those assumed in the Projected Operating Results. 18. All revenue from the Generating Facilities beginning June 1, 2002 will be available to pay interest on the Notes. A-43 19. The principal amount of the Notes will be $575,000,000. Additional Debt of $650,000,000 will be issued on June 1, 2003. The interest rates on the Debt will be as estimated by the Representatives of the Initial Purchasers, resulting in a weighted average interest rate over the term of the Notes of approximately 7.2 percent per year. The Debt will be refinanced upon maturity, as assumed by Southern Power, at the same respective principal amounts and interest rates, as estimated by the Representatives of the Initial Purchasers. CONCLUSIONS Set forth below are the principal opinions we have reached after our review of the Generating Facilities. For a complete understanding of the estimates, assumptions, and calculations upon which these opinions are based, the Report should be read in its entirety. On the basis of our review and analyses of the Generating Facilities and the assumptions set forth in this Report, we are of the opinion that: 1. Provided Southern Power takes into account the recommendations in the geotechnical reports by Southern Geotech, the sites for the Generating Facilities are suitable for the construction and operation of the Generating Facilities. 2. Based on GE's previously demonstrated capability to address the issues similar to those related to the Frame 7FA described herein, the power generation technologies proposed for the Generating Facilities are sound, proven methods of energy recovery. If constructed, operated and maintained as proposed by Southern Power, the Generating Facilities should be capable of meeting the requirements of the Power Purchase Agreements and the currently applicable environmental permit requirements. Furthermore, all off-site requirements of the Generating Facilities have been adequately provided for, including fuel supply, water supply, wastewater disposal, and electrical interconnection. 3. The proposed method of design, construction, operation, and maintenance of the Generating Facilities has been developed in accordance with generally accepted industry practice and has taken into consideration the current environmental, license and permit requirements that the Generating Facilities must meet. 4. Based on our review and provided that: (a) the units are operated and maintained by the operators in accordance with the policies and procedures as presented by Southern Power, (b) all required renewals and replacements are made on a timely basis as the units age, and (c) gas and oil burned by the units are within the expected range with respect to quantity and quality, the Generating Facilities should have useful lives of at least 20 years. 5. The performance guarantees proposed for the Generating Facilities under construction, if all the equipment contract guarantees are considered in their entirety, are similar to the performance tests of turnkey projects with which we are familiar. 6. The Generating Facilities should be capable of achieving the annual average output in full-pressure mode with power augmentation and the average annual net plant heat rates assumed in the Projected Operating Results. 7. The Generating Facilities should be capable of achieving the required average annual contract availabilities under the Power Purchase Agreements ranging from 96.5 to 97 percent, which exclude scheduled maintenance and allow Southern Power to replace the undelivered energy from another resource, and should also be capable of achieving an average annual availability of 92 percent, which includes provision for forced and scheduled maintenance. 8. The environmental site assessments performed by TTL, URS, ECT, and Williams related to the sites of the Generating Facilities were conducted in a manner consistent with industry standards, using comparable industry protocols for similar studies with which we are familiar. A-44 9. Southern Power has identified the major permits and approvals necessary for the construction and operation of the Generating Facilities. While all of the required permits and approvals have not yet been obtained, we did not identify any technical or engineering circumstance that would prevent the issuance of the remaining permits and approvals. 10. Southern Power's estimates of the costs of operating and maintaining the Generating Facilities, including provision for major maintenance, are within the range of the costs of similar plants with which we are familiar. 11. For the Base Case Projected Operating Results, the projected revenues from the sale of electricity are adequate to pay annual operating and maintenance expenses (including major maintenance), fuel expense, and other operating expenses. Such revenues provide an annual interest coverage on the Debt of at least 3.28 times the annual interest requirement in each year during the term of the Notes and a weighted average coverage of 3.61 times the annual interest requirement on the Debt over the term of the Notes. There is insufficient cash available after the payment of interest to repay the entire principal due on the Debt upon maturity. Southern Power has assumed that the Debt will be refinanced upon maturity. Respectfully submitted, /S/ R. W. BECK, INC. A-45 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2002(1) 2003 2004 2005 2006 2007 2008 - ------------------------ -------- ------- ------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 2,489 4,678 4,678 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 37.2% 14.7% 21.0% 25.9% 31.5% 33.5% 31.5% Contract Energy Sales (GWh)(4) 4,404 5,016 8,263 10,912 13,205 14,039 13,229 Other Energy Sales (GWh)(4) 268 1,053 541 0 47 45 44 -------- ------- ------- ------- ------- ------- ------- Total Energy Sales (GWh) 4,672 6,069 8,804 10,912 13,252 14,084 13,273 Fuel Consumption (BBtu) 33,408 46,663 66,407 82,283 99,399 104,941 99,572 Average Net Heat Rate (Btu/kWh)(5) 7,053 7,727 7,706 7,749 7,704 7,652 7,704 SO(2) Allowances Purchased (Tons)(6) 17 23 32 41 50 53 50 NO(x) Allowances Purchased (Tons)(7) 0 0 (95) 19 66 83 74 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 51.53 60.50 70.74 73.59 77.20 77.23 77.26 Contract Energy Price ($/MWh)(10) $ 3.72 6.65 6.32 7.38 6.95 6.78 7.42 Other Capacity Price ($/MWh)(11) $ 16.49 16.35 16.84 16.38 16.82 17.27 51.65 Other Energy Price ($/MWh)(11) $ 34.62 42.40 41.94 0.00 61.96 60.77 61.12 Fuel Price ($/MMBtu)(12) $ 3.94 4.83 4.61 0.00 3.32 3.45 3.56 SO(2) Allowances ($/Ton)(13) $ 154 158 162 167 171 176 181 NO(x) Allowances ($/Ton)(14) $ 0 0 2,006 1,707 1,753 1,800 1,849 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 29,314 46,845 45,510 2,666 0 0 0 Goat Rock(15) $ 38,262 80,211 102,807 115,807 118,340 120,728 120,302 Harris(15) $ 0 41,860 103,979 130,878 133,881 133,884 136,567 Stanton $ 0 9,970 43,098 44,343 44,734 45,020 45,450 Wansley $ 67,098 86,353 84,225 88,659 94,005 94,945 95,237 Other Electricity Revenues Dahlberg $ 0 0 0 11,886 16,393 16,570 44,122 Goat Rock(15) $ 10,188 16,024 9,284 0 0 0 0 Harris $ 0 38,269 17,711 0 0 0 0 Stanton $ 0 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 0 -------- ------- ------- ------- ------- ------- ------- Total Operating Revenues $144,862 319,533 406,614 394,239 407,353 411,147 441,678 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 0 0 0 0 1,747 1,771 1,782 Goat Rock $ 7,677 12,076 6,935 0 0 0 0 Harris $ 0 28,273 12,714 0 0 0 0 Stanton $ 0 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 0 Emissions Allowances $ 0 0 (191) (108) (55) (34) (44) Purchased Power $ 2,712 3,005 7,907 12,547 14,913 16,306 15,856 Operations & Maintenance $ 9,572 19,738 28,350 31,352 35,228 37,135 37,200 Major Maintenance $ 11,605 17,836 25,034 30,385 36,548 39,529 38,745 Administration $ 3,022 7,866 10,457 10,739 11,029 11,328 11,633 Insurance $ 756 1,995 2,676 2,748 2,821 2,899 2,978 Property Taxes $ 3,566 10,113 13,679 13,706 13,734 13,762 13,792 Other $ 90 216 270 270 270 270 270 -------- ------- ------- ------- ------- ------- ------- Total Operating Expenses $ 39,000 101,118 107,831 101,639 116,235 122,966 122,212 NET OPERATING REVENUES ($000) $105,862 218,415 298,783 292,601 291,118 288,181 319,466 ANNUAL INTEREST($000)(17) $ 20,964 66,271 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 5.05 3.30 3.40 3.33 3.31 3.28 3.63 2002-12 AVG INTEREST COVERAGE(19) 3.61 Year Ending December 31, 2009 2010 2011 2012 - ------------------------ ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 32.4% 32.2% 30.9% 29.6% Contract Energy Sales (GWh)(4) 13,543 7,180 4,131 3,314 Other Energy Sales (GWh)(4) 98 6,195 8,623 8,942 ------- ------- ------- ------- Total Energy Sales (GWh) 13,640 13,375 12,754 12,256 Fuel Consumption (BBtu) 102,438 102,287 98,157 94,697 Average Net Heat Rate (Btu/kWh)(5) 7,710 7,745 7,762 7,794 SO(2) Allowances Purchased (Tons)(6) 51 51 49 48 NO(x) Allowances Purchased (Tons)(7) 72 83 77 73 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 77.28 40.00 60.62 84.98 Contract Energy Price ($/MWh)(10) 7.45 8.10 11.19 10.30 Other Capacity Price ($/MWh)(11) 51.68 60.96 66.92 71.14 Other Energy Price ($/MWh)(11) 65.13 48.21 49.51 50.91 Fuel Price ($/MMBtu)(12) 3.67 4.63 4.78 4.95 SO(2) Allowances ($/Ton)(13) 186 191 196 201 NO(x) Allowances ($/Ton)(14) 1,899 1,950 2,002 2,057 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Goat Rock(15) 121,990 79,486 24,459 0 Harris(15) 135,147 87,426 72,017 72,338 Stanton 45,922 46,232 46,361 46,701 Wansley 97,381 0 0 0 Other Electricity Revenues Dahlberg 47,808 57,322 64,136 67,506 Goat Rock(15) 0 87,654 224,321 275,993 Harris 0 94,299 141,055 142,338 Stanton 0 0 0 0 Wansley 0 225,029 231,031 231,168 ------- ------- ------- ------- Total Operating Revenues 448,248 677,448 803,380 836,044 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 4,057 5,413 6,835 6,530 Goat Rock 0 47,765 120,080 148,195 Harris 0 52,219 76,505 76,796 Stanton 0 0 0 0 Wansley 0 117,408 115,791 112,603 Emissions Allowances (45) 163 160 156 Purchased Power 16,830 8,255 5,588 5,585 Operations & Maintenance 39,177 40,334 40,963 41,271 Major Maintenance 40,454 42,286 46,076 41,444 Administration 11,946 12,270 12,599 12,942 Insurance 3,057 3,140 3,224 3,311 Property Taxes 13,822 13,853 13,885 13,918 Other 270 270 270 270 ------- ------- ------- ------- Total Operating Expenses 129,568 343,375 441,976 463,022 NET OPERATING REVENUES ($000) 318,680 334,073 361,404 373,022 ANNUAL INTEREST($000)(17) 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 3.62 3.80 4.11 4.24 2002-12 AVG INTEREST COVERAGE(19)
A-46 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2013 2014 2015 2016 2017 2018 - ------------------------ -------- ------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,668 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 26.9% 24.5% 22.5% 21.8% 20.6% 19.8% Contract Energy Sales (GWh)(4) 2,803 1,680 1,494 1,432 1,296 1,291 Other Energy Sales (GWh)(4) 8,281 8,395 7,737 7,533 7,172 6,829 -------- ------- ------- ------- ------- ------- Total Energy Sales (GWh) 11,084 10,075 9,231 8,965 8,469 8,120 Fuel Consumption (BBtu) 86,581 78,843 73,165 71,203 67,456 64,506 Average Net Heat Rate (Btu/kWh)(5) 7,844 7,859 7,958 7,974 7,996 7,976 SO(2) Allowances Purchased (Tons)(6) 43 39 37 34 34 32 NO(x) Allowances Purchased (Tons)(7) 48 31 7 (5) (23) (29) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 79.61 88.55 88.55 88.55 88.55 88.55 Contract Energy Price ($/MWh)(10) $ 11.92 11.02 12.47 12.98 13.20 14.50 Other Capacity Price ($/MWh)(11) $ 74.88 74.48 77.98 78.32 79.53 83.65 Other Energy Price ($/MWh)(11) $ 52.34 55.56 57.92 60.04 63.19 64.92 Fuel Price ($/MMBtu)(12) $ 5.17 5.52 5.74 5.97 6.20 6.38 SO(2) Allowances ($/Ton)(13) $ 207 212 218 224 230 236 NO(x) Allowances ($/Ton)(14) $ 2,112 2,169 2,228 2,288 2,350 2,413 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 0 Goat Rock (15) $ 0 0 0 0 0 0 Harris (15) $ 72,851 71,243 71,353 71,308 69,836 71,447 Stanton $ 40,086 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 68,758 65,363 70,529 68,676 66,445 68,791 Goat Rock (15) $271,900 266,857 259,513 259,723 256,662 262,136 Harris $141,858 135,894 133,067 131,352 133,374 136,753 Stanton $ 11,653 89,439 91,775 95,005 102,605 101,731 Wansley $218,882 212,190 210,896 216,560 218,032 214,655 -------- ------- ------- ------- ------- ------- Total Operating Revenues $825,988 840,986 837,133 842,624 846,954 855,513 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 5,398 3,557 5,036 3,886 1,875 1,352 Goat Rock $144,260 139,150 131,512 133,474 129,954 127,866 Harris $ 76,321 70,936 68,599 67,375 68,128 68,423 Stanton $ 7,449 54,155 54,935 57,058 61,212 60,221 Wansley $101,122 96,568 92,806 96,861 93,865 88,860 Emissions Allowances $ 109 73 24 (5) (50) (61) Purchased Power $ 2,341 2,278 2,133 2,117 2,044 2,089 Operations & Maintenance $ 40,586 39,938 40,135 40,627 40,559 40,983 Major Maintenance $ 41,406 37,592 36,561 37,978 37,710 37,110 Administration $ 13,290 13,650 14,016 14,395 14,786 15,186 Insurance $ 3,400 3,493 3,587 3,684 3,784 3,887 Property Taxes $ 13,952 13,986 14,022 14,058 14,096 14,134 Other $ 270 270 270 270 270 270 -------- ------- ------- ------- ------- ------- Total Operating Expenses $449,904 475,648 463,637 471,778 468,235 460,320 NET OPERATING REVENUES ($000) $376,083 365,338 373,496 370,846 378,719 395,193 ANNUAL INTEREST($000) (17) $ 87,938 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE (18) 4.28 4.15 4.25 4.22 4.31 4.49 2002-12 AVG INTEREST COVERAGE (19) 3.61 Year Ending December 31, 2019 2020 2021 2022 - ------------------------ ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 18.8% 18.7% 17.2% 17.2% Contract Energy Sales (GWh)(4) 393 0 0 0 Other Energy Sales (GWh)(4) 7,281 7,645 7,026 7,026 ------- ------- ------- ------- Total Energy Sales (GWh) 7,674 7,645 7,026 7,026 Fuel Consumption (BBtu) 61,368 61,548 56,707 56,707 Average Net Heat Rate (Btu/kWh)(5) 7,997 8,050 8,071 8,071 SO(2) Allowances Purchased (Tons)(6) 30 30 28 28 NO(x) Allowances Purchased (Tons)(7) (32) (41) (48) (48) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 22.14 0.00 0.00 0.00 Contract Energy Price ($/MWh)(10) 9.07 0.00 0.00 0.00 Other Capacity Price ($/MWh)(11) 85.52 87.87 89.72 92.15 Other Energy Price ($/MWh)(11) 68.21 70.54 72.47 74.42 Fuel Price ($/MMBtu)(12) 6.57 6.83 7.06 7.22 SO(2) Allowances ($/Ton)(13) 242 249 256 262 NO(x) Allowances ($/Ton)(14) 2,478 2,545 2,614 2,684 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Goat Rock (15) 0 0 0 0 Harris (15) 16,750 0 0 0 Stanton 0 0 0 0 Wansley 0 0 0 0 Other Electricity Revenues Dahlberg 72,445 73,371 75,626 77,671 Goat Rock (15) 263,922 263,158 261,061 268,112 Harris 226,790 281,380 267,973 275,211 Stanton 107,421 110,763 108,620 111,553 Wansley 209,232 220,843 214,741 220,541 ------- ------- ------- ------- Total Operating Revenues 896,560 949,515 928,021 953,088 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 2,856 2,301 2,942 3,022 Goat Rock 125,097 125,325 122,136 124,957 Harris 109,565 137,165 126,738 129,657 Stanton 62,975 65,417 62,988 64,273 Wansley 82,184 90,313 85,366 87,275 Emissions Allowances (74) (99) (118) (122) Purchased Power 0 0 0 0 Operations & Maintenance 41,642 42,659 42,912 44,072 Major Maintenance 36,643 37,586 36,218 37,196 Administration 15,595 16,015 16,447 16,893 Insurance 3,991 4,100 4,210 4,324 Property Taxes 14,174 14,214 14,256 14,299 Other 270 270 270 270 ------- ------- ------- ------- Total Operating Expenses 494,917 535,266 514,364 526,115 NET OPERATING REVENUES ($000) 401,643 414,249 413,657 426,973 ANNUAL INTEREST($000) (17) 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE (18) 4.57 4.71 4.70 4.86 2002-12 AVG INTEREST COVERAGE (19)
A-47 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2002(1) 2003 2004 2005 2006 2007 2008 - ------------------------ ------- ------ ------ ------ ------ ------ ------ DAHLBERG FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 802 802 802 802 802 802 802 Average Annual Contract Capacity (MW)(20) 803 803 803 225 0 0 0 Average Annual Other Capacity (MW)(20) 0 0 0 802 802 802 802 Capacity Factor(%)(3) 0.1% 0.0% 0.0% 0.0% 0.7% 0.6% 0.6% Energy Generation (GWh) 5 0 0 0 47 45 44 Contract Energy Sales (GWh) 5 0 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 0 0 0 0 47 45 44 Net Heat Rate (Btu/kWh)(5) 11,362 0 0 0 11,219 11,471 11,332 Contract Fuel Consumption (BBtu) 53 0 0 0 0 0 0 Other Fuel Consumption (BBtu) 0 0 0 0 526 513 501 SO(2) Allowances Purchased (Tons)(6) 0 0 0 0 0 0 0 NO(x) Allowances Purchased (Tons)(7) 0 0 0 0 6 6 6 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) $ 62.57 58.37 56.71 11.85 0.00 0.00 0.00 Contract Energy ($/MWh) $ 4.72 0.00 0.00 0.00 0.00 0.00 0.00 Start Up Charge ($/Start) $ 0 0 0 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) $ 0.00 0.00 0.00 14.82 16.82 17.27 51.65 Other Energy ($/MWh) $ 0.00 0.00 0.00 0.00 61.96 60.77 61.12 Fuel ($/MMBtu)(12) $ 0.00 0.00 0.00 0.00 3.32 3.45 3.56 SO(2) Allowances ($/Ton)(13) $ 154 158 162 167 171 176 181 NO(x) Allowances ($/Ton)(14) $ 0 0 2,006 1,707 1,753 1,800 1,849 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues $29,291 46,845 45,510 2,666 0 0 0 Contract Energy Revenues $ 17 0 0 0 0 0 0 Contract VOM Hourly Revenues $ 0 0 0 0 0 0 0 Start-Up Charges Revenues $ 0 0 0 0 0 0 0 Heat Rate Adjustment Payment $ 0 0 0 0 0 0 0 Purchase Power Fuel Adjustment Payment $ 6 0 0 0 0 0 0 Other Electricity Revenues Other Capacity Revenues $ 0 0 0 11,886 13,488 13,852 41,420 Other Energy Revenues $ 0 0 0 0 2,905 2,718 2,702 ------- ------ ------ ------ ------ ------ ------ Total Operating Revenues $29,314 46,845 45,510 14,552 16,393 16,570 44,122 OPERATING EXPENSES ($000)(16) Fuel Costs $ 0 0 0 0 1,747 1,771 1,782 Emissions Allowances $ 0 0 0 0 11 11 11 Purchased Power $ 11 0 0 0 0 0 0 Operating and Maintenance $ 37 0 0 0 415 407 414 Major Maintenance $ 405 692 711 730 884 902 925 Administrative and General $ 2,991 5,206 5,289 5,374 5,459 5,549 5,640 Other $ 36 63 63 63 63 63 63 ------- ------ ------ ------ ------ ------ ------ Total Operating Expenses $ 3,480 5,961 6,063 6,167 8,579 8,703 8,835 NET OPERATING REVENUES ($000) $25,834 40,884 39,447 8,385 7,814 7,867 35,287 Year Ending December 31, 2009 2010 2011 2012 - ------------------------ ------ ------ ------ ------ DAHLBERG FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 802 802 802 802 Average Annual Contract Capacity (MW)(20) 0 0 0 0 Average Annual Other Capacity (MW)(20) 802 802 802 802 Capacity Factor(%)(3) 1.4% 1.8% 2.2% 2.0% Energy Generation (GWh) 98 126 153 141 Contract Energy Sales (GWh) 0 0 0 0 Other Energy Sales (Purchases)(GWh) 98 126 153 141 Net Heat Rate (Btu/kWh)(5) 11,318 11,284 11,282 11,324 Contract Fuel Consumption (BBtu) 0 0 0 0 Other Fuel Consumption (BBtu) 1,106 1,423 1,727 1,598 SO(2) Allowances Purchased (Tons)(6) 1 1 1 1 NO(x) Allowances Purchased (Tons)(7) 13 17 20 19 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) 0.00 0.00 0.00 0.00 Contract Energy ($/MWh) 0.00 0.00 0.00 0.00 Start Up Charge ($/Start) 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) 51.68 60.96 66.92 71.14 Other Energy ($/MWh) 65.13 66.87 68.38 74.06 Fuel ($/MMBtu)(12) 3.67 3.80 3.96 4.09 SO(2) Allowances ($/Ton)(13) 186 191 196 201 NO(x) Allowances ($/Ton)(14) 1,899 1,950 2,002 2,057 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues 0 0 0 0 Contract Energy Revenues 0 0 0 0 Contract VOM Hourly Revenues 0 0 0 0 Start-Up Charges Revenues 0 0 0 0 Heat Rate Adjustment Payment 0 0 0 0 Purchase Power Fuel Adjustment Payment 0 0 0 0 Other Electricity Revenues Other Capacity Revenues 41,444 48,890 53,668 57,056 Other Energy Revenues 6,364 8,432 10,468 10,450 ------ ------ ------ ------ Total Operating Revenues 47,808 57,322 64,136 67,506 OPERATING EXPENSES ($000)(16) Fuel Costs 4,057 5,413 6,835 6,530 Emissions Allowances 25 33 41 39 Purchased Power 0 0 0 0 Operating and Maintenance 937 1,243 1,550 1,466 Major Maintenance 1,116 1,237 5,780 1,370 Administrative and General 5,732 5,829 5,927 6,030 Other 63 63 63 63 ------ ------ ------ ------ Total Operating Expenses 11,929 13,817 20,196 15,497 NET OPERATING REVENUES ($000) 35,879 43,505 43,940 52,009
A-48 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2013 2014 2015 2016 2017 - ------------------------ ------- ------ ------ ------ ------ DAHLBERG FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 802 802 802 802 802 Average Annual Contract Capacity (MW)(20) 0 0 0 0 0 Average Annual Other Capacity (MW)(20) 802 802 802 802 802 Capacity Factor (%)(3) 1.6% 1.1% 1.4% 1.1% 0.5% Energy Generation (GWh) 115 74 100 74 35 Contract Energy Sales (GWh) 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 115 74 100 74 35 Net Heat Rate (Btu/kWh)(5) 11,318 11,239 11,274 11,255 11,264 Contract Fuel Consumption (BBtu) 0 0 0 0 0 Other Fuel Consumption (BBtu) 1,296 831 1,133 837 390 SO(2) Allowances Purchased (Tons)(6) 1 0 1 0 0 NO(x) Allowances Purchased (Tons)(7) 15 10 13 10 5 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) $ 0.00 0.00 0.00 0.00 0.00 Contract Energy ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 Start Up Charge ($/Start) $ 0 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) $ 75.12 74.48 78.07 78.13 79.33 Other Energy ($/MWh) $ 74.30 76.19 78.80 80.94 81.59 Fuel ($/MMBtu)(12) $ 4.17 4.28 4.44 4.64 4.81 SO(2) Allowances ($/Ton)(13) $ 207 212 218 224 230 NO(x) Allowances ($/Ton)(14) $ 2,112 2,169 2,228 2,288 2,350 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues $ 0 0 0 0 0 Contract Energy Revenues $ 0 0 0 0 0 Contract VOM Hourly Revenues $ 0 0 0 0 0 Start-Up Charges Revenues $ 0 0 0 0 0 Heat Rate Adjustment Payment $ 0 0 0 0 0 Purchase Power Fuel Adjustment Payment $ 0 0 0 0 0 Other Electricity Revenues Other Capacity Revenues $60,250 59,730 62,610 62,657 63,620 Other Energy Revenues $ 8,508 5,633 7,919 6,019 2,825 ------- ------ ------ ------ ------ Total Operating Revenues $68,758 65,363 70,529 68,676 66,445 OPERATING EXPENSES ($000)(16) Fuel Costs $ 5,398 3,557 5,036 3,886 1,875 Emissions Allowances $ 32 21 30 23 11 Purchased Power $ 0 0 0 0 0 Operating and Maintenance $ 1,223 811 1,131 860 412 Major Maintenance $ 3,172 1,190 1,323 1,257 1,138 Administrative and General $ 6,133 6,241 6,351 6,464 6,581 Other $ 63 63 63 63 63 ------- ------ ------ ------ ------ Total Operating Expenses $16,021 11,884 13,934 12,553 10,080 NET OPERATING REVENUES ($000) $52,737 53,479 56,595 56,123 56,365 Year Ending December 31, 2018 2019 2020 2021 2022 - ------------------------ ------- ------ ------ ------ ------ DAHLBERG FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 802 802 802 802 802 Average Annual Contract Capacity (MW)(20) 0 0 0 0 0 Average Annual Other Capacity (MW)(20) 802 802 802 802 802 Capacity Factor (%)(3) 0.3% 0.7% 0.5% 0.7% 0.7% Energy Generation (GWh) 24 49 38 47 47 Contract Energy Sales (GWh) 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 24 49 38 47 47 Net Heat Rate (Btu/kWh)(5) 11,298 11,358 11,302 11,217 11,217 Contract Fuel Consumption (BBtu) 0 0 0 0 0 Other Fuel Consumption (BBtu) 273 553 428 529 529 SO(2) Allowances Purchased (Tons)(6) 0 0 0 0 0 NO(x) Allowances Purchased (Tons)(7) 3 7 5 6 6 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) 0.00 0.00 0.00 0.00 0.00 Contract Energy ($/MWh) 0.00 0.00 0.00 0.00 0.00 Start Up Charge ($/Start) 0 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) 83.30 85.07 87.42 89.12 91.53 Other Energy ($/MWh) 82.02 86.57 86.01 88.04 90.42 Fuel ($/MMBtu)(12) 4.95 5.16 5.38 5.56 5.71 SO(2) Allowances ($/Ton)(13) 236 242 249 256 262 NO(x) Allowances ($/Ton)(14) 2,413 2,478 2,545 2,614 2,684 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues 0 0 0 0 0 Contract Energy Revenues 0 0 0 0 0 Contract VOM Hourly Revenues 0 0 0 0 0 Start-Up Charges Revenues 0 0 0 0 0 Heat Rate Adjustment Payment 0 0 0 0 Purchase Power Fuel Adjustment Payment 0 0 0 0 0 Other Electricity Revenues Other Capacity Revenues 66,809 68,230 70,114 71,474 73,407 Other Energy Revenues 1,982 4,215 3,257 4,152 4,264 ------ ------ ------ ------ ------ Total Operating Revenues 68,791 72,445 73,371 75,626 77,671 OPERATING EXPENSES ($000)(16) Fuel Costs 1,352 2,856 2,301 2,942 3,022 Emissions Allowances 8 16 13 16 17 Purchased Power 0 0 0 0 0 Operating and Maintenance 295 610 487 623 640 Major Maintenance 1,127 1,257 1,246 1,332 1,368 Administrative and General 6,700 6,823 6,947 7,075 7,209 Other 63 63 63 63 63 ------ ------ ------ ------ ------ Total Operating Expenses 9,545 11,626 11,057 12,052 12,319 NET OPERATING REVENUES ($000) 59,246 60,819 62,314 63,574 65,352
A-49 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2002(1) 2003 2004 2005 2006 2007 - ------------------------ ------- ------ ------- ------- ------- ------- GOAT ROCK FACILITY PERFORMANCE Average Annual Capacity(MW)(2) 564 1,159 1,159 1,159 1,159 1,159 Average Annual Contract Capacity (MW) 370 908 1,108 1,159 1,159 1,159 Average Annual Other Capacity (MW) 56 183 66 0 0 0 Capacity Factor (%)(3) 59.4% 26.3% 25.1% 34.7% 40.7% 43.0% Energy Generation (GWh) 1,711 2,096 2,551 3,526 4,129 4,363 Contract Energy Sales(GWh) 1,301 1,719 2,375 3,616 4,235 4,475 Other Energy Sales (Purchases)(GWh) 268 330 203 0 0 0 Net Heat Rate (Btu/kWh)(5) 6,679 7,599 7,750 7,655 7,615 7,583 Contract Fuel Consumption(BBtu) 9,481 13,355 18,185 26,991 31,443 33,084 Other Fuel Consumption (BBtu) 1,950 2,571 1,586 0 0 0 SO(2) Allowances Purchased (Tons)(6) 6 8 10 13 16 17 NO(x) Allowances Purchased (Tons)(7) 0 0 (43) (27) (16) (10) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) $ 99.01 69.28 77.92 77.96 77.96 77.96 Contract Energy ($/MWh) $ 3.63 8.47 6.93 7.05 6.62 6.80 Start Up Charge ($/Start) $11,996 32,086 26,372 31,951 31,283 34,313 Forward Net Revenue ($000) $12,168 2,713 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) $ 16.50 16.35 16.85 0.00 0.00 0.00 Other Energy ($/MWh) $ 34.62 39.53 40.28 0.00 0.00 0.00 Fuel ($/MMBtu)(12) $ 3.09 3.46 3.52 0.00 0.00 0.00 SO(2) Allowances ($/Ton)(13) $ 154 158 162 167 171 176 NO(x) Allowances ($/Ton)(14) $ 0 0 2,006 1,707 1,753 1,800 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues $21,369 62,934 86,335 90,318 90,318 90,318 Contract Energy Revenues $ 3,926 5,180 7,266 11,360 13,664 14,848 Contract VOM Hourly Revenues $ 0 0 0 0 0 0 Start-Up Charges Revenues $ 799 9,384 8,469 12,077 12,156 13,152 Net Forward Revenue $12,168 2,713 0 0 0 0 Heat Rate Adjustment Payment $ 0 0 0 0 0 0 Purchase Power Fuel Adjustment Payment $ 0 0 737 2,052 2,202 2,410 Other Electricity Revenues Other Capacity Revenues $ 924 2,992 1,112 0 0 0 Other Energy Revenues $ 9,264 13,032 8,172 0 0 0 ------- ------ ------- ------- ------- ------- Total Operating Revenues $48,450 96,235 112,091 115,807 118,340 120,728 OPERATING EXPENSES ($000)(16) Fuel Costs $ 7,677 12,076 6,935 0 0 0 Emissions Allowances $ 0 0 (87) (45) (27) (19) Purchased Power $ 0 0 1,149 3,664 4,337 4,774 Operating and Maintenance $ 3,094 6,321 8,128 9,279 10,121 10,632 Major Maintenance $ 4,019 5,844 7,465 9,893 11,584 12,384 Administrative and General $ 2,442 6,765 8,663 8,751 8,842 8,936 Other $ 18 49 62 62 62 62 ------- ------ ------- ------- ------- ------- Total Operating Expenses $17,249 31,055 32,315 31,603 34,919 36,770 NET OPERATING REVENUES ($000) $31,201 65,180 79,776 84,204 83,421 83,958 Year Ending December 31, 2008 2009 2010 2011 2012 - ------------------------ ------- ------- ------- ------- ------- GOAT ROCK FACILITY PERFORMANCE Average Annual Capacity(MW)(2) 1,159 1,159 1,159 1,159 1,159 Average Annual Contract Capacity (MW) 1,159 1,159 1,159 595 0 Average Annual Other Capacity (MW) 0 0 564 1,159 1,159 Capacity Factor (%)(3) 40.8% 42.2% 42.8% 40.0% 39.0% Energy Generation (GWh) 4,146 4,288 4,348 4,058 3,955 Contract Energy Sales(GWh) 4,252 4,398 3,028 728 0 Other Energy Sales (Purchases)(GWh) 0 0 1,378 3,330 3,955 Net Heat Rate(Btu/kWh)(5) 7,613 7,604 7,618 7,618 7,661 Contract Fuel Consumption(BBtu) 31,562 32,607 22,672 5,574 0 Other Fuel Consumption (BBtu) 0 0 10,449 25,343 30,299 SO(2) Allowances Purchased (Tons)(6) 16 16 17 15 15 NO(x) Allowances Purchased (Tons)(7) (12) (16) (10) (16) (15) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) 77.96 77.96 49.87 47.32 0.00 Contract Energy ($/MWh) 7.05 7.20 7.17 17.47 0.00 Start Up Charge ($/Start) 33,512 35,142 23,559 25,480 0 Forward Net Revenue ($000) 0 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) 0.00 0.00 41.66 56.03 71.14 Other Energy ($/MWh) 0.00 0.00 46.58 47.87 48.94 Fuel ($/MMBtu)(12) 0.00 0.00 3.95 4.07 4.21 SO(2) Allowances ($/Ton)(13) 181 186 191 196 201 NO(x) Allowances ($/Ton)(14) 1,849 1,899 1,950 2,002 2,057 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues 90,318 90,318 57,774 11,731 0 Contract Energy Revenues 14,487 15,378 10,678 2,594 0 Contract VOM Hourly Revenues 0 0 0 0 0 Start-Up Charges Revenues 13,089 13,781 9,959 10,134 0 Net Forward Revenue 0 0 0 0 0 Heat Rate Adjustment Payment 0 0 0 0 0 Purchase Power Fuel Adjustment Payment 2,408 2,513 1,075 0 0 Other Electricity Revenues Other Capacity Revenues 0 0 23,473 64,925 82,433 Other Energy Revenues 0 0 64,181 159,396 193,560 ------- ------- ------- ------- ------- Total Operating Revenues 120,302 121,990 167,140 248,780 275,993 OPERATING EXPENSES ($000)(16) Fuel Costs 0 0 47,765 120,080 148,195 Emissions Allowances (21) (30) (20) (31) (28) Purchased Power 4,657 5,015 2,709 0 0 Operating and Maintenance 10,694 11,133 11,499 11,483 11,674 Major Maintenance 12,240 12,846 13,369 12,841 13,053 Administrative and General 9,032 9,130 9,231 9,334 9,441 Other 62 62 62 62 62 ------- ------- ------- ------- ------- Total Operating Expenses 36,663 38,156 84,615 153,769 182,397 NET OPERATING REVENUES ($000) 83,639 83,834 82,525 95,011 93,596
A-50 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2013 2014 2015 2016 2017 - ------------------------ -------- ------- ------- ------- ------- GOAT ROCK FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 1,159 1,159 1,159 1,159 1,159 Average Annual Contract Capacity (MW) 0 0 0 0 0 Average Annual Other Capacity (MW) 1,159 1,159 1,159 1,159 1,159 Capacity Factor (%)(3) 36.3% 33.8% 29.9% 28.7% 26.7% Energy Generation (GWh) 3,681 3,428 3,040 2,909 2,709 Contract Energy Sales (GWh) 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 3,681 3,428 3,040 2,909 2,709 Net Heat Rate (Btu/kWh)(5) 7,715 7,706 7,829 7,902 7,948 Contract Fuel Consumption (BBtu) 0 0 0 0 0 Other Fuel Consumption (BBtu) 28,395 26,418 23,798 22,990 21,532 SO(2) Allowances Purchased (Tons)(6) 14 13 12 11 11 NO(x) Allowances Purchased (Tons)(7) (23) (24) (35) (40) (47) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) $ 0.00 0.00 0.00 0.00 0.00 Contract Energy ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 Start Up Charge ($/Start) $ 0 0 0 0 0 Forward Net Revenue ($000) $ 0 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) $ 75.13 74.48 78.07 78.13 79.33 Other Energy ($/MWh) $ 50.22 52.67 55.62 58.15 60.81 Fuel ($/MMBtu)(12) $ 4.33 4.45 4.60 4.83 5.04 SO(2) Allowances ($/Ton)(13) $ 207 212 218 224 230 NO(x) Allowances ($/Ton)(14) $ 2,112 2,169 2,228 2,288 2,350 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues $ 0 0 0 0 0 Contract Energy Revenues $ 0 0 0 0 0 Contract VOM Hourly Revenues $ 0 0 0 0 0 Start-Up Charges Revenues $ 0 0 0 0 0 Net Forward Revenue $ 0 0 0 0 0 Heat Rate Adjustment Payment $ 0 0 0 0 0 Purchase Power Fuel Adjustment Payment $ 0 0 0 0 0 Other Electricity Revenues Other Capacity Revenues $ 87,048 86,295 90,457 90,525 91,915 Other Energy Revenues $184,852 180,562 169,056 169,198 164,747 -------- ------- ------- ------- ------- Total Operating Revenues $271,900 266,857 259,513 259,723 256,662 OPERATING EXPENSES ($000)(16) Fuel Costs $144,260 139,150 131,512 133,474 129,954 Emissions Allowances $ ( 45) (50) (75) (90) (109) Purchased Power $ 0 0 0 0 0 Operating and Maintenance $ 11,664 11,673 11,504 11,652 11,703 Major Maintenance $ 12,640 12,249 11,800 12,145 11,724 Administrative and General $ 9,551 9,663 9,778 9,896 10,019 Other $ 62 62 62 62 62 -------- ------- ------- ------- ------- Total Operating Expenses $178,132 172,747 164,582 167,140 163,353 NET OPERATING REVENUES ($000) $ 93,768 94,110 94,931 92,583 93,309 Year Ending December 31, 2018 2019 2020 2021 2022 - ------------------------ ------- ------- ------- ------- ------- GOAT ROCK FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 1,159 1,159 1,159 1,159 1,159 Average Annual Contract Capacity (MW) 0 0 0 0 0 Average Annual Other Capacity (MW) 1,159 1,159 1,159 1,159 1,159 Capacity Factor (%)(3) 25.9% 24.7% 23.3% 22.0% 22.0% Energy Generation (GWh) 2,626 2,510 2,364 2,233 2,233 Contract Energy Sales (GWh) 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 2,626 2,510 2,364 2,233 2,233 Net Heat Rate (Btu/kWh)(5) 7,902 7,904 7,976 7,999 7,999 Contract Fuel Consumption (BBtu) 0 0 0 0 0 Other Fuel Consumption (BBtu) 20,749 19,840 18,854 17,864 17,864 SO(2) Allowances Purchased (Tons)(6) 10 10 9 9 9 NO(x) Allowances Purchased (Tons)(7) (48) (48) (54) (54) (54) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) 0.00 0.00 0.00 0.00 0.00 Contract Energy ($/MWh) 0.00 0.00 0.00 0.00 0.00 Start Up Charge ($/Start) 0 0 0 0 0 Forward Net Revenue ($000) 0 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) 83.30 85.08 87.42 89.12 91.53 Other Energy ($/MWh) 63.07 65.87 68.47 70.65 72.56 Fuel ($/MMBtu)(12) 5.26 5.41 5.71 5.85 6.00 SO(2) Allowances ($/Ton)(13) 236 242 249 256 262 NO(x) Allowances ($/Ton)(14) 2,413 2,478 2,545 2,614 2,684 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues 0 0 0 0 0 Contract Energy Revenues 0 0 0 0 0 Contract VOM Hourly Revenues 0 0 0 0 0 Start-Up Charges Revenues 0 0 0 0 0 Net Forward Revenue 0 0 0 0 0 Heat Rate Adjustment Payment 0 0 0 0 Purchase Power Fuel Adjustment Payment 0 0 0 0 0 Other Electricity Revenues Other Capacity Revenues 96,523 98,577 101,297 103,265 106,056 Other Energy Revenues 165,613 165,345 161,861 157,796 162,056 ------- ------- ------- ------- ------- Total Operating Revenues 262,136 263,922 263,158 261,061 268,112 OPERATING EXPENSES ($000)(16) Fuel Costs 127,866 125,097 125,325 122,136 124,957 Emissions Allowances (113) (117) (137) (139) (143) Purchased Power 0 0 0 0 0 Operating and Maintenance 11,903 12,067 12,185 12,322 12,655 Major Maintenance 11,691 11,595 11,348 11,168 11,469 Administrative and General 10,145 10,272 10,405 10,541 10,679 Other 62 62 62 62 62 ------- ------- ------- ------- ------- Total Operating Expenses 161,554 158,976 159,188 156,090 159,679 NET OPERATING REVENUES ($000) 100,582 104,946 103,970 104,971 108,433
A-51 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2002(1) 2003 2004 2005 2006 2007 - ------------------------ ------- ------ ------- ------- ------- ------- HARRIS FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 0 1,191 1,191 1,191 1,191 1,191 Average Annual Contract Capacity (MW) 0 595 1,191 1,191 1,191 1,191 Average Annual Other Capacity (MW) 0 595 595 0 0 0 Capacity Factor (%)(3) 0.0% 24.9% 23.0% 32.3% 39.8% 42.7% Energy Generation (GWh) 0 1,513 2,403 3,372 4,152 4,458 Contract Energy Sales (GWh) 0 806 2,091 3,450 4,248 4,561 Other Energy Sales (Purchases)(GWh) 0 723 339 0 0 0 Net Heat Rate (Btu/kWh)(5) 0 7,994 7,889 7,807 7,701 7,637 Contract Fuel Consumption (BBtu) 0 6,321 16,289 26,329 31,973 34,041 Other Fuel Consumption (BBtu) 0 5,775 2,672 0 0 0 SO(2) Allowances Purchased (Tons)(6) 0 6 9 13 16 17 NO(x) Allowances Purchased (Tons)(7) 0 0 (52) (37) (22) (15) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) $0.00 106.70 74.70 85.77 85.77 85.77 Contract Energy ($/MWh) $0.00 5.96 7.18 8.33 7.47 6.96 Start Up Charge ($/Start) $ 0 8,243 23,750 39,634 40,089 39,376 Forward Net Revenue ($000) $ 0 0 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) $0.00 11.17 5.33 0.00 0.00 0.00 Other Energy ($/MWh) $0.00 43.70 42.94 0.00 0.00 0.00 Fuel ($/MMBtu)(12) $0.00 3.58 3.52 0.00 0.00 0.00 SO(2) Allowances ($/Ton)(13) $ 154 158 162 167 171 176 NO(x) Allowances ($/Ton)(14) $ 0 0 2,006 1,707 1,753 1,800 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues $ 0 37,060 88,957 102,138 102,138 102,138 Contract Energy Revenues $ 0 2,364 6,254 10,577 13,369 14,743 Contract VOM Hourly Revenues $ 0 0 0 0 0 0 Start-Up Charges Revenues $ 0 1,967 8,031 16,222 16,299 14,772 Heat Rate Adjustment Payment $ 0 0 0 0 0 0 Purchase Power Fuel Adjustment Payment $ 0 469 737 1,941 2,075 2,231 Other Electricity Revenues Other Capacity Revenues $ 0 6,651 3,175 0 0 0 Other Energy Revenues $ 0 31,618 14,536 0 0 0 ----- ------ ------- ------- ------- ------- Total Operating Revenues $ 0 80,129 121,690 130,878 133,881 133,884 OPERATING EXPENSES ($000)(16) Fuel Costs $ 0 28,273 12,714 0 0 0 Emissions Allowances $ 0 0 (104) (63) (38) (27) Purchased Power $ 0 689 1,104 3,256 3,995 4,434 Operating and Maintenance $ 0 5,088 8,769 9,996 11,080 11,708 Major Maintenance $ 0 4,116 7,012 9,392 11,444 12,485 Administrative and General $ 0 4,066 7,062 7,155 7,252 7,350 Other $ 0 36 62 62 62 62 ----- ------ ------- ------- ------- ------- Total Operating Expenses $ 0 42,268 36,618 29,798 33,795 36,012 NET OPERATING REVENUES ($000) $ 0 37,861 85,072 101,080 100,086 97,872 Year Ending December 31, 2008 2009 2010 2011 2012 - ------------------------ ------- ------- ------- ------- ------- HARRIS FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 1,191 1,191 1,191 1,191 1,191 Average Annual Contract Capacity (MW) 1,191 1,191 1,191 595 595 Average Annual Other Capacity (MW) 0 0 595 595 595 Capacity Factor (%)(3) 40.0% 40.6% 41.1% 40.0% 39.1% Energy Generation (GWh) 4,174 4,234 4,286 4,175 4,079 Contract Energy Sales (GWh) 4,270 4,332 2,834 2,132 2,097 Other Energy Sales (Purchases)(GWh) 0 0 1,505 2,097 2,035 Net Heat Rate (Btu/kWh)(5) 7,701 7,674 7,681 7,722 7,727 Contract Fuel Consumption (BBtu) 32,144 32,488 21,440 16,063 15,810 Other Fuel Consumption (BBtu) 0 0 11,480 16,175 15,707 SO(2) Allowances Purchased (Tons)(6) 16 16 16 16 16 NO(x) Allowances Purchased (Tons)(7) (18) (21) (20) (22) (22) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) 85.77 85.77 54.65 88.55 88.55 Contract Energy ($/MWh) 8.06 7.62 7.88 9.05 9.35 Start Up Charge ($/Start) 43,097 41,986 28,113 24,524 25,154 Forward Net Revenue ($000) 0 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) 0.00 0.00 41.66 66.92 71.14 Other Energy ($/MWh) 0.00 0.00 46.19 48.27 49.14 Fuel ($/MMBtu)(12) 0.00 0.00 3.94 4.07 4.20 SO(2) Allowances ($/Ton)(13) 181 186 191 196 201 NO(x) Allowances ($/Ton)(14) 1,849 1,899 1,950 2,002 2,057 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues 102,138 102,138 65,078 52,725 52,725 Contract Energy Revenues 14,177 14,767 9,876 7,591 7,668 Contract VOM Hourly Revenues 0 0 0 0 0 Start-Up Charges Revenues 18,009 15,919 11,402 10,598 10,805 Heat Rate Adjustment Payment 0 0 0 0 0 Purchase Power Fuel Adjustment Payment 2,243 2,323 1,070 1,103 1,140 Other Electricity Revenues Other Capacity Revenues 0 0 24,802 39,843 42,359 Other Energy Revenues 0 0 69,497 101,212 99,979 ------- ------- ------- ------- ------- Total Operating Revenues 136,567 135,147 181,725 213,072 214,676 OPERATING EXPENSES ($000)(16) Fuel Costs 0 0 52,219 76,505 76,796 Emissions Allowances (34) (39) (39) (43) (43) Purchased Power 4,284 4,565 2,501 2,587 2,597 Operating and Maintenance 11,710 12,095 12,483 12,687 12,912 Major Maintenance 12,136 12,500 13,064 13,014 13,133 Administrative and General 7,451 7,556 7,664 7,773 7,887 Other 62 62 62 62 62 ------- ------- ------- ------- ------- Total Operating Expenses 35,610 36,739 87,953 112,585 113,344 NET OPERATING REVENUES ($000) 100,957 98,408 93,772 100,487 101,332
A-52 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2013 2014 2015 2016 2017 - ------------------------ -------- ------- ------- ------- ------- HARRIS FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 1,191 1,191 1,191 1,191 1,191 Average Annual Contract Capacity (MW) 595 595 595 595 595 Average Annual Other Capacity (MW) 595 595 595 595 595 Capacity Factor (%)(3) 35.4% 32.0% 28.9% 27.3% 25.5% Energy Generation (GWh) 3,696 3,336 3,011 2,851 2,656 Contract Energy Sales (GWh) 1,813 1,680 1,494 1,432 1,296 Other Energy Sales (Purchases)(GWh) 1,929 1,698 1,555 1,456 1,392 Net Heat Rate (Btu/kWh)(5) 7,836 7,868 7,964 7,970 8,048 Contract Fuel Consumption (BBtu) 13,902 12,881 11,634 11,163 10,168 Other Fuel Consumption (BBtu) 15,058 13,368 12,346 11,563 11,203 SO(2) Allowances Purchased (Tons)(6) 14 13 12 11 11 NO(x) Allowances Purchased (Tons)(7) (29) (38) (47) (49) (52) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) $ 88.55 88.55 88.55 88.55 88.55 Contract Energy ($/MWh) $ 11.10 11.02 12.47 12.98 13.20 Start Up Charge ($/Start) $ 26,059 25,095 26,077 27,687 24,980 Forward Net Revenue ($000) $ 0 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) $ 75.13 74.48 78.07 78.13 79.33 Other Energy ($/MWh) $ 50.36 53.92 55.69 58.28 61.89 Fuel ($/MMBtu)(12) $ 4.33 4.46 4.62 4.81 5.01 SO(2) Allowances ($/Ton)(13) $ 207 212 218 224 230 NO(x) Allowances ($/Ton)(14) $ 2,112 2,169 2,228 2,288 2,350 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues $ 52,725 52,725 52,725 52,725 52,725 Contract Energy Revenues $ 6,809 6,482 5,918 5,825 5,417 Contract VOM Hourly Revenues $ 0 0 0 0 0 Start-Up Charges Revenues $ 12,144 10,820 11,466 11,455 10,345 Heat Rate Adjustment Payment $ 0 0 0 0 0 Purchase Power Fuel Adjustment Payment $ 1,173 1,216 1,244 1,303 1,349 Other Electricity Revenues Other Capacity Revenues $ 44,730 44,343 46,482 46,517 47,231 Other Energy Revenues $ 97,128 91,551 86,585 84,835 86,143 -------- ------- ------- ------- ------- Total Operating Revenues $214,709 207,137 204,420 202,660 203,210 OPERATING EXPENSES ($000)(16) Fuel Costs $ 76,321 70,936 68,599 67,375 68,128 Emissions Allowances $ (59) (81) (103) (111) (122) Purchased Power $ 2,341 2,278 2,133 2,117 2,044 Operating and Maintenance $ 12,778 12,656 12,567 12,686 12,754 Major Maintenance $ 12,539 11,732 11,053 11,340 11,366 Administrative and General $ 8,003 8,122 8,243 8,370 8,499 Other $ 62 62 62 62 62 -------- ------- ------- ------- ------- Total Operating Expenses $111,984 105,705 102,553 101,839 102,732 NET OPERATING REVENUES ($000) $102,725 101,432 101,867 100,821 100,478 Year Ending December 31, 2018 2019 2020 2021 2022 - ------------------------ ------- ------- ------- ------- ------- HARRIS FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 1,191 1,191 1,191 1,191 1,191 Average Annual Contract Capacity (MW) 595 595 0 0 0 Average Annual Other Capacity (MW) 595 1,191 1,191 1,191 1,191 Capacity Factor (%)(3) 25.2% 24.2% 24.5% 21.7% 21.7% Energy Generation (GWh) 2,628 2,521 2,553 2,264 2,264 Contract Energy Sales (GWh) 1,291 393 0 0 0 Other Energy Sales (Purchases)(GWh) 1,370 2,128 2,553 2,264 2,264 Net Heat Rate (Btu/kWh)(5) 8,045 8,052 8,103 8,181 8,181 Contract Fuel Consumption (BBtu) 10,160 3,162 0 0 0 Other Fuel Consumption (BBtu) 10,984 17,136 20,685 18,518 18,518 SO(2) Allowances Purchased (Tons)(6) 11 10 10 9 9 NO(x) Allowances Purchased (Tons)(7) (53) (56) (57) (60) (60) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) 88.55 53.13 0.00 0.00 0.00 Contract Energy ($/MWh) 14.50 9.07 0.00 0.00 0.00 Start Up Charge ($/Start) 28,172 4,634 0 0 0 Forward Net Revenue ($000) 0 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) 83.30 71.61 87.42 89.12 91.53 Other Energy ($/MWh) 63.63 66.52 69.44 71.50 73.43 Fuel ($/MMBtu)(12) 5.28 5.49 5.73 5.84 6.00 SO(2) Allowances ($/Ton)(13) 236 242 249 256 262 NO(x) Allowances ($/Ton)(14) 2,413 2,478 2,545 2,614 2,684 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues 52,725 13,181 0 0 0 Contract Energy Revenues 5,540 1,734 0 0 0 Contract VOM Hourly Revenues 0 0 0 0 0 Start-Up Charges Revenues 11,756 1,835 0 0 0 Heat Rate Adjustment Payment 0 0 0 0 Purchase Power Fuel Adjustment Payment 1,426 0 0 0 0 Other Electricity Revenues Other Capacity Revenues 49,599 85,268 104,104 106,126 108,994 Other Energy Revenues 87,154 141,522 177,276 161,847 166,217 ------- ------- ------- ------- ------- Total Operating Revenues 208,200 243,540 281,380 267,973 275,211 OPERATING EXPENSES ($000)(16) Fuel Costs 68,423 109,565 137,165 126,738 129,657 Emissions Allowances (126) (138) (143) (155) (159) Purchased Power 2,089 0 0 0 0 Operating and Maintenance 13,060 13,254 13,659 13,576 13,944 Major Maintenance 11,404 11,419 11,837 10,978 11,274 Administrative and General 8,631 8,767 8,907 9,051 9,200 Other 62 62 62 62 62 ------- ------- ------- ------- ------- Total Operating Expenses 103,543 142,930 171,486 160,250 163,978 NET OPERATING REVENUES ($000) 104,657 100,610 109,894 107,723 111,233
A-53 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2002(1) 2003 2004 2005 2006 2007 - ------------------------ ------- ----- ------ ------ ------ ------ STANTON FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 0 404 404 404 404 404 Average Annual Contract Capacity (MW) 0 404 404 404 404 404 Average Annual Other Capacity (MW) 0 0 0 0 0 0 Capacity Factor (%)(3) 0.0% 30.4% 56.5% 43.8% 43.6% 42.9% Energy Generation (GWh) 0 268 1,997 1,549 1,540 1,518 Contract Energy Sales (GWh) 0 274 2,087 1,619 1,610 1,586 Other Energy Sales (Purchases)(GWh) 0 0 0 0 0 0 Net Heat Rate (Btu/kWh)(5) 0 7,915 7,375 7,706 7,741 7,763 Contract Fuel Consumption (BBtu) 0 2,125 14,727 11,937 11,925 11,786 Other Fuel Consumption (BBtu) 0 0 0 0 0 0 SO(2) Allowances Purchased (Tons)(6) 0 1 7 6 6 6 NO(x) Allowances Purchased (Tons)(7) 0 0 0 0 0 0 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) $0.00 79.70 79.70 79.70 79.70 79.70 Contract Energy ($/MWh) $0.00 7.03 5.24 7.52 7.81 8.10 Start Up Charge ($/Start) $ 0 0 5,357 11,178 11,718 12,032 Other Electricity Other Capacity ($/kW-yr) $0.00 0.00 0.00 0.00 0.00 0.00 Other Energy ($/MWh) $0.00 0.00 0.00 0.00 0.00 0.00 Fuel ($/MMBtu)(12) $0.00 0.00 0.00 0.00 0.00 0.00 SO(2) Allowances ($/Ton)(13) $ 154 158 162 167 171 176 NO(x) Allowances ($/Ton)(14) $ 0 0 2,006 1,707 1,753 1,800 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues $ 0 8,043 32,170 32,170 32,170 32,170 Contract Energy Revenues $ 0 200 1,564 1,246 1,273 1,288 Contract VOM Hourly Revenues $ 0 1,539 6,223 6,396 6,560 6,721 Start-Up Charges Revenues $ 0 0 619 2,510 2,737 2,808 Heat Rate Adjustment Payment $ 0 0 0 0 0 0 Purchase Power Fuel Adjustment Payment $ 0 188 2,522 2,021 1,994 2,033 Other Electricity Revenues Other Capacity Revenues $ 0 0 0 0 0 0 Other Energy Revenues $ 0 0 0 0 0 0 ----- ----- ------ ------ ------ ------ Total Operating Revenues $ 0 9,970 43,098 44,343 44,734 45,020 OPERATING EXPENSES ($000)(16) Fuel Costs $ 0 0 0 0 0 0 Emissions Allowances $ 0 0 0 0 0 0 Purchased Power $ 0 245 3,694 3,072 3,093 3,203 Operating and Maintenance $ 0 909 4,495 4,238 4,345 4,443 Major Maintenance $ 0 589 4,326 3,513 3,569 3,605 Administrative and General $ 0 583 2,362 2,393 2,424 2,457 Other $ 0 5 20 20 20 20 ----- ----- ------ ------ ------ ------ Total Operating Expenses $ 0 2,331 14,897 13,236 13,451 13,728 NET OPERATING REVENUES ($000) $ 0 7,639 28,201 31,107 31,284 31,292 Year Ending December 31, 2008 2009 2010 2011 2012 - ------------------------ ------ ------ ------ ------ ------ STANTON FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 404 404 404 404 404 Average Annual Contract Capacity (MW) 404 404 404 404 404 Average Annual Other Capacity (MW) 0 0 0 0 0 Capacity Factor (%)(3) 41.1% 37.4% 35.6% 34.4% 32.9% Energy Generation (GWh) 1,455 1,323 1,260 1,216 1,165 Contract Energy Sales (GWh) 1,520 1,382 1,317 1,271 1,217 Other Energy Sales (Purchases)(GWh) 0 0 0 0 0 Net Heat Rate (Btu/kWh)(5) 7,800 7,919 7,979 7,989 8,047 Contract Fuel Consumption (BBtu) 11,348 10,475 10,056 9,716 9,374 Other Fuel Consumption (BBtu) 0 0 0 0 0 SO(2) Allowances Purchased (Tons)(6) 6 5 5 5 5 NO(x) Allowances Purchased (Tons)(7) 0 0 0 0 0 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) 79.70 79.70 79.70 79.70 79.70 Contract Energy ($/MWh) 8.73 9.95 10.68 11.17 11.94 Start Up Charge ($/Start) 12,583 13,350 13,811 14,080 14,443 Other Electricity Other Capacity ($/kW-yr) 0.00 0.00 0.00 0.00 0.00 Other Energy ($/MWh) 0.00 0.00 0.00 0.00 0.00 Fuel ($/MMBtu)(12) 0.00 0.00 0.00 0.00 0.00 SO(2) Allowances ($/Ton)(13) 181 186 191 196 201 NO(x) Allowances ($/Ton)(14) 1,849 1,899 1,950 2,002 2,057 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues 32,170 32,170 32,170 32,170 32,170 Contract Energy Revenues 1,268 1,184 1,159 1,148 1,129 Contract VOM Hourly Revenues 6,929 7,157 7,313 7,469 7,755 Start-Up Charges Revenues 3,047 3,471 3,652 3,661 3,745 Heat Rate Adjustment Payment 0 0 0 0 0 Purchase Power Fuel Adjustment Payment 2,036 1,940 1,938 1,913 1,902 Other Electricity Revenues Other Capacity Revenues 0 0 0 0 0 Other Energy Revenues 0 0 0 0 0 ------ ------ ------ ------ ------ Total Operating Revenues 45,450 45,922 46,232 46,361 46,701 OPERATING EXPENSES ($000)(16) Fuel Costs 0 0 0 0 0 Emissions Allowances 0 0 0 0 0 Purchased Power 3,175 3,071 3,045 3,001 2,988 Operating and Maintenance 4,504 4,502 4,563 4,642 4,716 Major Maintenance 3,572 3,313 3,258 3,240 3,210 Administrative and General 2,491 2,524 2,559 2,595 2,632 Other 20 20 20 20 20 ------ ------ ------ ------ ------ Total Operating Expenses 13,762 13,430 13,445 13,498 13,566 NET OPERATING REVENUES ($000) 31,688 32,492 32,787 32,863 33,135
A-54 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2013 2014 2015 2016 2017 - ------------------------ ------- ------ ------ ------ ------- STANTON FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 404 394 394 394 394 Average Annual Contract Capacity (MW) 404 0 0 0 0 Average Annual Other Capacity (MW) 394 394 394 394 394 Capacity Factor (%)(3) 32.1% 29.0% 28.7% 28.8% 30.7% Energy Generation (GWh) 1,137 1,001 990 992 1,060 Contract Energy Sales (GWh) 990 0 0 0 0 Other Energy Sales (Purchases)(GWh) 147 1,001 990 992 1,060 Net Heat Rate (Btu/kWh)(5) 8,022 8,105 8,144 8,122 8,077 Contract Fuel Consumption (BBtu) 7,940 0 0 0 0 Other Fuel Consumption (BBtu) 1,178 8,116 8,062 8,059 8,562 SO(2) Allowances Purchased (Tons)(6) 5 4 4 4 4 NO(x) Allowances Purchased (Tons)(7) 0 0 0 0 0 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) $ 79.70 0.00 0.00 0.00 0.00 Contract Energy ($/MWh) $ 13.41 0.00 0.00 0.00 0.00 Start Up Charge ($/Start) $11,084 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) $ 8.17 74.53 77.15 80.13 81.42 Other Energy ($/MWh) $ 57.44 60.00 62.00 63.93 66.53 Fuel ($/MMBtu)(12) $ 4.63 4.77 4.90 5.17 5.35 SO(2) Allowances ($/Ton)(13) $ 207 212 218 224 230 NO(x) Allowances ($/Ton)(14) $ 2,112 2,169 2,228 2,288 2,350 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues $26,809 0 0 0 0 Contract Energy Revenues $ 943 0 0 0 0 Contract VOM Hourly Revenues $ 9,547 0 0 0 0 Start-Up Charges Revenues $ 2,787 0 0 0 0 Heat Rate Adjustment Payment $ 0 0 0 0 0 Purchase Power Fuel Adjustment Payment $ 0 0 0 0 0 Other Electricity Revenues Other Capacity Revenues $ 3,218 29,363 30,396 31,570 32,078 Other Energy Revenues $ 8,435 60,076 61,379 63,435 70,527 ------- ------ ------ ------ ------- Total Operating Revenues $51,739 89,439 91,775 95,005 102,605 OPERATING EXPENSES ($000)(16) Fuel Costs $ 7,449 54,155 54,935 57,058 61,212 Emissions Allowances $ 0 1 1 1 1 Purchased Power $ 0 0 0 0 0 Operating and Maintenance $ 4,813 4,798 4,914 5,050 5,266 Major Maintenance $ 3,248 3,065 3,083 3,459 3,772 Administrative and General $ 2,670 2,710 2,749 2,790 2,833 Other $ 20 20 20 20 20 ------- ------ ------ ------ ------- Total Operating Expenses $18,200 64,749 65,702 68,378 73,104 NET OPERATING REVENUES ($000) $33,539 24,690 26,073 26,627 29,501 Year Ending December 31, 2018 2019 2020 2021 2022 - ------------------------ ------- ------- ------- ------- ------- STANTON FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 394 394 394 394 394 Average Annual Contract Capacity (MW) 0 0 0 0 0 Average Annual Other Capacity (MW) 394 394 394 394 394 Capacity Factor(%)(3) 28.6% 29.1% 29.2% 27.1% 27.1% Energy Generation (GWh) 988 1,004 1,008 934 934 Contract Energy Sales (GWh) 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 988 1,004 1,008 934 934 Net Heat Rate (Btu/kWh)(5) 8,147 8,164 8,178 8,181 8,181 Contract Fuel Consumption (BBtu) 0 0 0 0 0 Other Fuel Consumption (BBtu) 8,048 8,193 8,243 7,637 7,637 SO(2) Allowances Purchased (Tons)(6) 4 4 4 4 4 NO(x) Allowances Purchased (Tons)(7) 0 0 0 0 0 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Electricity Contract Capacity ($/kW-yr)(9) 0.00 0.00 0.00 0.00 0.00 Contract Energy ($/MWh) 0.00 0.00 0.00 0.00 0.00 Start Up Charge ($/Start) 0 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) 86.92 90.35 92.67 96.23 98.83 Other Energy ($/MWh) 68.31 71.57 73.67 75.74 77.78 Fuel ($/MMBtu)(12) 5.57 5.81 6.07 6.23 6.40 SO(2) Allowances ($/Ton)(13) 236 242 249 256 262 NO(x) Allowances ($/Ton)(14) 2,413 2,478 2,545 2,614 2,684 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues 0 0 0 0 0 Contract Energy Revenues 0 0 0 0 0 Contract VOM Hourly Revenues 0 0 0 0 0 Start-Up Charges Revenues 0 0 0 0 0 Heat Rate Adjustment Payment 0 0 0 0 Purchase Power Fuel Adjustment Payment 0 0 0 0 0 Other Electricity Revenues Other Capacity Revenues 34,246 35,597 36,512 37,914 38,938 Other Energy Revenues 67,485 71,824 74,251 70,706 72,615 ------- ------- ------- ------- ------- Total Operating Revenues 101,731 107,421 110,763 108,620 111,553 OPERATING EXPENSES ($000)(16) Fuel Costs 60,221 62,975 65,417 62,988 64,273 Emissions Allowances 1 1 1 1 1 Purchased Power 0 0 0 0 0 Operating and Maintenance 5,321 5,484 5,638 5,694 5,847 Major Maintenance 3,602 3,761 3,872 3,696 3,796 Administrative and General 2,877 2,921 2,967 3,013 3,062 Other 20 20 20 20 20 ------- ------- ------- ------- ------- Total Operating Expenses 72,042 75,162 77,915 75,412 76,999 NET OPERATING REVENUES ($000) 29,689 32,259 32,848 33,208 34,554
A-55 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2002(1) 2003 2004 2005 2006 2007 - ------------------------ ------- ------ ------ ------ ------ ------ WANSLEY FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 1,123 1,123 1,123 1,123 1,123 1,123 Average Annual Contract Capacity (MW) 1,123 1,123 1,123 1,123 1,123 1,123 Average Annual Other Capacity (MW) 0 0 0 0 0 0 Capacity Factor(%)(3) 52.6% 22.0% 16.9% 22.1% 30.9% 33.9% Energy Generation (GWh) 3,021 2,162 1,666 2,171 3,035 3,331 Contract Energy Sales (GWh) 3,098 2,217 1,709 2,227 3,113 3,417 Other Energy Sales (Purchases)(GWh) 0 0 0 0 0 0 Net Heat Rate (Btu/kWh)(5) 7,258 7,641 7,770 7,842 7,753 7,660 Contract Fuel Consumption (BBtu) 21,924 16,516 12,948 17,026 23,532 25,517 Other Fuel Consumption (BBtu) 0 0 0 0 0 0 SO(2) Allowances Purchased (Tons)(6) 11 8 6 9 12 13 NO(x) Allowances Purchased (Tons)(7) 0 0 0 83 98 102 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Capacity ($/kW-yr)(9) $ 84.66 66.17 66.25 66.34 66.43 66.52 Contract Energy ($/MWh) $ 3.76 5.43 5.75 6.36 6.23 5.92 Start Up Charge ($/Start) $14,096 17,768 17,513 19,477 20,666 20,989 Other Electricity Other Capacity ($/kW-yr) $ 0.00 0.00 0.00 0.00 0.00 0.00 Other Energy ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 0.00 Fuel ($/MMBtu)(12) $ 0.00 0.00 0.00 0.00 0.00 0.00 SO(2) Allowances ($/Ton)(13) $ 154 158 162 167 171 176 NO(x) Allowances ($/Ton)(14) $ 0 0 2,006 1,707 1,753 1,800 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues $55,460 74,307 74,403 74,502 74,603 74,707 Contract Energy Revenues $ 7,824 5,750 4,553 6,092 8,746 9,859 Contract VOM Hourly Revenues $ 0 0 0 0 0 0 Start-Up Charges Revenues $ 2,117 4,899 4,087 6,533 8,550 8,033 Heat Rate Adjustment Payment $ 0 0 0 0 0 0 Purchase Power Fuel Adjustment Payment $ 1,697 1,397 1,182 1,532 2,106 2,346 Other Electricity Revenues Other Capacity Revenues $ 0 0 0 0 0 0 Other Energy Revenues $ 0 0 0 0 0 0 ------- ------ ------ ------ ------ ------ Total Operating Revenues $67,098 86,353 84,225 88,659 94,005 94,945 OPERATING EXPENSES ($000)(16) Fuel Costs $ 0 0 0 0 0 0 Emissions Allowances $ 0 0 0 0 0 0 Purchased Power $ 2,701 2,071 1,960 2,555 3,488 3,895 Operating and Maintenance $ 6,441 7,420 6,958 7,839 9,267 9,945 Major Maintenance $ 7,181 6,594 5,521 6,858 9,067 10,153 Administrative and General $ 1,911 3,354 3,436 3,520 3,607 3,697 Other $ 36 63 63 63 63 63 ------- ------ ------ ------ ------ ------ Total Operating Expenses $18,270 19,502 17,938 20,835 25,492 27,753 NET OPERATING REVENUES ($000) $48,828 66,851 66,287 67,824 68,513 67,192 Year Ending December 31, 2008 2009 2010 2011 2012 - ------------------------ ------ ------ ------- ------- ------- WANSLEY FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 1,123 1,123 1,123 1,123 1,123 Average Annual Contract Capacity (MW) 1,123 1,123 1,123 0 0 Average Annual Other Capacity (MW) 0 0 1,123 1,123 1,123 Capacity Factor(%)(3) 31.6% 34.0% 32.4% 30.9% 28.6% Energy Generation (GWh) 3,106 3,345 3,187 3,044 2,811 Contract Energy Sales (GWh) 3,186 3,431 (0) 0 0 Other Energy Sales (Purchases)(GWh) 0 0 3,187 3,044 2,811 Net Heat Rate (Btu/kWh)(5) 7,733 7,703 7,772 7,740 7,794 Contract Fuel Consumption (BBtu) 24,017 25,762 0 0 0 Other Fuel Consumption (BBtu) 0 0 24,767 23,559 21,909 SO(2) Allowances Purchased (Tons)(6) 12 13 12 12 11 NO(x) Allowances Purchased (Tons)(7) 98 96 96 95 91 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity ($/kW-yr)(9) 66.62 66.72 0.00 0.00 0.00 Contract Energy ($/MWh) 6.41 6.55 0.00 0.00 0.00 Start Up Charge ($/Start) 21,701 22,444 0 0 0 Other Electricity Other Capacity ($/kW-yr) 0.00 0.00 60.96 66.92 71.14 Other Energy ($/MWh) 0.00 0.00 49.13 51.21 53.81 Fuel ($/MMBtu)(12) 0.00 0.00 3.95 4.09 4.25 SO(2) Allowances ($/Ton)(13) 181 186 191 196 201 NO(x) Allowances ($/Ton)(14) 1,849 1,899 1,950 2,002 2,057 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues 74,814 74,924 0 0 0 Contract Energy Revenues 9,439 10,440 0 0 0 Contract VOM Hourly Revenues 0 0 0 0 0 Start-Up Charges Revenues 8,696 9,465 0 0 0 Heat Rate Adjustment Payment 0 0 0 0 0 Purchase Power Fuel Adjustment Payment 2,288 2,552 0 0 0 Other Electricity Revenues Other Capacity Revenues 0 0 68,457 75,148 79,894 Other Energy Revenues 0 0 156,572 155,883 151,274 ------ ------ ------- ------- ------- Total Operating Revenues 95,237 97,381 225,029 231,031 231,168 OPERATING EXPENSES ($000)(16) Fuel Costs 0 0 117,408 115,791 112,603 Emissions Allowances 0 0 189 193 188 Purchased Power 3,740 4,179 0 0 0 Operating and Maintenance 9,878 10,510 10,546 10,601 10,503 Major Maintenance 9,872 10,678 11,358 11,201 10,678 Administrative and General 3,789 3,883 3,980 4,079 4,181 Other 63 63 63 63 63 ------ ------ ------- ------- ------- Total Operating Expenses 27,342 29,313 143,544 141,928 138,217 NET OPERATING REVENUES ($000) 67,895 68,068 81,485 89,103 92,951
A-56 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2013 2014 2015 2016 2017 - ------------------------ -------- ------- ------- ------- ------- WANSLEY FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 1,123 1,123 1,123 1,123 1,123 Average Annual Contract Capacity (MW) 0 0 0 0 0 Average Annual Other Capacity (MW) 1,123 1,123 1,123 1,123 1,123 Capacity Factor (%)(3) 24.5% 22.3% 20.9% 21.4% 20.1% Energy Generation (GWh) 2,411 2,193 2,052 2,101 1,977 Contract Energy Sales (GWh) 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 2,411 2,193 2,052 2,101 1,977 Net Heat Rate (Btu/kWh)(5) 7,803 7,857 7,890 7,895 7,893 Contract Fuel Consumption (BBtu) 0 0 0 0 0 Other Fuel Consumption (BBtu) 18,812 17,229 16,192 16,591 15,601 SO(2) Allowances Purchased (Tons)(6) 9 9 8 8 8 NO(x) Allowances Purchased (Tons)(7) 85 83 76 74 71 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity ($/kW-yr)(9) $ 0.00 0.00 0.00 0.00 0.00 Contract Energy ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 Start Up Charge ($/Start) $ 0 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) $ 75.13 74.48 78.07 78.13 79.33 Other Energy ($/MWh) $ 55.80 58.62 60.04 61.30 65.24 Fuel ($/MMBtu)(12) $ 4.34 4.47 4.55 4.81 5.00 SO(2) Allowances ($/Ton)(13) $ 207 212 218 224 230 NO(x) Allowances ($/Ton)(14) $ 2,112 2,169 2,228 2,288 2,350 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues $ 0 0 0 0 0 Contract Energy Revenues $ 0 0 0 0 0 Contract VOM Hourly Revenues $ 0 0 0 0 0 Start-Up Charges Revenues $ 0 0 0 0 0 Heat Rate Adjustment Payment $ 0 0 0 0 0 Purchase Power Fuel Adjustment Payment $ 0 0 0 0 0 Other Electricity Revenues Other Capacity Revenues $ 84,366 83,637 87,670 87,736 89,083 Other Energy Revenues $134,516 128,553 123,226 128,824 128,949 -------- ------- ------- ------- ------- Total Operating Revenues $218,882 212,190 210,896 216,560 218,032 OPERATING EXPENSES ($000)(16) Fuel Costs $101,122 96,568 92,806 96,861 93,865 Emissions Allowances $ 181 182 171 171 170 Purchased Power $ 0 0 0 0 0 Operating and Maintenance $ 10,108 10,000 10,019 10,379 10,424 Major Maintenance $ 9,807 9,357 9,302 9,777 9,710 Administrative and General $ 4,285 4,393 4,504 4,617 4,734 Other $ 63 63 63 63 63 -------- ------- ------- ------- ------- Total Operating Expenses $125,566 120,563 116,865 121,868 118,966 NET OPERATING REVENUES ($000) $ 93,316 91,627 94,031 94,692 99,066 Year Ending December 31, 2018 2019 2020 2021 2022 - ------------------------ ------- ------- ------- ------- ------- WANSLEY FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 1,123 1,123 1,123 1,123 1,123 Average Annual Contract Capacity (MW) 0 0 0 0 0 Average Annual Other Capacity (MW) 1,123 1,123 1,123 1,123 1,123 Capacity Factor(%)(3) 18.5% 16.2% 17.1% 15.7% 15.7% Energy Generation (GWh) 1,821 1,591 1,683 1,548 1,548 Contract Energy Sales (GWh) 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 1,821 1,591 1,683 1,548 1,548 Net Heat Rate (Btu/kWh)(5) 7,847 7,849 7,927 7,853 7,853 Contract Fuel Consumption (BBtu) 0 0 0 0 0 Other Fuel Consumption (BBtu) 14,292 12,484 13,338 12,159 12,159 SO(2) Allowances Purchased (Tons)(6) 7 6 7 6 6 NO(x) Allowances Purchased (Tons)(7) 69 65 65 60 60 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity ($/kW-yr)(9) 0.00 0.00 0.00 0.00 0.00 Contract Energy ($/MWh) 0.00 0.00 0.00 0.00 0.00 Start Up Charge ($/Start) 0 0 0 0 0 Other Electricity Other Capacity ($/kW-yr) 83.30 85.08 87.42 89.12 91.53 Other Energy ($/MWh) 66.49 71.48 72.90 74.05 76.05 Fuel ($/MMBtu)(12) 5.19 5.41 5.67 5.82 5.97 SO(2) Allowances ($/Ton)(13) 236 242 249 256 262 NO(x) Allowances ($/Ton)(14) 2,413 2,478 2,545 2,614 2,684 OPERATING REVENUES ($000) Contract Electricity Revenues Contract Capacity Revenues 0 0 0 0 0 Contract Energy Revenues 0 0 0 0 0 Contract VOM Hourly Revenues 0 0 0 0 0 Start-Up Charges Revenues 0 0 0 0 0 Heat Rate Adjustment Payment 0 0 0 0 Purchase Power Fuel Adjustment Payment 0 0 0 0 0 Other Electricity Revenues Other Capacity Revenues 93,549 95,540 98,176 100,083 102,788 Other Energy Revenues 121,106 113,692 122,667 114,658 117,753 ------- ------- ------- ------- ------- Total Operating Revenues 214,655 209,232 220,843 214,741 220,541 OPERATING EXPENSES ($000)(16) Fuel Costs 88,860 82,184 90,313 85,366 87,275 Emissions Allowances 169 163 167 158 162 Purchased Power 0 0 0 0 0 Operating and Maintenance 10,404 10,227 10,690 10,697 10,986 Major Maintenance 9,285 8,609 9,283 9,044 9,288 Administrative and General 4,854 4,977 5,103 5,233 5,366 Other 63 63 63 63 63 ------- ------- ------- ------- ------- Total Operating Expenses 113,635 106,223 115,619 110,561 113,140 NET OPERATING REVENUES ($000) 101,020 103,009 105,224 104,180 107,401
A-57 FOOTNOTES TO EXHIBIT A-1 1. Represents seven months for the year 2002. 2. Represents annual average capacity for the Generating Facilities. Includes allowance for degradation. Reflects the commercial operation of Goat Rock 2, the Harris Facility, and the Stanton Facility in 2003. 3. Represents annual weighted average capacity factors of the Generating Facilities as projected by PA Consulting. 4. Energy sales both contractual and market are as projected by PA Consulting. Market sales assumed to be representative of long-term contracts Southern Power expects to enter into upon expiration of the Power Purchase Agreements. 5. Weighted average annual heat rate calculated as the sum of total fuel consumed by the Generating Facilities divided by the energy generated by the Generating Facilities, as projected by PA Consulting. 6. SO(2) allowances that Southern Power will have to purchase or have the ability to sell based on emission rates as provided by Southern Power and dispatch as projected by PA Consulting. During the term of the Power Purchase Agreements, we have assumed that any shortfall in emissions would be provided by the buyer of the generation. Upon expiration of the Power Purchase Agreements, we have assumed that Southern Power will purchase any allowances required or sell any excess allowances. 7. NO(x) allowances that Southern Power will have to purchase or have the ability to sell based on emission rates as provided by Southern Power and dispatch as projected by PA Consulting. During the Power Purchase Agreement period we have assumed that any shortfall in emissions would be provided by the buyer of the generation. Upon expiration of the Power Purchase Agreements, we have assumed that Southern Power will purchase any allowances required or sell any excess allowances. 8. Rate of change in general inflation and various inflation related escalators assumed to be 2.7 percent per year for the term of the Notes, based on the March 10, 2002 projection prepared by Blue Chip Economic Indicators. 9. Average contract capacity price calculated as the sum of the capacity revenues under the Power Purchase Agreements divided by the total annual contractual capacity from the various Power Purchase Agreements. 10. Average contract energy price calculated as the sum of the energy revenues under the Power Purchase Agreements divided by the total energy sold under the various Power Purchase Agreements as projected by PA Consulting. 11. Average other capacity and energy price calculated as the sum of the other electricity revenues of the Generating Facilities divided by the total energy or capacity sold as projected by PA Consulting. Assumed to be equivalent to the price of long-term contracts to be entered into by Southern Power upon expiration of the Power Purchase Agreements. Shown as zero in years during which there are no other capacity or energy sales. 12. Weighted average of fuel prices for the Generating Facilities calculated as sum of the fuel expenses divided by the total fuel consumed by the Generating Facilities as projected by PA Consulting. Shown as zero in years during which there are no fuel purchases. 13. Assumed to be $150 per ton in 2001 dollars and assumed to escalate thereafter at the rate of inflation. 14. Assumed to be $1,000 per ton through 2002, $2,300 per ton in 2004, $1,700 per ton in 2005 and assumed to escalate thereafter at the rate of inflation. 15. Assumes contract sales to third parties in 2002 and 2003 as reported by Southern Power for the Goat Rock Facility prior to commencement of the Goat Rock Power Purchase Agreement and market energy sales as estimated by PA Consulting for Harris 2 prior to the commencement of the Harris 2 Power Purchase Agreement. 16. Non-fuel operating expenses as estimated by the Southern Power assumed to escalate at the rate of inflation. 17. Interest payments are based on semi-annual payments due each July 15 and January 15 beginning January 15, 2003, as estimated by the Representatives of the Initial Purchasers. Assumes monthly accrual of interest payments six months prior to due date. Interest payments shown represent the payments due July 15 of the calendar year shown and January 15 of the following calendar year. Assumes the issuance of additional Debt of $650,000,000 on June 1, 2003, at an interest rate of 8.0 percent per year. The scheduled amortization of the Notes consists of a single payment due on July 15, 2012. Southern Power has assumed that the Debt will be refinanced upon maturity at the same principal amounts and interest rates. No additional costs of issuance have been included. No principal amortization of the Debt has been assumed. 18. Interest coverage is equal to the net operating revenue divided by the interest on the Debt. 19. Average interest coverage is equal to the total net operating revenues over the term of the Notes ending July 15, 2012 divided by the total interest on the Debt over the same period. 20. Capacity shown in 2005 for the Dahlberg Facility reflects the expiration of the Dynegy Power Purchase Agreement on May 31. Full capacity of the Dahlberg Facility is available for other sales after May 31. A-58 EXHIBIT A-2 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY A - LOW FUEL MARKET PRICE SCENARIO
Year Ending December 31, 2002(1) 2003 2004 2005 2006 2007 - ------------------------ -------- ------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 2,489 4,678 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 55.8% 28.7% 33.6% 40.1% 47.1% 47.6% Contract Energy Sales (GWh)(4) 6,654 10,033 13,171 16,887 19,780 19,978 Other Energy Sales (GWh)(4) 426 1,840 895 8 49 43 -------- ------- ------- ------- ------- ------- Total Energy Sales (GWh) 7,080 11,872 14,066 16,895 19,829 20,021 Fuel Consumption (BBtu) 48,949 85,160 102,071 121,015 141,325 142,452 Average Net Heat Rate (Btu/kWh)(5) 6,894 7,242 7,403 7,358 7,318 7,306 SO(2) Allowances Purchased (Tons)(6) 24 43 52 60 70 70 NO(x) Allowances Purchased (Tons)(7) 0 0 (43) 127 183 188 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 51.53 60.50 70.74 73.59 77.20 77.23 Contract Energy Price ($/MWh)(10) $ 3.10 4.01 4.79 4.77 4.46 4.43 Other Capacity Price ($/MWh)(11) $ 16.90 16.74 16.95 16.27 17.40 20.22 Other Energy Price ($/MWh)(11) $ 29.57 32.62 32.88 60.45 53.24 53.63 Fuel Price ($/MMBtu)(12) $ 3.22 3.67 3.57 2.85 2.81 2.91 SO(2) Allowances ($/Ton)(13) $ 154 158 162 167 171 176 NO(x) Allowances ($/Ton)(14) $ 0 0 2,006 1,707 1,753 1,800 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 30,117 46,845 45,517 2,668 0 0 Goat Rock(15) $ 38,984 80,463 107,393 116,227 118,022 118,085 Harris(15) $ 0 41,914 104,968 126,879 128,473 127,664 Stanton $ 0 10,029 43,343 43,310 43,956 43,859 Wansley $ 69,806 92,857 89,193 93,295 96,939 98,239 Other Electricity Revenues Dahlberg $ 10 0 0 12,266 16,544 18,498 Goat Rock(15) $ 13,535 22,941 11,577 0 0 0 Harris $ 0 46,940 22,179 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 -------- ------- ------- ------- ------- ------- Total Operating Revenues $152,452 341,990 424,170 394,645 403,934 406,345 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 7 0 0 239 1,545 1,407 Goat Rock $ 9,640 16,587 8,390 0 0 0 Harris $ 0 33,446 15,522 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Emissions Allowances $ 0 1 (86) (1) 11 10 Purchased Power $ 3,650 4,771 9,468 14,888 17,416 18,229 Operations & Maintenance $ 12,487 26,074 33,823 37,825 42,422 43,811 Major Maintenance $ 16,248 29,777 36,218 43,115 50,438 53,464 Administration $ 3,022 7,866 10,457 10,739 11,029 11,328 Insurance $ 756 1,995 2,676 2,748 2,821 2,899 Property Taxes $ 3,566 10,113 13,679 13,706 13,734 13,762 Other $ 90 216 270 270 270 270 -------- ------- ------- ------- ------- ------- Total Operating Expenses $ 49,466 130,846 130,417 123,529 139,687 145,180 NET OPERATING REVENUES ($000) $102,986 211,144 293,754 271,116 264,247 261,165 ANNUAL INTEREST($000)(17) $ 20,964 66,271 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 4.91 3.19 3.34 3.08 3.00 2.97 2002-12 AVG INTEREST COVERAGE(19) 3.42 Year Ending December 31, 2008 2009 2010 2011 2012 - ---------------------------------------- ------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 45.7% 44.8% 45.2% 42.9% 41.7% Contract Energy Sales (GWh)(4) 19,187 18,763 9,932 5,402 4,288 Other Energy Sales (GWh)(4) 55 103 8,823 12,316 12,925 ------- ------- ------- ------- ------- Total Energy Sales (GWh) 19,242 18,866 18,755 17,717 17,213 Fuel Consumption (BBtu) 137,674 135,937 136,807 130,377 127,262 Average Net Heat Rate (Btu/kWh)(5) 7,346 7,396 7,385 7,417 7,451 SO(2) Allowances Purchased (Tons)(6) 69 69 68 66 64 NO(x) Allowances Purchased (Tons)(7) 176 163 164 150 144 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 77.26 77.28 40.00 60.62 84.98 Contract Energy Price ($/MWh)(10) 4.83 5.26 5.38 6.71 7.31 Other Capacity Price ($/MWh)(11) 48.96 54.17 61.15 66.19 71.22 Other Energy Price ($/MWh)(11) 53.81 56.29 37.62 38.91 39.68 Fuel Price ($/MMBtu)(12) 3.00 3.10 3.69 3.81 3.93 SO(2) Allowances ($/Ton)(13) 181 186 191 196 201 NO(x) Allowances ($/Ton)(14) 1,849 1,899 1,950 2,002 2,057 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Goat Rock(15) 120,302 121,512 79,462 18,281 0 Harris(15) 129,416 131,518 83,530 68,776 69,676 Stanton 44,058 44,845 45,454 45,805 46,548 Wansley 98,388 100,335 0 0 0 Other Electricity Revenues Dahlberg 42,196 49,216 55,928 62,132 66,648 Goat Rock(15) 0 0 95,330 245,977 297,375 Harris 0 0 99,269 149,395 151,073 Stanton 0 0 0 0 0 Wansley 0 0 247,563 252,733 259,759 ------- ------- ------- ------- ------- Total Operating Revenues 434,360 447,426 706,536 843,099 891,079 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 1,843 3,593 4,405 5,661 5,970 Goat Rock 0 0 52,173 132,787 159,422 Harris 0 0 54,490 80,149 81,079 Stanton 0 0 0 0 0 Wansley 0 0 130,130 128,010 130,842 Emissions Allowances 13 26 277 294 307 Purchased Power 18,159 18,426 8,839 5,808 5,748 Operations & Maintenance 44,120 45,351 46,897 47,236 47,931 Major Maintenance 53,178 53,874 55,849 60,515 57,737 Administration 11,633 11,946 12,270 12,599 12,942 Insurance 2,978 3,057 3,140 3,224 3,311 Property Taxes 13,792 13,822 13,853 13,885 13,918 Other 270 270 270 270 270 ------- ------- ------- ------- ------- Total Operating Expenses 145,986 150,365 382,592 490,439 519,478 NET OPERATING REVENUES ($000) 288,374 297,061 323,944 352,660 371,601 ANNUAL INTEREST($000)(17) 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 3.28 3.38 3.68 4.01 4.23 2002-12 AVG INTEREST COVERAGE(19)
A-59 EXHIBIT A-2 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY A - LOW FUEL MARKET PRICE SCENARIO
Year Ending December 31, 2013 2014 2015 2016 2017 - ------------------------ -------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 39.4% 36.4% 34.5% 32.3% 29.9% Contract Energy Sales (GWh)(4) 3,820 2,497 2,287 2,139 1,971 Other Energy Sales (GWh)(4) 12,381 12,445 11,880 11,110 10,292 -------- ------- ------- ------- ------- Total Energy Sales (GWh) 16,201 14,941 14,167 13,249 12,264 Fuel Consumption (BBtu) 120,386 111,785 106,688 100,312 93,404 Average Net Heat Rate (Btu/kWh)(5) 7,461 7,513 7,561 7,602 7,647 SO(2) Allowances Purchased (Tons)(6) 61 57 54 49 47 NO(x) Allowances Purchased (Tons)(7) 134 112 100 76 48 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 79.61 88.55 88.55 88.55 88.55 Contract Energy Price ($/MWh)(10) $ 7.64 7.35 7.86 7.59 8.28 Other Capacity Price ($/MWh)(11) $ 73.75 75.88 79.35 80.66 82.65 Other Energy Price ($/MWh)(11) $ 40.84 43.33 44.78 47.24 49.29 Fuel Price ($/MMBtu)(12) $ 4.08 4.36 4.51 4.73 4.93 SO(2) Allowances ($/Ton)(13) $ 207 212 218 224 230 NO(x) Allowances ($/Ton)(14) $ 2,112 2,169 2,228 2,288 2,350 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 Goat Rock (15) $ 0 0 0 0 0 Harris (15) $ 68,550 71,068 70,694 68,960 69,047 Stanton $ 40,171 0 0 0 0 Wansley $ 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 67,003 67,061 71,771 70,073 68,767 Goat Rock (15) $296,116 289,841 295,172 289,954 283,502 Harris $152,045 149,899 150,794 149,199 151,884 Stanton $ 11,784 92,099 93,448 96,381 102,511 Wansley $252,915 249,408 243,961 247,711 237,332 -------- ------- ------- ------- ------- Total Operating Revenues $888,584 919,376 925,840 922,278 913,043 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 4,971 3,774 4,986 3,366 1,676 Goat Rock $157,945 150,345 153,014 149,266 143,924 Harris $ 81,410 78,949 78,834 77,318 79,739 Stanton $ 7,304 54,076 54,571 56,368 59,818 Wansley $124,385 120,645 113,673 113,882 103,523 Emissions Allowances $ 290 253 230 184 121 Purchased Power $ 2,666 2,633 2,518 2,467 2,371 Operations & Maintenance $ 47,642 46,930 47,279 46,865 46,124 Major Maintenance $ 58,784 54,544 53,821 52,920 51,170 Administration $ 13,290 13,650 14,016 14,395 14,786 Insurance $ 3,400 3,493 3,587 3,684 3,784 Property Taxes $ 13,952 13,986 14,022 14,058 14,096 Other $ 270 270 270 270 270 -------- ------- ------- ------- ------- Total Operating Expenses $516,308 543,550 540,822 535,043 521,403 NET OPERATING REVENUES ($000) $372,276 375,826 385,018 387,235 391,640 ANNUAL INTEREST($000) (17) $ 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE (18) 4.23 4.27 4.38 4.40 4.45 2002-12 AVG INTEREST COVERAGE (19) 3.42 Year Ending December 31, 2018 2019 2020 2021 2022 - ------------------------ ------- ------- ------- ------- --------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,668 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 28.6% 27.0% 24.6% 22.7% 22.7% Contract Energy Sales (GWh)(4) 1,955 573 0 0 0 Other Energy Sales (GWh)(4) 9,787 10,452 10,043 9,266 9,266 ------- ------- ------- ------- --------- Total Energy Sales (GWh) 11,743 11,025 10,043 9,266 9,266 Fuel Consumption (BBtu) 89,772 85,213 78,895 72,968 72,968 Average Net Heat Rate (Btu/kWh)(5) 7,677 7,729 7,856 7,874 7,874 SO(2) Allowances Purchased (Tons)(6) 45 42 39 37 37 NO(x) Allowances Purchased (Tons)(7) 41 31 (1) (9) (9) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 88.55 22.14 0.00 0.00 0.00 Contract Energy Price ($/MWh)(10) 9.90 7.38 0.00 0.00 0.00 Other Capacity Price ($/MWh)(11) 84.60 86.35 88.16 89.98 92.41 Other Energy Price ($/MWh)(11) 52.26 54.70 57.56 59.75 61.37 Fuel Price ($/MMBtu)(12) 5.09 5.28 5.58 5.75 5.88 SO(2) Allowances ($/Ton)(13) 236 242 249 256 262 NO(x) Allowances ($/Ton)(14) 2,413 2,478 2,545 2,614 2,684 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Goat Rock (15) 0 0 0 0 0 Harris (15) 72,074 17,407 0 0 0 Stanton 0 0 0 0 0 Wansley 0 0 0 0 0 Other Electricity Revenues Dahlberg 69,587 73,483 73,281 73,655 75,645 Goat Rock (15) 292,313 290,945 275,759 278,822 286,350 Harris 153,199 249,241 292,818 279,968 287,526 Stanton 103,909 108,549 112,123 112,206 115,235 Wansley 237,084 236,502 235,606 229,143 235,330 ------- ------- ------- ------- --------- Total Operating Revenues 928,166 976,127 989,587 973,794 1,000,086 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 1,490 3,067 2,286 1,575 1,617 Goat Rock 144,257 140,738 131,795 131,030 134,090 Harris 77,179 122,484 143,171 131,126 134,164 Stanton 59,396 61,697 64,446 63,226 64,517 Wansley 100,159 98,406 98,376 92,484 94,585 Emissions Allowances 109 83 8 (12) (13) Purchased Power 2,498 0 0 0 0 Operations & Maintenance 46,487 47,028 46,572 46,374 47,627 Major Maintenance 50,370 49,348 50,593 45,433 46,750 Administration 15,186 15,595 16,015 16,447 16,893 Insurance 3,887 3,991 4,100 4,210 4,324 Property Taxes 14,134 14,174 14,214 14,256 14,299 Other 270 270 270 270 270 ------- ------- ------- ------- --------- Total Operating Expenses 515,422 556,880 571,845 546,418 559,123 NET OPERATING REVENUES ($000) 412,744 419,247 417,742 427,376 440,963 ANNUAL INTEREST($000) (17) 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE (18) 4.69 4.77 4.75 4.86 5.01 2002-12 AVG INTEREST COVERAGE (19)
A-60 FOOTNOTES TO EXHIBIT A-3 The footnotes to Exhibit A-2 are the same as the footnotes for Exhibit A-1, except: 3. Capacity factor as estimated by PA Consulting under its "Low Gas Price" scenario. 8. As estimated by PA Consulting in its "Low Gas Price" scenario. Weighted average market electricity price for the Generating Facilities calculated as the sum of the electricity revenues divided by the electricity generation, as estimated by PA Consulting. 9. As estimated by PA Consulting in its "Low Gas Price" scenario. Weighted average fuel price for the Generating Facilities calculated as sum of the fuel expenses divided by the total fuel consumed by the Generating Facilities. A-61 EXHIBIT A-3 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY B - HIGH FUEL MARKET PRICE SCENARIO
Year Ending December 31, 2002(1) 2003 2004 2005 2006 2007 - ------------------------ -------- ------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 2,489 4,678 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 24.4% 11.3% 16.4% 21.0% 26.5% 28.6% Contract Energy Sales (GWh)(4) 2,870 3,731 6,471 8,846 11,091 11,998 Other Energy Sales (GWh)(4) 137 906 415 1 51 42 -------- ------- ------- ------- ------- ------- Total Energy Sales (GWh) 3,007 4,637 6,886 8,847 11,142 12,041 Fuel Consumption (BBtu) 22,751 36,267 52,965 68,033 85,523 91,597 Average Net Heat Rate (Btu/kWh)(5) 7,339 7,834 7,865 7,905 7,884 7,812 SO(2) Allowances Purchased (Tons)(6) 11 17 27 34 43 45 NO(x) Allowances Purchased (Tons)(7) 0 0 (131) (38) 11 33 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 51.53 60.50 70.74 73.59 77.20 77.23 Contract Energy Price ($/MWh)(10) $ 5.76 7.36 7.36 8.62 8.53 8.22 Other Capacity Price ($/MWh)(11) $ 16.49 16.35 17.20 16.38 16.82 17.27 Other Energy Price ($/MWh)(11) $ 42.47 49.38 50.12 81.80 67.54 70.58 Fuel Price ($/MMBtu)(12) $ 4.90 5.66 5.54 3.88 3.85 3.99 SO(2) Allowances ($/Ton)(13) $ 154 158 162 167 171 176 NO(x) Allowances ($/Ton)(14) $ 0 0 2,006 1,707 1,753 1,800 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 29,303 46,858 45,510 2,666 0 0 Goat Rock(15) $ 38,781 78,210 101,442 114,784 119,572 120,862 Harris(15) $ 0 41,614 102,301 129,551 137,838 137,265 Stanton $ 0 9,981 44,335 44,902 45,374 45,832 Wansley $ 66,740 82,692 81,414 86,127 91,000 94,030 Other Electricity Revenues Dahlberg $ 0 0 0 11,945 16,947 16,832 Goat Rock(15) $ 6,763 15,325 8,445 0 0 0 Harris $ 0 39,076 16,736 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 -------- ------- ------- ------- ------- ------- Total Operating Revenues $141,587 313,756 400,183 389,975 410,731 414,821 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 0 0 0 31 2,208 1,921 Goat Rock $ 5,107 11,557 6,379 0 0 0 Harris $ 0 29,136 12,217 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Emissions Allowances $ 0 0 (263) (180) (120) (95) Purchased Power $ 2,193 2,654 7,533 12,005 14,804 16,499 Operations & Maintenance $ 7,687 18,149 26,397 29,231 32,982 34,859 Major Maintenance $ 8,345 14,843 20,898 25,776 31,575 34,633 Administration $ 3,022 7,866 10,457 10,739 11,029 11,328 Insurance $ 756 1,995 2,676 2,748 2,821 2,899 Property Taxes $ 3,566 10,113 13,679 13,706 13,734 13,762 Other $ 90 216 270 270 270 270 -------- ------- ------- ------- ------- ------- Total Operating Expenses $ 30,766 96,529 100,243 94,327 109,302 116,076 NET OPERATING REVENUES ($000) $110,821 217,227 299,940 295,648 301,429 298,744 ANNUAL INTEREST($000)(17) $ 20,964 66,271 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 5.29 3.28 3.41 3.36 3.43 3.40 2002-12 AVG INTEREST COVERAGE(19) 3.65 Year Ending December 31, 2008 2009 2010 2011 2012 - ------------------------ ------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 27.3% 28.3% 27.5% 26.9% 25.3% Contract Energy Sales (GWh)(4) 11,437 11,789 6,293 3,654 2,806 Other Energy Sales (GWh)(4) 44 100 5,111 7,470 7,654 ------- ------- ------- ------- ------- Total Energy Sales (GWh) 11,481 11,889 11,404 11,124 10,460 Fuel Consumption (BBtu) 87,417 90,671 88,917 86,835 82,313 Average Net Heat Rate (Btu/kWh)(5) 7,819 7,830 7,902 7,875 7,938 SO(2) Allowances Purchased (Tons)(6) 43 46 45 43 41 NO(x) Allowances Purchased (Tons)(7) 30 33 37 36 24 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 77.26 77.28 40.00 60.62 84.98 Contract Energy Price ($/MWh)(10) 8.50 8.58 9.68 13.04 12.28 Other Capacity Price ($/MWh)(11) 50.19 48.57 59.99 63.65 68.55 Other Energy Price ($/MWh)(11) 71.86 77.49 57.41 58.02 59.91 Fuel Price ($/MMBtu)(12) 4.11 4.25 5.49 5.62 5.83 SO(2) Allowances ($/Ton)(13) 181 186 191 196 201 NO(x) Allowances ($/Ton)(14) 1,849 1,899 1,950 2,002 2,057 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Goat Rock(15) 119,516 121,373 80,160 25,717 0 Harris(15) 137,373 137,609 89,186 71,903 72,242 Stanton 46,106 46,072 46,615 46,661 47,104 Wansley 93,617 95,671 0 0 0 Other Electricity Revenues Dahlberg 43,405 46,687 58,961 63,081 66,071 Goat Rock(15) 0 0 83,499 221,762 273,728 Harris 0 0 95,737 144,453 140,142 Stanton 0 0 0 0 0 Wansley 0 0 218,232 226,306 230,838 ------- ------- ------- ------- ------- Total Operating Revenues 440,017 447,412 672,390 799,883 830,125 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 2,047 4,797 7,027 7,777 7,189 Goat Rock 0 0 45,611 123,007 151,666 Harris 0 0 55,012 82,082 77,566 Stanton 0 0 0 0 0 Wansley 0 0 114,738 117,193 116,504 Emissions Allowances (100) (101) 76 77 55 Purchased Power 15,961 17,253 8,577 5,845 5,686 Operations & Maintenance 35,126 37,109 38,011 38,868 38,946 Major Maintenance 34,457 36,120 36,395 41,201 36,412 Administration 11,633 11,946 12,270 12,599 12,942 Insurance 2,978 3,057 3,140 3,224 3,311 Property Taxes 13,792 13,822 13,853 13,885 13,918 Other 270 270 270 270 270 ------- ------- ------- ------- ------- Total Operating Expenses 116,164 124,274 334,981 446,029 464,464 NET OPERATING REVENUES ($000) 323,854 323,138 337,409 353,854 365,661 ANNUAL INTEREST($000)(17) 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 3.68 3.67 3.84 4.02 4.16 2002-12 AVG INTEREST COVERAGE(19)
A-62 EXHIBIT A-3 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY B - HIGH FUEL MARKET PRICE SCENARIO
Year Ending December 31, 2013 2014 2015 2016 2017 - ------------------------ -------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 22.9% 20.5% 19.0% 18.2% 16.7% Contract Energy Sales (GWh)(4) 2,380 1,408 1,240 1,245 1,045 Other Energy Sales (GWh)(4) 7,022 7,014 6,550 6,241 5,825 -------- ------- ------- ------- ------- Total Energy Sales (GWh) 9,402 8,422 7,790 7,486 6,870 Fuel Consumption (BBtu) 74,753 67,149 62,605 60,094 55,343 Average Net Heat Rate (Btu/kWh)(5) 7,983 8,007 8,069 8,061 8,087 SO(2) Allowances Purchased (Tons)(6) 37 33 32 31 28 NO(x) Allowances Purchased (Tons)(7) 5 (13) (26) (40) (56) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 79.61 88.55 88.55 88.55 88.55 Contract Energy Price ($/MWh)(10) $ 13.92 12.15 13.03 13.66 13.85 Other Capacity Price ($/MWh)(11) $ 73.15 74.76 76.72 72.49 77.95 Other Energy Price ($/MWh)(11) $ 61.89 65.29 67.83 71.47 73.53 Fuel Price ($/MMBtu)(12) $ 6.09 6.51 6.75 7.03 7.33 SO(2) Allowances ($/Ton)(13) $ 207 212 218 224 230 NO(x) Allowances ($/Ton)(14) $ 2,112 2,169 2,228 2,288 2,350 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 Goat Rock(15) $ 0 0 0 0 0 Harris(15) $ 72,379 69,827 68,879 69,734 67,206 Stanton $ 40,287 0 0 0 0 Wansley $ 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 69,838 66,897 70,314 64,431 65,951 Goat Rock(15) $268,996 259,187 254,965 249,836 244,669 Harris $141,074 136,126 130,497 129,639 129,495 Stanton $ 11,819 89,669 92,407 94,853 100,237 Wansley $217,400 210,602 208,634 202,522 205,443 -------- ------- ------- ------- ------- Total Operating Revenues $821,793 832,308 825,696 811,015 813,001 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 6,855 4,321 5,573 4,056 2,141 Goat Rock $145,714 135,321 130,889 131,374 124,866 Harris $ 77,481 72,455 67,983 68,818 67,748 Stanton $ 7,808 56,298 57,845 58,652 62,056 Wansley $102,349 97,439 94,340 91,126 88,104 Emissions Allowances $ 15 (23) (51) (89) (128) Purchased Power $ 2,301 2,238 2,073 2,177 1,931 Operations & Maintenance $ 38,494 37,770 38,115 38,394 38,194 Major Maintenance $ 36,325 32,601 31,580 31,676 30,965 Administration $ 13,290 13,650 14,016 14,395 14,786 Insurance $ 3,400 3,493 3,587 3,684 3,784 Property Taxes $ 13,952 13,986 14,022 14,058 14,096 Other $ 270 270 270 270 270 -------- ------- ------- ------- ------- Total Operating Expenses $448,255 469,821 460,243 458,591 448,814 NET OPERATING REVENUES ($000) $373,538 362,487 365,453 352,424 364,187 ANNUAL INTEREST($000)(17) $ 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 4.25 4.12 4.16 4.01 4.14 2002-12 AVG INTEREST COVERAGE(19) 3.65 Year Ending December 31, 2018 2019 2020 2021 2022 - ------------------------ ------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,668 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 16.1% 14.9% 13.9% 13.0% 13.0% Contract Energy Sales (GWh)(4) 1,093 291 0 0 0 Other Energy Sales (GWh)(4) 5,531 5,809 5,667 5,316 5,316 ------- ------- ------- ------- ------- Total Energy Sales (GWh) 6,624 6,100 5,667 5,316 5,316 Fuel Consumption (BBtu) 53,407 49,609 46,156 43,237 43,237 Average Net Heat Rate (Btu/kWh)(5) 8,097 8,132 8,144 8,133 8,133 SO(2) Allowances Purchased (Tons)(6) 27 24 22 21 21 NO(x) Allowances Purchased (Tons)(7) (66) (68) (82) (93) (93) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 88.55 22.14 0.00 0.00 0.00 Contract Energy Price ($/MWh)(10) 15.67 9.82 0.00 0.00 0.00 Other Capacity Price ($/MWh)(11) 82.10 84.39 87.46 89.36 91.78 Other Energy Price ($/MWh)(11) 75.96 80.90 83.20 84.60 86.89 Fuel Price ($/MMBtu)(12) 7.55 7.79 8.19 8.45 8.64 SO(2) Allowances ($/Ton)(13) 236 242 249 256 262 NO(x) Allowances ($/Ton)(14) 2,413 2,478 2,545 2,614 2,684 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Goat Rock(15) 0 0 0 0 0 Harris(15) 69,845 16,040 0 0 0 Stanton 0 0 0 0 0 Wansley 0 0 0 0 0 Other Electricity Revenues Dahlberg 68,187 73,341 75,847 76,781 78,855 Goat Rock(15) 254,813 255,835 241,120 248,156 254,856 Harris 133,284 212,500 254,583 250,887 257,660 Stanton 100,498 102,824 103,630 102,675 105,447 Wansley 197,755 203,499 204,632 188,454 193,542 ------- ------- ------- ------- ------- Total Operating Revenues 824,382 864,039 879,812 866,953 890,360 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 1,622 3,791 3,950 3,764 3,865 Goat Rock 126,541 121,685 110,479 114,539 117,153 Harris 68,049 100,279 119,665 117,149 119,810 Stanton 61,857 62,154 63,224 61,498 62,742 Wansley 79,646 79,741 80,666 68,485 69,939 Emissions Allowances (153) (162) (201) (235) (242) Purchased Power 2,046 0 0 0 0 Operations & Maintenance 38,678 39,322 39,736 40,103 41,187 Major Maintenance 31,008 30,345 29,989 33,333 30,681 Administration 15,186 15,595 16,015 16,447 16,893 Insurance 3,887 3,991 4,100 4,210 4,324 Property Taxes 14,134 14,174 14,214 14,256 14,299 Other 270 270 270 270 270 ------- ------- ------- ------- ------- Total Operating Expenses 442,772 471,184 482,106 473,818 480,921 NET OPERATING REVENUES ($000) 381,610 392,855 397,706 393,135 409,439 ANNUAL INTEREST($000)(17) 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 4.34 4.47 4.52 4.47 4.66 2002-12 AVG INTEREST COVERAGE(19)
A-63 FOOTNOTES TO EXHIBIT A-3 The footnotes to Exhibit A-3 are the same as the footnotes for Exhibit A-1, except: 3. Capacity factor as estimated by PA Consulting under its "High Gas Price" scenario. 8. As estimated by PA Consulting in its "High Gas Price" scenario. Weighted average market electricity price for the Generating Facilities calculated as the sum of the electricity revenues divided by the electricity generation, as estimated by PA Consulting. 9. As estimated by PA Consulting in its "High Gas Price" scenario. Weighted average fuel price for the Generating Facilities calculated as sum of the fuel expenses divided by the total fuel consumed by the Generating Facilities. A-64 EXHIBIT A-4 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY C - OVERBUILD PRICE SCENARIO
Year Ending December 31, 2002(1) 2003 2004 2005 2006 2007 - ------------------------ -------- ------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 2,489 4,678 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 37.2% 10.7% 14.0% 20.3% 27.4% 29.1% Contract Energy Sales (GWh)(4) 4,404 3,609 5,518 8,544 11,525 12,241 Other Energy Sales (GWh)(4) 268 765 354 0 0 1 -------- ------- ------- ------- ------- ------- Total Energy Sales (GWh) 4,672 4,374 5,873 8,544 11,525 12,243 Fuel Consumption (BBtu) 33,408 33,803 45,095 64,359 85,758 90,833 Average Net Heat Rate (Btu/kWh)(5) 7,053 7,741 7,850 7,749 7,651 7,629 SO(2) Allowances Purchased (Tons)(6) 17 17 21 32 43 46 NO(x) Allowances Purchased (Tons)(7) 0 0 (135) (16) 26 45 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 51.53 60.50 70.74 73.59 77.20 77.23 Contract Energy Price ($/MWh)(10) $ 3.72 6.68 7.03 7.14 6.74 6.73 Other Capacity Price ($/MWh)(11) $ 16.49 17.07 17.40 15.79 16.16 16.63 Other Energy Price ($/MWh)(11) $ 34.62 40.85 43.18 0.00 0.00 57.54 Fuel Price ($/MMBtu)(12) $ 3.94 5.17 5.14 0.00 0.00 3.44 SO(2) Allowances ($/Ton)(13) $ 154 158 162 167 171 176 NO(x) Allowances ($/Ton)(14) $ 0 0 2,006 1,707 1,753 1,800 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 29,314 46,845 45,510 2,666 0 0 Goat Rock(15) $ 38,262 76,893 98,397 109,428 113,064 116,864 Harris(15) $ 0 39,755 98,147 122,297 130,133 128,364 Stanton $ 0 9,897 43,305 43,707 44,288 44,548 Wansley $ 67,098 82,624 80,831 84,692 89,429 91,970 Other Electricity Revenues Dahlberg $ 0 0 0 11,462 12,961 13,417 Goat Rock(15) $ 10,188 12,023 6,346 0 0 0 Harris $ 0 29,303 13,387 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 -------- ------- ------- ------- ------- ------- Total Operating Revenues $144,862 297,341 385,923 374,252 389,875 395,163 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 0 0 0 0 0 55 Goat Rock $ 7,677 9,182 4,800 0 0 0 Harris $ 0 22,295 9,785 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Emissions Allowances $ 0 0 (271) (153) (103) (82) Purchased Power $ 2,712 2,042 5,450 9,995 13,006 14,342 Operations & Maintenance $ 9,572 17,943 25,476 28,841 32,841 34,548 Major Maintenance $ 11,605 14,427 18,686 25,088 32,516 35,024 Administration $ 3,022 7,866 10,457 10,739 11,029 11,328 Insurance $ 756 1,995 2,676 2,748 2,821 2,899 Property Taxes $ 3,566 10,113 13,679 13,706 13,734 13,762 Other $ 90 216 270 270 270 270 -------- ------- ------- ------- ------- ------- Total Operating Expenses $ 39,000 86,079 91,007 91,233 106,113 112,145 NET OPERATING REVENUES ($000) $105,862 211,262 294,916 283,018 283,761 283,018 ANNUAL INTEREST($000)(17) $ 20,964 66,271 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 5.05 3.19 3.35 3.22 3.23 3.22 2002-12 AVG INTEREST COVERAGE(19) 3.37 Year Ending December 31, 2008 2009 2010 2011 2012 - ------------------------ ------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 31.6% 32.3% 32.8% 31.3% 29.9% Contract Energy Sales (GWh)(4) 13,332 13,582 7,706 4,522 3,671 Other Energy Sales (GWh)(4) 0 28 5,910 8,445 8,710 ------- ------- ------- ------- ------- Total Energy Sales (GWh) 13,332 13,610 13,616 12,967 12,381 Fuel Consumption (BBtu) 98,972 101,521 103,225 99,026 95,230 Average Net Heat Rate (Btu/kWh)(5) 7,631 7,666 7,691 7,713 7,769 SO(2) Allowances Purchased (Tons)(6) 50 51 51 49 47 NO(x) Allowances Purchased (Tons)(7) 64 61 58 47 43 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 77.26 77.28 40.00 60.62 84.98 Contract Energy Price ($/MWh)(10) 7.01 7.28 7.50 9.84 9.62 Other Capacity Price ($/MWh)(11) 17.08 18.02 44.95 54.08 57.01 Other Energy Price ($/MWh)(11) 0.00 61.47 48.77 50.12 52.04 Fuel Price ($/MMBtu)(12) 0.00 3.70 4.69 4.81 4.98 SO(2) Allowances ($/Ton)(13) 181 186 191 196 201 NO(x) Allowances ($/Ton)(14) 1,849 1,899 1,950 2,002 2,057 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Goat Rock(15) 119,201 121,201 78,895 23,771 0 Harris(15) 134,721 135,902 87,975 70,924 72,786 Stanton 44,679 45,321 45,953 46,416 47,438 Wansley 94,238 96,036 0 0 0 Other Electricity Revenues Dahlberg 13,694 16,157 37,714 46,433 49,505 Goat Rock(15) 0 0 78,425 213,163 260,910 Harris 0 0 87,030 131,994 131,850 Stanton 0 0 0 0 0 Wansley 0 0 207,178 220,489 220,773 ------- ------- ------- ------- ------- Total Operating Revenues 406,533 414,617 623,170 753,190 783,262 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 0 1,137 1,039 2,035 2,308 Goat Rock 0 0 44,919 119,801 145,950 Harris 0 0 51,484 74,727 73,978 Stanton 0 0 0 0 0 Wansley 0 0 116,291 117,262 114,415 Emissions Allowances (65) (64) 116 102 94 Purchased Power 15,938 17,333 9,422 6,540 6,565 Operations & Maintenance 36,769 38,323 39,577 40,157 40,507 Major Maintenance 38,742 40,140 41,599 41,867 41,456 Administration 11,633 11,946 12,270 12,599 12,942 Insurance 2,978 3,057 3,140 3,224 3,311 Property Taxes 13,792 13,822 13,853 13,885 13,918 Other 270 270 270 270 270 ------- ------- ------- ------- ------- Total Operating Expenses 120,058 125,963 333,980 432,470 455,715 NET OPERATING REVENUES ($000) 286,475 288,654 289,190 320,720 327,547 ANNUAL INTEREST($000)(17) 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 3.26 3.28 3.29 3.65 3.72 2002-12 AVG INTEREST COVERAGE(19)
A-65 EXHIBIT A-4 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY C - OVERBUILD PRICE SCENARIO
Year Ending December 31, 2013 2014 2015 2016 2017 - ------------------------ -------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 26.8% 24.3% 22.2% 21.9% 20.5% Contract Energy Sales (GWh)(4) 2,980 1,576 1,396 1,391 1,218 Other Energy Sales (GWh)(4) 8,056 8,397 7,719 7,598 7,202 -------- ------- ------- ------- ------- Total Energy Sales (GWh) 11,036 9,973 9,115 8,989 8,419 Fuel Consumption (BBtu) 85,986 78,148 71,914 70,876 66,589 Average Net Heat Rate (Btu/kWh)(5) 7,821 7,867 7,920 7,916 7,938 SO(2) Allowances Purchased (Tons)(6) 43 38 35 35 32 NO(x) Allowances Purchased (Tons)(7) 28 9 (10) (17) (33) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 79.61 88.55 88.55 88.55 88.55 Contract Energy Price ($/MWh)(10) $ 11.04 11.29 12.52 11.97 11.95 Other Capacity Price ($/MWh)(11) $ 62.39 64.02 71.14 72.46 77.29 Other Energy Price ($/MWh)(11) $ 53.00 56.69 58.28 60.87 62.41 Fuel Price ($/MMBtu)(12) $ 5.18 5.55 5.76 5.99 6.20 SO(2) Allowances ($/Ton)(13) $ 207 212 218 224 230 NO(x) Allowances ($/Ton)(14) $ 2,112 2,169 2,228 2,288 2,350 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 Goat Rock(15) $ 0 0 0 0 0 Harris(15) $ 72,197 70,525 70,213 69,368 67,284 Stanton $ 40,250 0 0 0 0 Wansley $ 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 53,406 54,334 60,499 59,901 62,303 Goat Rock(15) $256,132 249,248 246,352 247,506 246,916 Harris $131,107 128,133 126,181 128,076 128,221 Stanton $ 13,547 99,962 104,056 107,827 118,024 Wansley $207,680 205,103 202,540 214,311 208,773 -------- ------- ------- ------- ------- Total Operating Revenues $774,319 807,305 809,841 826,989 831,521 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 1,732 1,290 1,839 1,089 270 Goat Rock $140,723 132,114 125,940 126,606 124,767 Harris $ 72,298 68,495 65,543 66,511 66,085 Stanton $ 9,204 65,194 66,607 67,218 73,115 Wansley $101,334 99,023 91,366 98,217 89,964 Emissions Allowances $ 65 24 (17) (34) (71) Purchased Power $ 2,207 2,188 2,018 2,095 1,913 Operations & Maintenance $ 39,742 39,340 39,285 40,095 40,086 Major Maintenance $ 39,289 37,141 35,797 37,134 36,263 Administration $ 13,290 13,650 14,016 14,395 14,786 Insurance $ 3,400 3,493 3,587 3,684 3,784 Property Taxes $ 13,952 13,986 14,022 14,058 14,096 Other $ 270 270 270 270 270 -------- ------- ------- ------- ------- Total Operating Expenses $437,506 476,210 460,274 471,339 465,329 NET OPERATING REVENUES ($000) $336,813 331,095 349,567 355,650 366,192 ANNUAL INTEREST($000)(17) $ 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 3.83 3.77 3.98 4.04 4.16 2002-12 AVG INTEREST COVERAGE(19) 3.37 Year Ending December 31, 2018 2019 2020 2021 2022 - ------------------------ ------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,668 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 19.9% 17.5% 17.1% 15.9% 15.9% Contract Energy Sales (GWh)(4) 1,232 336 0 0 0 Other Energy Sales (GWh)(4) 6,929 6,815 6,985 6,500 6,500 ------- ------- ------- ------- ------- Total Energy Sales (GWh) 8,161 7,151 6,985 6,500 6,500 Fuel Consumption (BBtu) 64,682 57,135 56,202 52,543 52,543 Average Net Heat Rate (Btu/kWh)(5) 7,956 7,990 8,047 8,083 8,083 SO(2) Allowances Purchased (Tons)(6) 32 29 27 25 25 NO(x) Allowances Purchased (Tons)(7) (29) (45) (54) (59) (59) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 88.55 22.14 0.00 0.00 0.00 Contract Energy Price ($/MWh)(10) 14.34 8.59 0.00 0.00 0.00 Other Capacity Price ($/MWh)(11) 80.40 85.35 87.07 88.88 91.28 Other Energy Price ($/MWh)(11) 65.33 69.00 71.66 73.29 75.27 Fuel Price ($/MMBtu)(12) 6.35 6.64 6.94 7.13 7.29 SO(2) Allowances ($/Ton)(13) 236 242 249 256 262 NO(x) Allowances ($/Ton)(14) 2,413 2,478 2,545 2,614 2,684 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Goat Rock(15) 0 0 0 0 0 Harris(15) 70,390 16,068 0 0 0 Stanton 0 0 0 0 0 Wansley 0 0 0 0 0 Other Electricity Revenues Dahlberg 65,466 71,047 72,074 73,701 75,692 Goat Rock(15) 254,615 252,494 244,643 248,673 255,387 Harris 133,499 209,561 262,680 254,525 261,396 Stanton 112,945 112,886 113,335 112,699 115,742 Wansley 213,598 206,530 214,283 201,728 207,174 ------- ------- ------- ------- ------- Total Operating Revenues 850,513 868,586 907,015 891,326 915,391 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 614 1,587 1,335 1,576 1,619 Goat Rock 123,040 115,760 110,788 111,841 114,384 Harris 66,564 95,247 122,782 116,547 119,192 Stanton 69,504 69,187 69,664 68,531 69,965 Wansley 89,438 79,502 85,600 76,091 77,749 Emissions Allowances (62) (107) (131) (149) (153) Purchased Power 2,015 0 0 0 0 Operations & Maintenance 40,874 40,586 41,424 41,723 42,851 Major Maintenance 36,821 34,866 35,151 34,161 35,084 Administration 15,186 15,595 16,015 16,447 16,893 Insurance 3,887 3,991 4,100 4,210 4,324 Property Taxes 14,134 14,174 14,214 14,256 14,299 Other 270 270 270 270 270 ------- ------- ------- ------- ------- Total Operating Expenses 462,284 470,658 501,211 485,504 496,476 NET OPERATING REVENUES ($000) 388,229 397,928 405,804 405,822 418,915 ANNUAL INTEREST($000)(17) 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 4.41 4.53 4.61 4.61 4.76 2002-12 AVG INTEREST COVERAGE(19)
A-66 FOOTNOTES TO EXHIBIT A-4 The footnotes to Exhibit A-4 are the same as the footnotes for Exhibit A-1, except: 3. Capacity factor as estimated by PA Consulting under its "Capacity Overbuild" scenario. 8. As estimated by PA Consulting in its "Capacity Overbuild" scenario. Weighted average market electricity price for the Generating Facilities calculated as the sum of the electricity revenues divided by the electricity generation, as estimated by PA Consulting. 9. As estimated by PA Consulting in its "Capacity Overbuild" scenario. Weighted average fuel price for the Generating Facilities calculated as sum of the fuel expenses divided by the total fuel consumed by the Generating Facilities. A-67 EXHIBIT A-5 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY D - REDUCED OUTPUT
Year Ending December 31, 2002(1) 2003 2004 2005 2006 2007 - ------------------------ -------- ------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 2,364 4,444 4,444 4,444 4,444 4,444 Average Capacity Factor (%)(3) 37.2% 14.7% 21.0% 25.9% 31.5% 33.5% Contract Energy Sales (GWh)(4) 4,184 4,765 7,849 10,367 12,545 13,337 Other Energy Sales (GWh)(4) 247 998 514 0 45 42 -------- ------- ------- ------- ------- ------- Total Energy Sales (GWh) 4,431 5,764 8,364 10,367 12,590 13,380 Fuel Consumption (BBtu) 31,687 44,309 63,085 78,169 94,428 99,697 Average Net Heat Rate (Btu/kWh)(5) 7,042 7,723 7,706 7,749 7,703 7,652 SO(2) Allowances Purchased (Tons)(6) 15 23 31 40 47 50 NO(x) Allowances Purchased (Tons)(7) 0 0 (104) 5 50 66 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 51.53 60.52 70.61 73.41 77.20 77.23 Contract Energy Price ($/MWh)(10) $ 3.76 6.83 6.50 7.60 7.14 6.96 Other Capacity Price ($/MWh)(11) $ 16.49 16.35 16.84 16.38 16.82 17.27 Other Energy Price ($/MWh)(11) $ 34.62 42.40 41.94 0.00 61.94 60.75 Fuel Price ($/MMBtu)(12) $ 3.99 4.90 4.67 0.00 3.32 3.45 SO(2) Allowances ($/Ton)(13) $ 154 158 162 167 171 176 NO(x) Allowances ($/Ton)(14) $ 0 0 2,006 1,707 1,753 1,800 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 29,322 46,845 45,510 2,666 0 0 Goat Rock (15) $ 36,996 76,806 98,090 110,667 113,076 115,399 Harris (15) $ 0 39,867 99,180 125,194 128,051 127,977 Stanton $ 0 9,549 41,286 42,571 42,962 43,244 Wansley $ 63,850 82,279 80,217 84,554 89,731 90,599 Other Electricity Revenues Dahlberg $ 0 0 0 11,291 15,573 15,741 Goat Rock (15) $ 9,430 15,122 8,820 0 0 0 Harris $ 0 36,356 16,826 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 -------- ------- ------- ------- ------- ------- Total Operating Revenues $139,598 306,825 389,929 376,943 389,393 392,960 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 0 0 0 0 1,658 1,685 Goat Rock $ 7,178 11,536 6,652 0 0 0 Harris $ 0 27,238 12,243 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Emissions Allowances $ 0 0 (209) (126) (76) (57) Purchased Power $ 2,589 2,855 7,511 11,919 14,167 15,490 Operations & Maintenance $ 9,303 19,417 27,920 30,797 34,508 36,346 Major Maintenance $ 11,605 17,836 25,034 30,385 36,548 39,529 Administration $ 3,022 7,866 10,457 10,739 11,029 11,328 Insurance $ 756 1,995 2,676 2,748 2,821 2,899 Property Taxes $ 3,566 10,113 13,679 13,706 13,734 13,762 Other $ 90 216 270 270 270 270 -------- ------- ------- ------- ------- ------- Total Operating Expenses $ 38,109 99,072 106,233 100,438 114,659 121,252 NET OPERATING REVENUES ($000) $101,489 207,753 283,695 276,505 274,734 271,708 ANNUAL INTEREST($000) (17) $ 20,964 66,271 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE (18) 4.84 3.13 3.23 3.14 3.12 3.09 2002-12 AVG INTEREST COVERAGE (19) 3.41 Year Ending December 31, 2008 2009 2010 2011 2012 - ------------------------ ------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,444 4,444 4,444 4,444 4,444 Average Capacity Factor (%)(3) 31.5% 32.4% 32.2% 30.9% 29.6% Contract Energy Sales (GWh)(4) 12,567 12,865 6,821 3,924 3,148 Other Energy Sales (GWh)(4) 42 93 5,886 8,192 8,495 ------- ------- ------- ------- ------- Total Energy Sales (GWh) 12,609 12,958 12,706 12,116 11,643 Fuel Consumption (BBtu) 94,592 97,314 97,171 93,250 89,962 Average Net Heat Rate (Btu/kWh)(5) 7,704 7,710 7,745 7,762 7,794 SO(2) Allowances Purchased (Tons)(6) 46 48 50 47 44 NO(x) Allowances Purchased (Tons)(7) 57 55 65 59 55 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 77.26 77.28 40.00 60.62 84.98 Contract Energy Price ($/MWh)(10) 7.62 7.65 8.35 11.61 10.68 Other Capacity Price ($/MWh)(11) 51.65 51.68 60.96 66.92 71.14 Other Energy Price ($/MWh)(11) 61.12 65.13 48.21 49.51 50.91 Fuel Price ($/MMBtu)(12) 3.56 3.67 4.67 4.82 4.99 SO(2) Allowances ($/Ton)(13) 181 186 191 196 201 NO(x) Allowances ($/Ton)(14) 1,849 1,899 1,950 2,002 2,057 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Goat Rock (15) 114,992 116,633 76,064 23,744 0 Harris (15) 130,690 129,238 83,679 69,001 69,319 Stanton 43,679 44,156 44,472 44,600 44,942 Wansley 90,911 92,986 0 0 0 Other Electricity Revenues Dahlberg 41,917 45,418 54,454 60,929 64,131 Goat Rock (15) 0 0 83,271 213,105 262,193 Harris 0 0 89,584 134,001 135,221 Stanton 0 0 0 0 0 Wansley 0 0 213,778 219,480 219,609 ------- ------- ------- ------- ------- Total Operating Revenues 422,189 428,431 645,302 764,860 795,415 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 1,690 3,852 5,140 6,491 6,202 Goat Rock 0 0 45,696 114,922 141,823 Harris 0 0 49,959 73,213 73,499 Stanton 0 0 0 0 0 Wansley 0 0 112,516 110,979 107,951 Emissions Allowances (67) (68) 128 125 121 Purchased Power 15,064 15,989 7,843 5,309 5,306 Operations & Maintenance 36,438 38,347 39,477 40,103 40,429 Major Maintenance 38,745 40,454 42,286 46,076 41,444 Administration 11,633 11,946 12,270 12,599 12,942 Insurance 2,978 3,057 3,140 3,224 3,311 Property Taxes 13,792 13,822 13,853 13,885 13,918 Other 270 270 270 270 270 ------- ------- ------- ------- ------- Total Operating Expenses 120,543 127,669 332,579 427,196 447,216 NET OPERATING REVENUES ($000) 301,646 300,763 312,723 337,664 348,199 ANNUAL INTEREST($000) (17) 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE (18) 3.43 3.42 3.56 3.84 3.96 2002-12 AVG INTEREST COVERAGE (19)
A-68 EXHIBIT A-5 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY D - REDUCED OUTPUT
Year Ending December 31, 2013 2014 2015 2016 2017 - ------------------------ -------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,444 4,435 4,435 4,435 4,435 Average Capacity Factor (%)(3) 26.9% 24.5% 22.5% 21.8% 20.6% Contract Energy Sales (GWh)(4) 2,662 1,596 1,419 1,360 1,231 Other Energy Sales (GWh)(4) 7,867 7,975 7,350 7,157 6,814 -------- ------- ------- ------- ------- Total Energy Sales (GWh) 10,530 9,571 8,770 8,517 8,045 Fuel Consumption (BBtu) 82,252 74,901 69,505 67,644 64,084 Average Net Heat Rate (Btu/kWh)(5) 7,844 7,859 7,958 7,975 7,996 SO(2) Allowances Purchased (Tons)(6) 41 37 35 34 31 NO(x) Allowances Purchased (Tons)(7) 34 15 (7) (19) (37) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 79.61 88.55 88.55 88.55 88.55 Contract Energy Price ($/MWh)(10) $ 12.40 11.40 12.92 13.45 13.67 Other Capacity Price ($/MWh)(11) $ 74.88 74.48 77.98 78.32 79.53 Other Energy Price ($/MWh)(11) $ 52.34 55.56 57.92 60.04 63.19 Fuel Price ($/MMBtu)(12) $ 5.21 5.58 5.79 6.03 6.26 SO(2) Allowances ($/Ton)(13) $ 207 212 218 224 230 NO(x) Allowances ($/Ton)(14) $ 2,112 2,169 2,228 2,288 2,350 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 Goat Rock(15) $ 0 0 0 0 0 Harris(15) $ 69,875 68,283 68,421 68,380 66,929 Stanton $ 38,698 0 0 0 0 Wansley $ 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 65,320 62,095 67,003 65,242 63,122 Goat Rock(15) $258,304 253,514 246,538 246,736 243,828 Harris $134,765 129,099 126,414 124,784 126,705 Stanton $ 11,070 84,967 87,187 90,255 97,475 Wansley $207,937 201,580 200,351 205,732 207,130 -------- ------- ------- ------- ------- Total Operating Revenues $785,969 799,538 795,914 801,129 805,189 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 5,132 3,382 4,782 3,687 1,784 Goat Rock $138,105 133,273 126,035 127,935 124,524 Harris $ 73,057 67,954 65,745 64,594 65,322 Stanton $ 7,175 52,216 52,959 54,975 58,922 Wansley $ 97,042 92,714 89,121 92,875 89,966 Emissions Allowances $ 75 41 (8) (36) (79) Purchased Power $ 2,224 2,164 2,027 2,011 1,942 Operations & Maintenance $ 39,811 39,229 39,453 39,955 39,925 Major Maintenance $ 41,406 37,592 36,561 37,978 37,710 Administration $ 13,290 13,650 14,016 14,395 14,786 Insurance $ 3,400 3,493 3,587 3,684 3,784 Property Taxes $ 13,952 13,986 14,022 14,058 14,096 Other $ 270 270 270 270 270 -------- ------- ------- ------- ------- Total Operating Expenses $434,938 459,965 448,570 456,381 452,954 NET OPERATING REVENUES ($000) $351,030 339,573 347,344 344,748 352,235 ANNUAL INTEREST($000)(17) $ 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 3.99 3.86 3.95 3.92 4.01 2002-12 AVG INTEREST COVERAGE(19) 3.41 Year Ending December 31, 2018 2019 2020 2021 2022 - ------------------------ ------- ------- ------- ------- ------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,435 4,435 4,435 4,435 4,435 Average Capacity Factor (%)(3) 19.8% 18.8% 18.7% 17.2% 17.2% Contract Energy Sales (GWh)(4) 1,226 374 0 0 0 Other Energy Sales (GWh)(4) 6,487 6,917 7,263 6,675 6,675 ------- ------- ------- ------- ------- Total Energy Sales (GWh) 7,714 7,290 7,263 6,675 6,675 Fuel Consumption (BBtu) 61,280 58,299 58,472 53,871 53,871 Average Net Heat Rate (Btu/kWh)(5) 7,976 7,997 8,051 8,071 8,071 SO(2) Allowances Purchased (Tons)(6) 31 29 29 27 27 NO(x) Allowances Purchased (Tons)(7) (40) (44) (52) (59) (59) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 88.55 22.14 0.00 0.00 0.00 Contract Energy Price ($/MWh)(10) 15.04 9.32 0.00 0.00 0.00 Other Capacity Price ($/MWh)(11) 83.65 85.52 87.87 89.72 92.15 Other Energy Price ($/MWh)(11) 64.92 68.21 70.54 72.47 74.42 Fuel Price ($/MMBtu)(12) 6.44 6.63 6.89 7.12 7.28 SO(2) Allowances ($/Ton)(13) 236 242 249 256 262 NO(x) Allowances ($/Ton)(14) 2,413 2,478 2,545 2,614 2,684 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Goat Rock(15) 0 0 0 0 0 Harris(15) 68,534 16,004 0 0 0 Stanton 0 0 0 0 0 Wansley 0 0 0 0 0 Other Electricity Revenues Dahlberg 65,352 68,823 69,702 71,845 73,787 Goat Rock(15) 249,030 250,726 249,999 248,007 254,706 Harris 129,916 215,449 267,310 254,573 261,450 Stanton 96,644 102,049 105,224 103,189 105,976 Wansley 203,922 198,770 209,801 204,004 209,515 ------- ------- ------- ------- ------- Total Operating Revenues 813,398 851,821 902,036 881,618 905,434 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 1,283 2,712 2,188 2,798 2,873 Goat Rock 122,411 119,726 119,947 116,909 119,588 Harris 65,526 104,871 131,239 121,331 124,105 Stanton 57,977 60,594 62,917 60,608 61,829 Wansley 85,153 78,809 86,529 81,830 83,644 Emissions Allowances (90) (105) (128) (149) (152) Purchased Power 1,985 0 0 0 0 Operations & Maintenance 40,367 41,030 42,038 42,319 43,462 Major Maintenance 37,110 36,643 37,586 36,218 37,196 Administration 15,186 15,595 16,015 16,447 16,893 Insurance 3,887 3,991 4,100 4,210 4,324 Property Taxes 14,134 14,174 14,214 14,256 14,299 Other 270 270 270 270 270 ------- ------- ------- ------- ------- Total Operating Expenses 445,198 478,309 516,914 497,047 508,330 NET OPERATING REVENUES ($000) 368,200 373,512 385,122 384,571 397,104 ANNUAL INTEREST($000)(17) 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 4.19 4.25 4.38 4.37 4.52 2002-12 AVG INTEREST COVERAGE(19)
A-69 FOOTNOTES TO EXHIBIT A-5 The footnotes to Exhibit A-5 are the same as the footnotes for Exhibit A-1, except: 1. The Output of the Generating Facilities is assumed to be 5 percent less than that assumed in the Base Case. A-70 EXHIBIT A-6 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY E - REDUCED AVAILABILITY
Year Ending December 31, 2002(1) 2003 2004 2005 2006 2007 - ------------------------ -------- ------- -------- -------- -------- -------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 2,489 4,678 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 35.3% 14.0% 19.9% 24.6% 29.9% 31.7% Contract Energy Sales (GWh)(4) 4,404 5,016 8,263 10,912 13,205 14,039 Other Energy Sales (GWh)(4) 179 908 406 0 45 42 -------- ------- -------- -------- -------- -------- Total Energy Sales (GWh) 4,584 5,924 8,669 10,912 13,250 14,082 Fuel Consumption (BBtu) 31,633 44,238 62,983 78,043 94,276 99,533 Average Net Heat Rate (Btu/kWh)(5) 7,041 7,723 7,706 7,749 7,704 7,652 SO(2) Allowances Purchased (Tons)(6) 15 23 31 39 47 50 NO(x) Allowances Purchased (Tons)(7) 0 0 (104) 4 49 65 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 51.53 60.50 70.74 73.59 77.20 77.23 Contract Energy Price ($/MWh)(10) $ 4.49 7.53 7.36 8.30 7.85 7.72 Other Capacity Price ($/MWh)(11) $ 16.49 16.35 16.84 16.38 16.82 17.27 Other Energy Price ($/MWh)(11) $ 34.62 42.72 42.12 0.00 61.97 60.77 Fuel Price ($/MMBtu)(12) $ 3.99 4.93 4.70 0.00 3.32 3.45 SO(2) Allowances ($/Ton)(13) $ 154 158 162 167 171 176 NO(x) Allowances ($/Ton)(14) $ 0 0 2,006 1,707 1,753 1,800 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 29,322 46,845 45,510 2,666 0 0 Goat Rock (15) $ 38,262 80,211 104,282 118,011 120,868 123,609 Harris (15) $ 0 43,036 105,817 133,356 136,751 137,046 Stanton $ 0 10,440 45,996 46,633 47,025 47,386 Wansley $ 70,491 89,145 86,584 91,721 98,215 99,632 Other Electricity Revenues Dahlberg $ 0 0 0 11,886 16,246 16,432 Goat Rock (15) $ 7,134 11,787 6,185 0 0 0 Harris $ 0 36,639 15,206 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 -------- ------- -------- -------- -------- -------- Total Operating Revenues $145,209 318,103 409,580 404,273 419,105 424,105 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 0 0 0 0 1,658 1,681 Goat Rock $ 5,212 8,296 4,349 0 0 0 Harris $ 0 27,206 10,670 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Emissions Allowances $ 0 0 (209) (127) (76) (58) Purchased Power $ 8,127 9,479 21,121 35,828 43,060 47,245 Operations & Maintenance $ 9,294 19,408 27,907 30,779 34,485 36,324 Major Maintenance $ 11,127 17,365 24,408 29,609 35,568 38,447 Administration $ 3,022 7,866 10,457 10,739 11,029 11,328 Insurance $ 756 1,995 2,676 2,748 2,821 2,899 Property Taxes $ 3,566 10,113 13,679 13,706 13,734 13,762 Other $ 90 216 270 270 270 270 -------- ------- -------- -------- -------- -------- Total Operating Expenses $ 41,193 101,945 115,327 123,552 142,549 151,899 NET OPERATING REVENUES ($000) $104,016 216,158 294,253 280,721 276,556 272,206 ANNUAL INTEREST($000)(17) $ 20,964 66,271 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 4.96 3.26 3.35 3.19 3.14 3.10 2002-12 AVG INTEREST COVERAGE(19) 3.47 Year Ending December 31, 2008 2009 2010 2011 2012 - ------------------------ -------- -------- ------- ------- -------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 29.9% 30.8% 30.6% 29.3% 28.1% Contract Energy Sales (GWh)(4) 13,229 13,543 7,180 4,131 3,314 Other Energy Sales (GWh)(4) 42 93 5,805 8,141 8,481 -------- -------- ------- ------- -------- Total Energy Sales (GWh) 13,271 13,635 12,985 12,272 11,795 Fuel Consumption (BBtu) 94,438 97,158 97,012 93,099 89,816 Average Net Heat Rate (Btu/kWh)(5) 7,704 7,710 7,745 7,762 7,794 SO(2) Allowances Purchased (Tons)(6) 46 48 50 47 44 NO(x) Allowances Purchased (Tons)(7) 57 54 65 58 55 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 77.26 77.28 40.00 60.62 84.98 Contract Energy Price ($/MWh)(10) 8.39 8.44 8.40 11.74 10.98 Other Capacity Price ($/MWh)(11) 51.65 51.68 60.96 66.92 71.14 Other Energy Price ($/MWh)(11) 61.15 65.13 48.23 49.52 50.91 Fuel Price ($/MMBtu)(12) 3.56 3.67 4.67 4.82 4.99 SO(2) Allowances ($/Ton)(13) 181 186 191 196 201 NO(x) Allowances ($/Ton)(14) 1,849 1,899 1,950 2,002 2,057 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Goat Rock(15) 123,117 124,941 79,486 24,459 0 Harris(15) 139,673 138,368 87,426 72,017 72,338 Stanton 47,827 48,107 48,446 48,653 48,946 Wansley 99,814 102,485 0 0 0 Other Electricity Revenues Dahlberg 43,986 47,485 56,894 63,605 66,975 Goat Rock(15) 0 0 82,754 214,331 266,015 Harris 0 0 89,006 135,838 137,185 Stanton 0 0 0 0 0 Wansley 0 0 216,958 222,996 223,370 -------- -------- ------- ------- -------- Total Operating Revenues 454,417 461,386 660,970 781,899 814,829 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 1,690 3,852 5,136 6,487 6,194 Goat Rock 0 0 44,441 113,400 141,630 Harris 0 0 48,593 73,111 73,394 Stanton 0 0 0 0 0 Wansley 0 0 112,362 110,827 107,807 Emissions Allowances (68) (69) 127 124 119 Purchased Power 45,888 48,967 22,239 14,202 14,205 Operations & Maintenance 36,414 38,321 39,452 40,078 40,404 Major Maintenance 37,696 39,359 40,388 44,963 40,358 Administration 11,633 11,946 12,270 12,599 12,942 Insurance 2,978 3,057 3,140 3,224 3,311 Property Taxes 13,792 13,822 13,853 13,885 13,918 Other 270 270 270 270 270 -------- -------- ------- ------- -------- Total Operating Expenses 150,293 159,525 342,272 433,171 454,552 NET OPERATING REVENUES ($000) 304,124 301,861 318,698 348,729 360,277 ANNUAL INTEREST($000)(17) 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 3.46 3.43 3.62 3.97 4.10 2002-12 AVG INTEREST COVERAGE(19)
A-71 EXHIBIT A-6 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY E - REDUCED AVAILABILITY
Year Ending December 31, 2013 2014 2015 2016 2017 2018 - ------------------------ -------- ------- -------- -------- -------- -------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,668 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 25.5% 23.3% 21.3% 20.7% 19.6% 18.8% Contract Energy Sales (GWh)(4) 2,803 1,680 1,494 1,432 1,296 1,291 Other Energy Sales (GWh)(4) 7,804 7,962 7,338 7,145 6,803 6,477 -------- ------- -------- -------- -------- -------- Total Energy Sales (GWh) 10,606 9,642 8,832 8,577 8,099 7,768 Fuel Consumption (BBtu) 82,119 74,780 69,394 67,533 63,981 61,181 Average Net Heat Rate 7,844 7,859 7,958 7,974 7,997 7,976 (Btu/kWh)(5) SO(2) Allowances Purchased 41 37 35 34 31 31 (Tons)(6) NO(x) Allowances Purchased 32 15 (7) (19) (37) (40) (Tons)(7) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price $ 79.61 88.55 88.55 88.55 88.55 88.55 ($/kW-yr)(9) Contract Energy Price ($/MWh)(10) $ 11.89 11.02 12.47 12.98 13.20 14.50 Other Capacity Price ($/MWh)(11) $ 74.88 74.48 77.98 78.32 79.53 83.65 Other Energy Price ($/MWh)(11) $ 52.31 55.56 57.92 60.04 63.19 64.92 Fuel Price ($/MMBtu)(12) $ 5.20 5.58 5.80 6.03 6.26 6.44 SO(2) Allowances ($/Ton)(13) $ 207 212 218 224 230 236 NO(x) Allowances ($/Ton)(14) $ 2,112 2,169 2,228 2,288 2,350 2,413 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 0 Goat Rock (15) $ 0 0 0 0 0 0 Harris (15) $ 72,851 71,243 71,353 71,308 69,836 71,447 Stanton $ 40,010 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 68,326 65,077 70,126 68,371 66,300 68,690 Goat Rock (15) $262,371 257,549 250,798 251,001 248,170 253,600 Harris $136,852 131,175 128,604 126,979 128,934 132,261 Stanton $ 8,288 86,342 88,611 91,735 98,970 98,253 Wansley $211,948 205,564 204,544 209,919 211,385 208,412 -------- ------- -------- -------- -------- -------- Total Operating Revenues $800,646 816,950 814,036 819,313 823,595 832,663 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 5,123 3,382 4,777 3,687 1,784 1,283 Goat Rock $137,915 133,087 125,870 127,761 124,358 122,242 Harris $ 72,957 67,860 65,658 64,507 65,236 65,436 Stanton $ 4,542 52,159 52,900 54,908 58,852 57,910 Wansley $ 96,916 92,598 89,007 92,750 89,846 85,039 Emissions Allowances $ 73 40 (9) (37) (80) (91) Purchased Power $ 7,022 6,834 6,400 6,350 6,131 6,268 Operations & Maintenance $ 39,787 39,207 39,429 39,936 39,905 40,347 Major Maintenance $ 40,392 36,662 35,506 36,045 36,766 36,214 Administration $ 13,290 13,650 14,016 14,395 14,786 15,186 Insurance $ 3,400 3,493 3,587 3,684 3,784 3,887 Property Taxes $ 13,952 13,986 14,022 14,058 14,096 14,134 Other $ 270 270 270 270 270 270 -------- ------- -------- -------- -------- -------- Total Operating Expenses $435,640 463,229 451,434 458,314 455,736 448,125 NET OPERATING REVENUES ($000) $365,006 353,721 362,602 360,999 367,859 384,538 ANNUAL INTEREST($000) (17) $ 87,938 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE (18) 4.15 4.02 4.12 4.11 4.18 4.37 2002-12 AVG INTEREST COVERAGE (19) 3.47 Year Ending December 31, 2019 2020 2021 2022 - ------------------------ -------- -------- -------- -------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 17.8% 17.7% 16.3% 16.3% Contract Energy Sales (GWh)(4) 393 0 0 0 Other Energy Sales (GWh)(4) 6,885 7,251 6,664 6,664 -------- -------- -------- -------- Total Energy Sales (GWh) 7,279 7,251 6,664 6,664 Fuel Consumption (BBtu) 58,206 58,377 53,784 53,784 Average Net Heat Rate 7,997 8,051 8,071 8,071 (Btu/kWh)(5) SO(2) Allowances Purchased 29 29 27 27 (Tons)(6) NO(x) Allowances Purchased (44) (53) (59) (59) (Tons)(7) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 Contract Capacity Price 22.14 0.00 0.00 0.00 ($/kW-yr)(9) Contract Energy Price ($/MWh)(10) 9.07 0.00 0.00 0.00 Other Capacity Price ($/MWh)(11) 85.52 87.87 89.72 92.15 Other Energy Price ($/MWh)(11) 68.21 70.54 72.47 74.42 Fuel Price ($/MMBtu)(12) 6.63 6.89 7.12 7.28 SO(2) Allowances ($/Ton)(13) 242 249 256 262 NO(x) Allowances ($/Ton)(14) 2,478 2,545 2,614 2,684 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Goat Rock (15) 0 0 0 0 Harris (15) 16,750 0 0 0 Stanton 0 0 0 0 Wansley 0 0 0 0 Other Electricity Revenues Dahlberg 72,231 73,206 75,416 77,454 Goat Rock (15) 255,400 254,815 252,927 259,758 Harris 218,141 272,242 259,630 266,643 Stanton 103,718 106,935 104,976 107,810 Wansley 203,371 214,520 208,830 214,472 -------- -------- -------- -------- Total Operating Revenues 869,611 921,718 901,779 926,137 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 2,712 2,188 2,792 2,867 Goat Rock 119,557 119,782 116,751 119,426 Harris 103,662 131,050 121,162 123,931 Stanton 60,524 62,845 60,540 61,758 Wansley 78,706 86,410 81,720 83,530 Emissions Allowances (106) (129) (150) (153) Purchased Power 0 0 0 0 Operations & Maintenance 41,012 42,018 42,301 43,444 Major Maintenance 35,773 36,685 35,383 36,336 Administration 15,595 16,015 16,447 16,893 Insurance 3,991 4,100 4,210 4,324 Property Taxes 14,174 14,214 14,256 14,299 Other 270 270 270 270 -------- -------- -------- -------- Total Operating Expenses 475,870 515,447 495,682 506,925 NET OPERATING REVENUES ($000) 393,741 406,271 406,097 419,212 ANNUAL INTEREST($000) (17) 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE (18) 4.48 4.62 4.62 4.77 2002-12 AVG INTEREST COVERAGE (19)
A-72 FOOTNOTES TO EXHIBIT A-6 The footnotes to Exhibit A-6 are the same as the footnotes for Exhibit A-1, except: 2. Availability of the Generating Facilities is assumed to be 5 percentage points less than that assumed in the Base Case based on a 5 percentage point increase in the forced outage rate for each of the Generating Facilities. 3. Capacity factor is assumed to decrease such that annual generation for each of the Generating Facilities is reduced by 5 percent from that assumed in the Base Case. A-73 EXHIBIT A-7 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY F - INCREASED HEAT RATE
Year Ending December 31, 2002(1) 2003 2004 2005 2006 2007 - ------------------------ -------- ------- -------- -------- -------- -------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 2,489 4,678 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 37.2% 14.7% 21.0% 25.9% 31.5% 33.5% Contract Energy Sales (GWh)(4) 4,404 5,016 8,263 10,912 13,205 14,039 Other Energy Sales (GWh)(4) 268 1,053 541 0 47 45 -------- ------- -------- -------- -------- -------- Total Energy Sales (GWh) 4,672 6,069 8,804 10,912 13,252 14,084 Fuel Consumption (BBtu) 35,079 48,996 69,726 86,398 104,369 110,190 Average Net Heat Rate (Btu/kWh)(5) 7,406 8,113 8,091 8,136 8,089 8,034 SO(2) Allowances Purchased (Tons)(6) 18 24 35 43 52 54 NO(x) Allowances Purchased (Tons)(7) 0 0 (86) 34 83 100 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 51.53 60.50 70.74 73.59 77.20 77.23 Contract Energy Price ($/MWh)(10) $ 3.74 6.67 6.35 7.41 6.97 6.81 Other Capacity Price ($/MWh)(11) $ 16.49 16.35 16.84 16.38 16.82 17.27 Other Energy Price ($/MWh)(11) $ 34.62 42.40 41.94 0.00 61.96 60.77 Fuel Price ($/MMBtu)(12) $ 6.22 5.53 7.07 0.00 34.44 38.28 SO(2) Allowances ($/Ton)(13) $ 154 158 162 167 171 176 NO(x) Allowances ($/Ton)(14) $ 0 0 2,006 1,707 1,753 1,800 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 29,314 46,845 45,510 2,666 0 0 Goat Rock(15) $ 38,262 80,211 102,843 115,863 118,401 120,799 Harris(15) $ 0 41,885 104,015 130,927 133,940 133,948 Stanton $ 0 9,979 43,224 44,444 44,835 45,119 Wansley $ 67,182 86,422 84,281 88,736 94,110 95,062 Other Electricity Revenues Dahlberg $ 0 0 0 11,886 16,393 16,570 Goat Rock(15) $ 10,188 16,024 9,284 0 0 0 Harris $ 0 38,269 17,711 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 -------- ------- -------- -------- -------- -------- Total Operating Revenues $144,946 319,636 406,868 394,522 407,679 411,498 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 7 0 0 0 1,837 1,861 Goat Rock $ 9,442 14,807 10,420 4,719 5,412 5,909 Harris $ 0 30,450 16,067 4,630 5,492 6,056 Stanton $ 0 455 2,805 2,246 2,219 2,260 Wansley $ 3,292 2,709 2,290 2,972 4,083 4,548 Emissions Allowances $ 0 0 (173) (91) (34) (15) Purchased Power $ 2,712 3,005 7,907 12,547 14,913 16,306 Operations & Maintenance $ 9,572 19,738 28,350 31,352 35,228 37,135 Major Maintenance $ 11,605 17,836 25,034 30,385 36,548 39,529 Administration $ 3,022 7,866 10,457 10,739 11,029 11,328 Insurance $ 756 1,995 2,676 2,748 2,821 2,899 Property Taxes $ 3,566 10,113 13,679 13,706 13,734 13,762 Other $ 90 216 270 270 270 270 -------- ------- -------- -------- -------- -------- Total Operating Expenses $ 44,065 109,189 119,784 116,223 133,552 141,848 NET OPERATING REVENUES ($000) $100,881 210,447 287,084 278,300 274,127 269,651 ANNUAL INTEREST($000)(17) $ 20,964 66,271 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 4.81 3.18 3.26 3.16 3.12 3.07 2002-12 AVG INTEREST COVERAGE(19) 3.42 Year Ending December 31, 2008 2009 2010 2011 2012 - ------------------------ -------- -------- ------- ------- -------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 31.5% 32.4% 32.2% 30.9% 29.6% Contract Energy Sales (GWh)(4) 13,229 13,543 7,180 4,131 3,314 Other Energy Sales (GWh)(4) 44 98 6,195 8,623 8,942 -------- -------- ------- ------- -------- Total Energy Sales (GWh) 13,273 13,640 13,375 12,754 12,256 Fuel Consumption (BBtu) 104,550 107,559 107,399 103,065 99,430 Average Net Heat Rate (Btu/kWh)(5) 8,089 8,095 8,132 8,150 8,183 SO(2) Allowances Purchased (Tons)(6) 53 54 53 51 51 NO(x) Allowances Purchased (Tons)(7) 91 90 101 94 90 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 77.26 77.28 40.00 60.62 84.98 Contract Energy Price ($/MWh)(10) 7.44 7.48 8.11 11.21 10.33 Other Capacity Price ($/MWh)(11) 51.65 51.68 60.96 66.92 71.14 Other Energy Price ($/MWh)(11) 61.12 65.13 48.21 49.51 50.91 Fuel Price ($/MMBtu)(12) 38.68 20.49 4.81 4.84 4.99 SO(2) Allowances ($/Ton)(13) 181 186 191 196 201 NO(x) Allowances ($/Ton)(14) 1,849 1,899 1,950 2,002 2,057 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Goat Rock(15) 120,373 122,063 79,486 24,459 0 Harris(15) 136,630 135,212 87,426 72,017 72,338 Stanton 45,554 46,021 46,331 46,458 46,800 Wansley 95,352 97,508 0 0 0 Other Electricity Revenues Dahlberg 44,122 47,808 57,322 64,136 67,506 Goat Rock(15) 0 0 87,654 224,321 275,993 Harris 0 0 94,299 141,055 142,338 Stanton 0 0 0 0 0 Wansley 0 0 225,029 231,031 231,168 -------- -------- ------- ------- -------- Total Operating Revenues 442,031 448,612 677,547 803,477 836,143 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 1,871 4,263 5,683 7,175 6,852 Goat Rock 5,830 6,230 54,323 126,376 154,567 Harris 5,938 6,209 58,707 83,068 83,419 Stanton 2,265 2,157 2,156 2,127 2,117 Wansley 4,439 4,951 122,300 120,604 117,258 Emissions Allowances (24) (21) 193 194 192 Purchased Power 15,856 16,830 8,255 5,588 5,585 Operations & Maintenance 37,200 39,177 40,334 40,963 41,271 Major Maintenance 38,745 40,454 42,286 46,076 41,444 Administration 11,633 11,946 12,270 12,599 12,942 Insurance 2,978 3,057 3,140 3,224 3,311 Property Taxes 13,792 13,822 13,853 13,885 13,918 Other 270 270 270 270 270 -------- -------- ------- ------- -------- Total Operating Expenses 140,793 149,343 363,770 462,150 483,145 NET OPERATING REVENUES ($000) 301,238 299,269 313,777 341,327 352,998 ANNUAL INTEREST($000)(17) 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 3.43 3.40 3.57 3.88 4.01 2002-12 AVG INTEREST COVERAGE(19)
A-74 EXHIBIT A-7 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY F - INCREASED HEAT RATE
Year Ending December 31, 2013 2014 2015 2016 2017 2018 - ------------------------ -------- ------- -------- -------- -------- -------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,668 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 26.9% 24.5% 22.5% 21.8% 20.6% 19.8% Contract Energy Sales (GWh)(4) 2,803 1,680 1,494 1,432 1,296 1,291 Other Energy Sales (GWh)(4) 8,281 8,395 7,737 7,533 7,172 6,829 -------- ------- -------- -------- -------- -------- Total Energy Sales (GWh) 11,084 10,075 9,231 8,965 8,469 8,120 Fuel Consumption (BBtu) 90,913 82,784 76,822 74,762 70,830 67,731 Average Net Heat Rate (Btu/kWh)(5) 8,236 8,251 8,356 8,373 8,396 8,375 SO(2) Allowances Purchased (Tons)(6) 46 41 39 37 34 34 NO(x) Allowances Purchased (Tons)(7) 65 45 22 9 (11) (15) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 79.61 88.55 88.55 88.55 88.55 88.55 Contract Energy Price ($/MWh)(10) $ 11.92 11.02 12.47 12.98 13.20 14.50 Other Capacity Price ($/MWh)(11) $ 74.88 74.48 77.98 78.32 79.53 83.65 Other Energy Price ($/MWh)(11) $ 52.34 55.56 57.92 60.04 63.19 64.92 Fuel Price ($/MMBtu)(12) $ 5.20 5.52 5.72 5.96 6.19 6.37 SO(2) Allowances ($/Ton)(13) $ 207 212 218 224 230 236 NO(x) Allowances ($/Ton)(14) $ 2,112 2,169 2,228 2,288 2,350 2,413 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 0 Goat Rock(15) $ 0 0 0 0 0 0 Harris(15) $ 72,851 71,243 71,353 71,308 69,836 71,447 Stanton $ 40,086 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 68,758 65,363 70,529 68,676 66,445 68,791 Goat Rock(15) $271,900 266,857 259,513 259,723 256,662 262,136 Harris $141,858 135,894 133,067 131,352 133,374 136,753 Stanton $ 11,653 89,439 91,775 95,005 102,605 101,731 Wansley $218,882 212,190 210,896 216,560 218,032 214,655 -------- ------- -------- -------- -------- -------- Total Operating Revenues $825,988 840,986 837,133 842,624 846,954 855,513 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 5,673 3,733 5,284 4,077 1,972 1,420 Goat Rock $150,415 145,022 136,984 139,025 135,384 133,317 Harris $ 82,593 76,811 74,123 72,839 73,464 73,993 Stanton $ 9,562 56,093 56,912 59,136 63,507 62,460 Wansley $105,203 100,417 96,487 100,851 97,764 92,572 Emissions Allowances $ 143 106 55 26 (20) (30) Purchased Power $ 2,341 2,278 2,133 2,117 2,044 2,089 Operations & Maintenance $ 40,586 39,938 40,135 40,627 40,559 40,983 Major Maintenance $ 41,406 37,592 36,561 37,978 37,710 37,110 Administration $ 13,290 13,650 14,016 14,395 14,786 15,186 Insurance $ 3,400 3,493 3,587 3,684 3,784 3,887 Property Taxes $ 13,952 13,986 14,022 14,058 14,096 14,134 Other $ 270 270 270 270 270 270 -------- ------- -------- -------- -------- -------- Total Operating Expenses $468,834 493,391 480,569 489,084 485,321 477,391 NET OPERATING REVENUES ($000) $357,153 347,595 356,564 353,540 361,633 378,122 ANNUAL INTEREST($000)(17) $ 87,938 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 4.06 3.95 4.05 4.02 4.11 4.30 2002-12 AVG INTEREST COVERAGE(19) 3.42 Year Ending December 31, 2019 2020 2021 2022 - ------------------------ -------- -------- -------- -------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 18.8% 18.7% 17.2% 17.2% Contract Energy Sales (GWh)(4) 393 0 0 0 Other Energy Sales (GWh)(4) 7,281 7,645 7,026 7,026 -------- -------- -------- -------- Total Energy Sales (GWh) 7,674 7,645 7,026 7,026 Fuel Consumption (BBtu) 64,438 64,628 59,542 59,542 Average Net Heat Rate (Btu/kWh)(5) 8,397 8,453 8,474 8,474 SO(2) Allowances Purchased (Tons)(6) 32 32 29 29 NO(x) Allowances Purchased (Tons)(7) (21) (31) (36) (36) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 22.14 0.00 0.00 0.00 Contract Energy Price ($/MWh)(10) 9.07 0.00 0.00 0.00 Other Capacity Price ($/MWh)(11) 85.52 87.87 89.72 92.15 Other Energy Price ($/MWh)(11) 68.21 70.54 72.47 74.42 Fuel Price ($/MMBtu)(12) 6.54 6.78 7.00 7.16 SO(2) Allowances ($/Ton)(13) 242 249 256 262 NO(x) Allowances ($/Ton)(14) 2,478 2,545 2,614 2,684 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Goat Rock(15) 0 0 0 0 Harris(15) 16,750 0 0 0 Stanton 0 0 0 0 Wansley 0 0 0 0 Other Electricity Revenues Dahlberg 72,445 73,371 75,626 77,671 Goat Rock(15) 263,922 263,158 261,061 268,112 Harris 226,790 281,380 267,973 275,211 Stanton 107,421 110,763 108,620 111,553 Wansley 209,232 220,843 214,741 220,541 -------- -------- -------- -------- Total Operating Revenues 896,560 949,515 928,021 953,088 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 3,001 2,419 3,092 3,176 Goat Rock 130,469 130,715 127,352 130,313 Harris 115,133 143,091 132,145 135,210 Stanton 65,355 67,923 65,369 66,718 Wansley 85,565 94,096 88,902 90,906 Emissions Allowances (45) (70) (89) (92) Purchased Power 0 0 0 0 Operations & Maintenance 41,642 42,659 42,912 44,072 Major Maintenance 36,643 37,586 36,218 37,196 Administration 15,595 16,015 16,447 16,893 Insurance 3,991 4,100 4,210 4,324 Property Taxes 14,174 14,214 14,256 14,299 Other 270 270 270 270 -------- -------- -------- -------- Total Operating Expenses 511,793 553,018 531,083 543,285 NET OPERATING REVENUES ($000) 384,767 396,497 396,938 409,803 ANNUAL INTEREST($000)(17) 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 4.38 4.51 4.51 4.66 2002-12 AVG INTEREST COVERAGE(19)
A-75 FOOTNOTES TO EXHIBIT A-7 The footnotes to Exhibit A-7 are the same as the footnotes for Exhibit A-1, except: 4. Heat rate for each of the Generating Facilities is assumed to be 5 percent higher than that assumed in the Base Case. A-76 EXHIBIT A-8 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY G - INCREASED OPERATING EXPENSES
Year Ending December 31, 2002(1) 2003 2004 2005 2006 2007 - ----------------------- -------- ------- -------- -------- -------- -------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 2,489 4,678 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 37.2% 14.7% 21.0% 25.9% 31.5% 33.5% Contract Energy Sales (GWh)(4) 4,404 5,016 8,263 10,912 13,205 14,039 Other Energy Sales (GWh)(4) 268 1,053 541 0 47 45 -------- ------- -------- -------- -------- -------- Total Energy Sales (GWh) 4,672 6,069 8,804 10,912 13,252 14,084 Fuel Consumption (BBtu) 33,408 46,663 66,407 82,283 99,399 104,941 Average Net Heat Rate (Btu/kWh)(5) 7,053 7,727 7,706 7,749 7,704 7,652 SO(2) Allowances Purchased (Tons)(6) 17 23 32 41 50 53 NO(x) Allowances Purchased (Tons)(7) 0 0 (95) 19 66 83 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 51.53 60.50 70.74 73.59 77.20 77.23 Contract Energy Price ($/MWh)(10) $ 3.72 6.65 6.32 7.38 6.95 6.78 Other Capacity Price ($/MWh)(11) $ 16.49 16.35 16.84 16.38 16.82 17.27 Other Energy Price ($/MWh)(11) $ 34.62 42.40 41.94 0.00 61.96 60.77 Fuel Price ($/MMBtu)(12) $ 3.94 4.83 4.61 0.00 3.32 3.45 SO(2) Allowances ($/Ton)(13) $ 154 158 162 167 171 176 NO(x) Allowances ($/Ton)(14) $ 0 0 2,006 1,707 1,753 1,800 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 29,314 46,845 45,510 2,666 0 0 Goat Rock (15) $ 38,262 80,211 102,807 115,807 118,340 120,728 Harris (15) $ 0 41,860 103,979 130,878 133,881 133,884 Stanton $ 0 9,970 43,098 44,343 44,734 45,020 Wansley $ 67,098 86,353 84,225 88,659 94,005 94,945 Other Electricity Revenues Dahlberg $ 0 0 0 11,886 16,393 16,570 Goat Rock (15) $ 10,188 16,024 9,284 0 0 0 Harris $ 0 38,269 17,711 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 -------- ------- -------- -------- -------- -------- Total Operating Revenues $144,862 319,533 406,614 394,239 407,353 411,147 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 0 0 0 0 1,747 1,771 Goat Rock $ 7,677 12,076 6,935 0 0 0 Harris $ 0 28,273 12,714 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Emissions Allowances $ 0 0 (191) (108) (55) (34) Purchased Power $ 2,712 3,005 7,907 12,547 14,913 16,306 Operations & Maintenance $ 10,530 21,715 31,189 34,486 38,751 40,849 Major Maintenance $ 12,766 19,618 27,538 33,424 40,203 43,482 Administration $ 3,326 8,653 11,504 11,815 12,133 12,460 Insurance $ 831 2,194 2,944 3,022 3,105 3,189 Property Taxes $ 3,924 11,125 15,045 15,075 15,106 15,138 Other $ 99 238 296 296 296 296 -------- ------- -------- -------- -------- -------- Total Operating Expenses $ 41,865 106,897 115,881 110,556 126,200 133,457 NET OPERATING REVENUES ($000) $102,997 212,636 290,733 283,683 281,154 277,690 ANNUAL INTEREST($000) (17) $ 20,964 66,271 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE (18) 4.91 3.21 3.31 3.23 3.20 3.16 2002-12 AVG INTEREST COVERAGE (19) 3.50 Year Ending December 31, 2008 2009 2010 2011 2012 - ----------------------- -------- -------- ------- ------- -------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,678 4,678 4,678 4,678 Average Capacity Factor (%)(3) 31.5% 32.4% 32.2% 30.9% 29.6% Contract Energy Sales (GWh)(4) 13,229 13,543 7,180 4,131 3,314 Other Energy Sales (GWh)(4) 44 98 6,195 8,623 8,942 -------- -------- ------- ------- -------- Total Energy Sales (GWh) 13,273 13,640 13,375 12,754 12,256 Fuel Consumption (BBtu) 99,572 102,438 102,287 98,157 94,697 Average Net Heat Rate (Btu/kWh)(5) 7,704 7,710 7,745 7,762 7,794 SO(2) Allowances Purchased (Tons)(6) 50 51 51 49 48 NO(x) Allowances Purchased (Tons)(7) 74 72 83 77 73 COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 77.26 77.28 40.00 60.62 84.98 Contract Energy Price ($/MWh)(10) 7.42 7.45 8.10 11.19 10.30 Other Capacity Price ($/MWh)(11) 51.65 51.68 60.96 66.92 71.14 Other Energy Price ($/MWh)(11) 61.12 65.13 48.21 49.51 50.91 Fuel Price ($/MMBtu)(12) 3.56 3.67 4.63 4.78 4.95 SO(2) Allowances ($/Ton)(13) 181 186 191 196 201 NO(x) Allowances ($/Ton)(14) 1,849 1,899 1,950 2,002 2,057 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Goat Rock (15) 120,302 121,990 79,486 24,459 0 Harris (15) 136,567 135,147 87,426 72,017 72,338 Stanton 45,450 45,922 46,232 46,361 46,701 Wansley 95,237 97,381 0 0 0 Other Electricity Revenues Dahlberg 44,122 47,808 57,322 64,136 67,506 Goat Rock (15) 0 0 87,654 224,321 275,993 Harris 0 0 94,299 141,055 142,338 Stanton 0 0 0 0 0 Wansley 0 0 225,029 231,031 231,168 -------- -------- ------- ------- -------- Total Operating Revenues 441,678 448,248 677,448 803,380 836,044 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 1,782 4,057 5,413 6,835 6,530 Goat Rock 0 0 47,765 120,080 148,195 Harris 0 0 52,219 76,505 76,796 Stanton 0 0 0 0 0 Wansley 0 0 117,408 115,791 112,603 Emissions Allowances (44) (45) 163 160 156 Purchased Power 15,856 16,830 8,255 5,588 5,585 Operations & Maintenance 40,924 43,094 44,366 45,060 45,397 Major Maintenance 42,619 44,496 46,514 50,682 45,587 Administration 12,797 13,141 13,498 13,862 14,235 Insurance 3,275 3,364 3,455 3,549 3,645 Property Taxes 15,170 15,203 15,237 15,273 15,309 Other 296 296 296 296 296 -------- -------- ------- ------- -------- Total Operating Expenses 132,675 140,436 354,589 453,681 474,335 NET OPERATING REVENUES ($000) 309,003 307,812 322,859 349,698 361,709 ANNUAL INTEREST($000) (17) 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE (18) 3.51 3.50 3.67 3.98 4.11 2002-12 AVG INTEREST COVERAGE (19)
A-77 EXHIBIT A-8 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY G - INCREASED OPERATING EXPENSES
Year Ending December 31, 2013 2014 2015 2016 2017 2018 - ------------------------ -------- ------- -------- -------- -------- -------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,678 4,668 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 26.9% 24.5% 22.5% 21.8% 20.6% 19.8% Contract Energy Sales (GWh)(4) 2,803 1,680 1,494 1,432 1,296 1,291 Other Energy Sales (GWh)(4) 8,281 8,395 7,737 7,533 7,172 6,829 -------- ------- -------- -------- -------- -------- Total Energy Sales (GWh) 11,084 10,075 9,231 8,965 8,469 8,120 Fuel Consumption (BBtu) 86,581 78,843 73,165 71,203 67,456 64,506 Average Net Heat Rate (Btu/kWh)(5) 7,844 7,859 7,958 7,974 7,996 7,976 SO(2) Allowances Purchased (Tons)(6) 43 39 37 34 34 32 NO(x) Allowances Purchased (Tons)(7) 48 31 7 (5) (23) (29) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) $ 79.61 88.55 88.55 88.55 88.55 88.55 Contract Energy Price ($/MWh)(10) $ 11.92 11.02 12.47 12.98 13.20 14.50 Other Capacity Price ($/MWh)(11) $ 74.88 74.48 77.98 78.32 79.53 83.65 Other Energy Price ($/MWh)(11) $ 52.34 55.56 57.92 60.04 63.19 64.92 Fuel Price ($/MMBtu)(12) $ 5.17 5.52 5.74 5.97 6.20 6.38 SO(2) Allowances ($/Ton)(13) $ 207 212 218 224 230 236 NO(x) Allowances ($/Ton)(14) $ 2,112 2,169 2,228 2,288 2,350 2,413 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 0 Goat Rock(15) $ 0 0 0 0 0 0 Harris(15) $ 72,851 71,243 71,353 71,308 69,836 71,447 Stanton $ 40,086 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 68,758 65,363 70,529 68,676 66,445 68,791 Goat Rock(15) $271,900 266,857 259,513 259,723 256,662 262,136 Harris $141,858 135,894 133,067 131,352 133,374 136,753 Stanton $ 11,653 89,439 91,775 95,005 102,605 101,731 Wansley $218,882 212,190 210,896 216,560 218,032 214,655 -------- ------- -------- -------- -------- -------- Total Operating Revenues $825,988 840,986 837,133 842,624 846,954 855,513 OPERATING EXPENSES ($000)(16) Fuel Dahlberg $ 5,398 3,557 5,036 3,886 1,875 1,352 Goat Rock $144,260 139,150 131,512 133,474 129,954 127,866 Harris $ 76,321 70,936 68,599 67,375 68,128 68,423 Stanton $ 7,449 54,155 54,935 57,058 61,212 60,221 Wansley $101,122 96,568 92,806 96,861 93,865 88,860 Emissions Allowances $ 109 73 24 (5) (50) (61) Purchased Power $ 2,341 2,278 2,133 2,117 2,044 2,089 Operations & Maintenance $ 44,639 43,932 44,151 44,690 44,613 45,079 Major Maintenance $ 45,547 41,352 40,218 41,776 41,480 40,819 Administration $ 14,618 15,014 15,418 15,836 16,264 16,704 Insurance $ 3,742 3,842 3,946 4,053 4,162 4,274 Property Taxes $ 15,346 15,384 15,423 15,463 15,504 15,546 Other $ 296 296 296 296 296 296 -------- ------- -------- -------- -------- -------- Total Operating Expenses $461,189 486,538 474,498 482,880 479,349 471,468 NET OPERATING REVENUES ($000) $364,799 354,448 362,635 359,744 367,605 384,045 ANNUAL INTEREST($000) (17) $ 87,938 87,938 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE (18) 4.15 4.03 4.12 4.09 4.18 4.37 2002-12 AVG INTEREST COVERAGE (19) 3.50 Year Ending December 31, 2019 2020 2021 2022 - ------------------------ -------- -------- -------- -------- CONSOLIDATED PERFORMANCE Annual Average Capacity (MW)(2) 4,668 4,668 4,668 4,668 Average Capacity Factor (%)(3) 18.8% 18.7% 17.2% 17.2% Contract Energy Sales (GWh)(4) 393 0 0 0 Other Energy Sales (GWh)(4) 7,281 7,645 7,026 7,026 -------- -------- -------- -------- Total Energy Sales (GWh) 7,674 7,645 7,026 7,026 Fuel Consumption (BBtu) 61,368 61,548 56,707 56,707 Average Net Heat Rate (Btu/kWh)(5) 7,997 8,050 8,071 8,071 SO(2) Allowances Purchased (Tons)(6) 30 30 28 28 NO(x) Allowances Purchased (Tons)(7) (32) (41) (48) (48) COMMODITY PRICES General Inflation (%)(8) 2.70 2.70 2.70 2.70 Contract Capacity Price ($/kW-yr)(9) 22.14 0.00 0.00 0.00 Contract Energy Price ($/MWh)(10) 9.07 0.00 0.00 0.00 Other Capacity Price ($/MWh)(11) 85.52 87.87 89.72 92.15 Other Energy Price ($/MWh)(11) 68.21 70.54 72.47 74.42 Fuel Price ($/MMBtu)(12) 6.57 6.83 7.06 7.22 SO(2) Allowances ($/Ton)(13) 242 249 256 262 NO(x) Allowances ($/Ton)(14) 2,478 2,545 2,614 2,684 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Goat Rock(15) 0 0 0 0 Harris(15) 16,750 0 0 0 Stanton 0 0 0 0 Wansley 0 0 0 0 Other Electricity Revenues Dahlberg 72,445 73,371 75,626 77,671 Goat Rock(15) 263,922 263,158 261,061 268,112 Harris 226,790 281,380 267,973 275,211 Stanton 107,421 110,763 108,620 111,553 Wansley 209,232 220,843 214,741 220,541 -------- -------- -------- -------- Total Operating Revenues 896,560 949,515 928,021 953,088 OPERATING EXPENSES ($000)(16) Fuel Dahlberg 2,856 2,301 2,942 3,022 Goat Rock 125,097 125,325 122,136 124,957 Harris 109,565 137,165 126,738 129,657 Stanton 62,975 65,417 62,988 64,273 Wansley 82,184 90,313 85,366 87,275 Emissions Allowances (74) (99) (118) (122) Purchased Power 0 0 0 0 Operations & Maintenance 45,803 46,924 47,205 48,481 Major Maintenance 40,307 41,345 39,840 40,916 Administration 17,153 17,617 18,092 18,582 Insurance 4,390 4,508 4,632 4,757 Property Taxes 15,590 15,634 15,680 15,727 Other 296 296 296 296 -------- -------- -------- -------- Total Operating Expenses 506,141 546,746 525,796 537,820 NET OPERATING REVENUES ($000) 390,419 402,769 402,225 415,268 ANNUAL INTEREST($000)(17) 87,938 87,938 87,938 87,938 ANNUAL INTEREST COVERAGE(18) 4.44 4.58 4.57 4.72 2002-12 AVG INTEREST COVERAGE(19)
A-78 FOOTNOTES TO EXHIBIT A-8 The footnotes to Exhibit A-8 are the same as the footnotes for Exhibit A-1, except: 13. Assumed to be 10 percent higher than that assumed in the Base Case. 14. Assumed to be 10 percent higher than that assumed in the Base Case. 16. Assumed to be 10 percent higher than that assumed in the Base Case. A-79 ANNEX B SOUTHERN POWER Independent Market Expert's Report for the SERC and FRCC Regions June 5, 2002 B-1 SOUTHERN POWER Independent Market Expert's Report for the SERC and FRCC Regions June 5, 2002 Company Confidential (C) PA Knowledge Limited 2002 PA Consulting Group, Inc. 390 Interlocken Crescent Prepared by: Todd Filsinger Suite 410 Broomfield Colorado 80021 Tel: +1 720 566 9920 Fax: +1 720 566 9680 www.paconsulting.com Southern Power - June 5, 2002 DISCLAIMER This report presents the analysis of PA Consulting Group, Inc. (PA) for the following regions: - SERC - Southeastern Electric Reliability Council - FRCC - Florida Reliability Coordinating Council (i) some information in the report is necessarily based on predictions and estimates of future events and behaviors, (ii) such predictions or estimates may differ from that which other experts specializing in the electricity industry might present, (iii) the provision of a report by PA does not obviate the need for potential investors to make further appropriate inquiries as to the accuracy of the information included therein, or to undertake an analysis of their own, (iv) this report is not intended to be a complete and exhaustive analysis of the subject issues and therefore will not consider some factors that are important to a potential investor's decision making, and (v) PA and its employees cannot accept liability for loss suffered in consequence of reliance on the report. Nothing in PA's report should be taken as a promise or guarantee as to the occurrence of any future events. Southern Power - June 5, 2002 i This page intentionally left blank. ii Southern Power - June 5, 2002 TABLE OF CONTENTS [PA LOGO] DISCLAIMER i 1. INTRODUCTION 1-1 1.1 Background 1-1 1.2 Asset Portfolio Description 1-1 1.3 Key Assumptions 1-1 1.4 Results 1-2 1.5 Report Structure 1-4 2. COMPETITION AND RESTRUCTURING IN THE U.S. ELECTRIC INDUSTRY 2-1 2.1 Introduction 2-1 2.2 Recent Federal Restructuring 2-1 2.2.1 FERC Order 2000 2-1 2.2.2 SAFE Act of 2001 2-1 2.2.3 Energy Policy Act of 2002 2-1 2.2.4 The Prospect for Legislation in 2002 2-2 2.3 State Restructuring 2-2 2.3.1 Alabama 2-2 2.3.2 Florida 2-4 2.3.3 Georgia 2-4 2.4 Reliability and Competitive Markets 2-5 2.4.1 Introduction 2-5 2.4.2 Overview of Regional Markets 2-5 2.4.3 Power Pools 2-6 2.4.4 ISOs -- Independent System Operators 2-6 2.4.5 RTOs -- Regional Transmission Organizations 2-6 2.4.6 Additional RTO-Related Actions by FERC 2-9 3. APPROACH TO MARKET PRICE FORECASTING 3-1 3.1 Introduction 3-1 3.2 Market Price Forecasting Principles 3-2 3.2.1 Economic Equilibrium 3-2 3.2.2 Capacity and Energy Markets 3-3 3.2.3 Price Bidding and Formulation 3-4 3.3 Step 1 - Review of Market Characteristics 3-5 3.4 Step 2 - Development of Assumptions 3-5 3.5 Step 3 - Fundamental Analysis 3-5 3.5.1 Energy Price and Dispatch Simulation 3-6 3.5.2 Capacity Compensation Simulation 3-6 3.5.3 Capacity Add/Retire Simulation 3-6 3.6 Step 4 - Plant-Level Dispatch Analysis 3-8
Southern Power - June 5, 2002 iii Table of Contents 4. KEY ASSUMPTIONS 4-1 4.1 Introduction 4-1 4.2 Demand and Energy Forecasts 4-1 4.3 Fuel Prices 4-1 4.3.1 Natural Gas 4-2 4.3.2 Fuel Oil 4-4 4.3.3 Coal 4-5 4.3.4 Hydroelectric 4-7 4.3.5 Nuclear 4-7 4.4 SO(2)/NO(x) Emission Allowance Prices 4-7 4.4.1 Sulfur Dioxide Emission Allowance Prices 4-7 4.4.2 Development of NO(x) Emission Allowance Prices 4-8 4.5 Electricity Imports 4-9 4.5.1 Transfer Capabilities 4-9 4.5.2 Wheeling Rates 4-10 4.6 Capacity Additions and Retirements 4-10 4.7 Financial Assumptions 4-13 4.7.1 Generic Plant Characteristics 4-13 4.7.2 Other Expenses 4-13 4.7.3 Economic and Financial Assumptions 4-13 5. REGIONAL ANALYSIS 5-1 5.1 Introduction 5-1 5.2 Risk Issues and Sensitivity Cases 5-1 5.3 SERC 5-3 5.3.1 Background 5-3 5.3.2 Power Markets 5-3 5.3.3 Transmission System 5-3 5.3.4 Market Characteristics 5-4 5.3.5 Price Forecasts 5-5 5.3.6 Critical Market Factors 5-8 5.3.7 Dispatch Curves 5-9 5.4 FRCC 5-10 5.4.1 Background 5-10 5.4.2 Power Markets 5-10 5.4.3 Transmission System 5-10 5.4.4 Market Characteristics 5-11 5.4.5 Price Forecasts 5-12 5.4.6 Critical Market Factors 5-15 5.4.7 Dispatch Curves 5-16
iv Southern Power - June 5, 2002 1. INTRODUCTION 1.1 BACKGROUND PA Consulting Group, Inc. (PA) was retained by Southern Power to assess future prices for electric energy and capacity in the markets in which Southern Power owns, has rights to, or is developing generating assets, as shown in Table 1-1. The markets analyzed in this report include: - - SERC - Southeastern Electric Reliability Council - - FRCC - Florida Reliability Coordinating Council. This report assesses the price projections based on stated assumptions for electric prices in the markets mentioned above and presents the results of PA's analysis for the study period 2002-2021. The actual unit specific results were provided to the independent engineer (R.W. Beck) for inclusion in the financial projections for the years 2002-2022. The results for the final year, 2022, were held constant in real terms from the projections for 2021. 1.2 ASSET PORTFOLIO DESCRIPTION Southern Power owns or has ownership interests in FIGURE 1-1 SOUTHERN POWER ASSETS IN GENERATION PORTFOLIO [MAP] companies with 4,777 MW of generation capacity, as summarized in Figure 1-1 and Table 1-1.
TABLE 1-1 REGIONAL MARKET LOCATION OF SOUTHERN POWER GENERATING ASSETS - ---------------------------------------------------------- REGIONAL ASSET TYPE TOTAL CAPACITY(1) MARKET DISTRIBUTION (MW) - --------------------------------------------------------- SERC Gas/Oil - 100% 4,366 FRCC Gas/Oil - 100% 633(2)
(1) Capacity rating at 70 degrees Fahrenheit. (2) Southern Power owns a 65% interest (or 411 MW) in the Stanton facility. 1.3 KEY ASSUMPTIONS There are many important assumptions in the development of the price projections, including but not limited to demand growth, fuel prices, and capacity additions and retirements. Variations in these three factors, as well as other assumptions, can lead to significant variations in the end price results. PA has tested the forecasts presented herein for variations of these three assumptions, which represent the high fuel, low fuel, and overbuild sensitivity cases analyzed in Chapter 5. Another key fundamental assumption on which this analysis is based is the concept of a competitive wholesale market. These results are based on the assumptions that rational markets for electricity exist, that markets are attempting to adjust to economic equilibrium, and that market players make decisions based on sound economic judgment. DEMAND. Peak demand in the regions is forecasted to grow from 2002 through 2021 at annual compound growth rates of approximately(1): SERC 2.0% FRCC 2.3% (1) Source: EIA Annual Energy Outlook 2002. Southern Power - June 5, 2002 1-1 FUEL PRICES. Futures prices in the near term and a consensus fuel price forecast (derived from published fuel price forecasts) in the long term were utilized to develop fuel price forecasts for natural gas and oil. (See Chapter 4.) The marginal nuclear fuel costs were assumed to be $5.70/MWh, while the marginal coal prices were developed for each individual unit. CAPACITY ADDITIONS AND RETIREMENTS. PA estimates capacity additions and retirements based on three main principles. First, near-term (2002 through 2004) capacity additions are based upon PA's investigation of new capacity addition announcements through a review of publicly available sources of new capacity addition information. These sources include newspapers, trade journals, developer and utility web sites and contacts, and industry news publications. PA has developed a proprietary database that tracks the status of new capacity additions and evaluates the probability of announced projects actually being constructed. Second, capacity additions post-2005 are based on economic analyses of generic new units. Third, units that are not competitive are retired in accordance with the methodology described in further detail in Chapter 3. PA's base case results incorporate PA's best estimate of new capacity additions and retirements. The capacity and online dates for specific projects are identified in Chapter 4. These unit assumptions are based on PA's best estimate at the time the analyses are prepared. Due to deregulation of the electric industry, changes in economic conditions, the sometimes volatile nature of the industry, and the lead times associated with building new plants, these assumptions are likely to deviate from what actually transpires. Individual unit characteristics such as online dates and capacities may change. Projects may be cancelled or new ones may be added. The assumed capacity additions and retirements included in this analysis are summarized in Table 1-2.
- ------------------------------------------------------------------ TABLE 1-2 CAPACITY ADDITIONS AND RETIREMENTS(1) - ------------------------------------------------------------------ REGION CAPACITY CAPACITY CAPACITY ADDITIONS ADDITIONS RETIREMENTS 2002-2004 (MW) 2005-2021 (MW) 2002-2021 (MW) - ------------------------------------------------------------------ SERC 33,061 61,310 8,413 FRCC 7,015 26,155 98
(1) Total capacity at the end of 2001 in each region was: SERC 178,283 MW FRCC 41,548 MW
A more complete discussion of the three key assumptions of demand growth, fuel prices, and capacity additions and retirements may be found in Chapter 4. 1.4 RESULTS PA modeled the generation asset portfolio under alternative price and capacity scenarios. Before summarizing these scenarios, it is important to acknowledge that this portfolio valuation approach incorporates a conservative view on asset and portfolio management. In other words, PA simplifies real world asset and portfolio management decision-making by excluding the potential for incremental returns and corresponding risk enabled through dynamic portfolio optimization strategies and techniques. PA has adopted this view for three reasons: 1. Dynamic portfolio optimization assumes a fairly high degree of decision-making sophistication that requires state-of-the-art tools, systems, and risk management acumen. Assessing this type of risk and portfolio decision-making capacity is not part of this report. Implementing an aggressive portfolio optimization strategy with a weak risk management framework can degrade rather than improve returns. 2. Portfolio optimization modeling is a complex analysis that attracts significant debate across the industry. This analytical complexity and the lack of an industry-accepted standard to quantify such value and risk would prevent a report, which attempts to include such value, from meeting objectives set forth by financial institutions for integrity and expert opinion. 3. Portfolio optimization modeling results are driven by market data (e.g., historic spot, volatility, and forwards) that often do not exist or that require a fair amount of extrapolation to create a useful data set. PA's approach of creating a forecast to better represent a given market over a given time horizon than a single snapshot of forward market data is not conducive to portfolio optimization analysis. While PA has adopted this conservative position, we recognize that it is possible for asset owners to generate incremental portfolio returns above and beyond the compensation mechanisms contemplated in this analysis if supported by a best-practice risk and portfolio management framework. 1-2 Southern Power - June 5, 2002 Using the assumptions presented in Chapter 4, PA developed a base case for each region that reflects PA's assessment, given the stated set of assumptions in Chapter 4, of future market prices. It should be recognized that these cases will vary to the extent the input assumptions change, and such assumptions should be reviewed with the same rigor as the resulting forecast. The base case is described below: - - The BASE CASE incorporates the actual futures gas prices through December 2004 (2003 for oil). Prices then decrease linearly to the consensus forecast price in years 2006 (2005 for oil). The base case is constructed using generation and load growth data stated in the EIA Forms 411 combined with PA's merchant plant and in-house fuel forecast. This method is discussed in further detail in Chapter 4. In addition to the base case, PA developed three sensitivity cases. These sensitivity cases are intended to provide an indication as to how changes in certain input parameters such as fuel prices and new capacity additions affect forecasted price results. These sensitivities are not intended to be bounding, or worst case scenarios. Their purpose is to determine the impact of an assumed change on the price forecast results. The magnitude of the changes in input parameters may be greater than or less than those assumed in the sensitivities. The three sensitivity cases evaluated are as follows: - - The LOW FUEL CASE evaluates the effects of lower gas and oil prices represented as a $0.50/MMBtu reduction in the 2002 consensus gas and oil prices with escalation remaining unchanged (coal prices are not changed). - - The HIGH FUEL CASE evaluates the effects of higher gas and oil prices represented as a $0.50/MMBtu increase in the 2002 gas and oil prices with escalation remaining unchanged. - - The OVERBUILD CASE evaluates an over-exuberance of merchant plant development in the regions reviewed. In addition to the base case merchant capacity, the overbuild case assumes that additional capacity is constructed:
------------- --------------- --------------- 2003 2004 ------------- --------------- --------------- SERC 8,135 MW 2,425 MW FRCC 5,700 MW 1,560 MW
Gross revenue is total revenue minus variable costs (including fixed fuel). Figure 1-2 shows the proportion of projected gross revenues for each region while Figure 1-3 shows the percentage difference in terms of gross revenues for each sensitivity case as compared to the base case. FIGURE 1-2 SUMMARY OF PROJECTED GROSS REVENUES (BASE CASE)(1) [CHART] FIGURE 1-3 GROSS REVENUES (% CHANGE FROM BASE CASE)(1) [CHART] Southern Power - June 5, 2002 1-3 FIGURE 1-4 AVERAGE REGIONAL ALL-IN PRICE FORECASTS(1) ($/MWH) [CHART] The all-in market price combines the energy price with the price received by generators for other relevant generation services and energy products in the market. The all-in price reflects PA's estimate of the total market price that generators will recover in the markets at a 100% capacity factor. The all-in price results of the study are summarized in Figure 1-4. 1.5 REPORT STRUCTURE The remainder of this report is structured as follows: - - CHAPTER 2 provides an overview of competition and restructuring in the U.S. electricity markets. - - CHAPTER 3 reviews the methodology used to develop the forecasts presented in Chapter 5. - - CHAPTER 4 provides key assumptions that drive the forecast results in Chapter 5. - - CHAPTER 5 contains a discussion of each of the relevant generation markets organized by NERC transmission region. Each regional section includes an overview of the market with a discussion of the current generation mix and a summary of PA's fundamental load and generation requirements forecast for the period 2002-2021. Each section also provides forecasts of energy prices and capacity compensation for the base case as well as associated sensitivity cases. Dispatch curves are provided for 2006 and 2012. These curves illustrate the marginal cost of the last generator for the given load shown on the horizontal axis. The location of the assets in the generating portfolio are identified on the curves. 1-4 Southern Power - June 5, 2002 2. COMPETITION AND RESTRUCTURING IN THE U.S. ELECTRIC INDUSTRY 2.1 INTRODUCTION Over the past two decades, the structure of the electric power industry has been increasingly shaped by the emergence of a prevailing market trend in the networked industries, namely the introduction of competition in formerly regulated markets. This chapter examines the recent development of competitive power markets in the United States. 2.2 RECENT FEDERAL RESTRUCTURING 2.2.1 FERC ORDER 2000 In 1999, the Federal Energy Regulatory Commission (FERC) issued Order 2000 promoting the formation of Regional Transmission Organizations (RTOs), which represent a broadening of the ISO concept. Public utilities that own, operate, or control transmission are left to decide the type of RTO they wish to form or to join. The purpose of the order is to provide greater guarantees to wholesale market participants of open access to the transmission systems of FERC jurisdictional utilities. By pushing for additional levels of independence over the control and operation of the transmission system, it is FERC's hope that the formation of RTOs will further promote competition and greater investment efficiency in the wholesale and retail power sectors. Order 2000 is discussed in greater detail in Section 2.4.4. 2.2.2 SAFE ACT OF 2001 While the Securing America's Future Energy (SAFE) Act of 2001 currently does not have an electricity section, HR 3406 -- a bill that many lobbyists believe will be incorporated into the SAFE Act legislation -- contains many provisions of importance to electric power utilities and other wholesale market participants, including: - - repeal of the Public Utility Holding Company Act (PUHCA) - - repeal of the Public Utility Regulatory Policies Act (PURPA) mandate requiring utilities to purchase from and sell to qualified cogeneration facilities (QFs) - - replacement of NERC with an electric reliability organization that has mandatory standards. - - repeal of FERC's merger authority - - requirement that all transmission-owning utilities participate in an RTO within 12 months of the bill's enactment - - grant of transmission siting authority to FERC where states have delayed transmission projects involving interstate commerce - - tax deferral for the sale of transmission assets by utilities that join an RTO - - open access to the grid by transmission-owning utilities at fair rates. HR 3406 further requires that FERC establish transmission pricing policies and standards to upgrade the system, and contains $33.5 billion in tax incentives -- primarily for research and development associated with the production of traditional energy sources. The SAFE Act was introduced to the House of Representatives on July 27, 2001, as HR 4. On August 2, 2001, the bill was passed by a vote of 240-189 and was then sent to the Senate. 2.2.3 ENERGY POLICY ACT OF 2002 Unlike the legislation passed in the House, the Senate's Energy Policy Act of 2002 does contain specific provisions for electricity. In several ways, the Senate bill compares directly to HR 3406, as both bills call for: - - Repeal of PUHCA. However, the Senate bill transfers PUHCA's merger authority from the Securities and Exchange Commission to FERC. - - Repeal of the PURPA mandate requiring utilities to purchase from and sell to QFs, but only if FERC determines that QFs have access to day-ahead and real-time power markets and competitive suppliers. - - Replacement of NERC with an electric reliability organization that has mandatory standards. - - Open access to the grid by transmission-owning utilities at fair rates. Southern Power - June 5, 2002 2-1 However, the Senate legislation does contain several points in which it differs significantly from the House bill, such as: - - FERC's jurisdiction over merger and acquisition activity is expanded in the Senate bill rather than repealed. Under the language of the bill, FERC would be given authority to oversee mergers of holding companies that own utilities, mergers of generation-only utilities, and acquisitions of natural gas companies by electric companies. - - Unlike HR 3406, the Energy Policy Act contains no references to RTOs or siting policies. - - Also, under the Senate bill, utilities would be required to generate 10% of their electricity from renewable energy facilities by 2020 -- an increase from the 2% currently required. Other important general aspects of the bill include $14 billion in tax credits and subsidies for new fossil fuel production (oil and gas production, coal mining, etc.), energy efficiency provisions, and energy produced from renewable resources. Included in this tax package is the recognition of capital gains on the sale of assets by electric utilities to independent transmission companies over an eight-year time frame. Almost $2 billion in incentives also are outlined to promote electricity generation from "clean coal" plants under the bill. The Senate Energy Policy Act of 2002 was passed on April 25, 2002 by a vote of 88-11. 2.2.4 THE PROSPECT FOR LEGISLATION IN 2002 Selected House and Senate members must now agree on the final form of compromise legislation based on both House and Senate energy bills. Once this final bill is completed, it may then be put to a Congressional vote in the fall of 2002. However, while the White House is very interested in getting energy legislation passed in 2002, some believe that, given election year politics, there is a chance the energy legislation will not be put to a vote in the fall session. 2.3 STATE RESTRUCTURING Restructuring in the United States has progressed in a piecemeal fashion because of the division of authority over various aspects of the electric power industry between state and federal legislative and regulatory bodies. While restructuring of the wholesale retail electricity markets has developed largely under federal jurisdiction, retail electricity markets have developed on a state-by-state basis. As illustrated in Figure 2-1, 24 states plus the District of Columbia have either enacted retail choice restructuring legislation or issued a comprehensive regulatory order on restructuring. The remaining states are either investigating the subject or have done nothing to address the topic. A summary of the restructuring status of Alabama, Florida, and Georgia follows. 2.3.1 ALABAMA As a low-cost electricity state, Alabama has been slowly and deliberately progressing toward reform of its current system. It has taken action to ensure stranded cost recovery when a competitive market is eventually adopted. Utilities will have the opportunity to recover stranded costs through exit fees assessed on customers who choose alternate suppliers. This May 1996 law was challenged in federal court, but the challenge was dismissed. Since there is no retail choice in Alabama at this time, the law has not yet been applied. No other restructuring legislation has been introduced. After it opened a restructuring inquiry in June 1998, the Alabama PSC conducted restructuring studies and also received input from several market participants: - - Alabama Power and other public utilities urged the Alabama PSC to take no immediate action to restructure the state's electric industry, citing low power costs in the state and problems with restructuring in other states. The utilities recommended the PSC take two to five years to review the issue and learn from other states' mistakes. Alabama Power called for full recovery of stranded costs if restructuring was ordered and opposed a regional ISO and the forced divesture of the utility's generating assets, claiming a code of conduct and some restructuring of its business operations could handle any market power issues. - - Alabama Industrial Energy Consumers (AIEC) proposed retail choice beginning January 2001 and completed by the end of 2004. It argued that even with the current low energy prices, customers in the state would benefit from retail choice. AIEC claimed Alabama will lose its current rate advantage as high-priced states surrounding it restructure, noting also that some low-cost states had recognized the benefits of 2-2 Southern Power - June 5, 2002 FIGURE 2-1 STATUS OF STATE ELECTRIC INDUSTRY RESTRUCTURING ACTIVITY AS OF MARCH 2002 [MAP] retail choice. The industrial users argued that Alabama could already draw key lessons from California, including the need to avoid high stranded-cost charges and a power exchange approach. On the issue of stranded costs, AIEC said that Alabama Power's existing plants have a low book values and the company should have no stranded costs to recover. If any costs were shown, AIEC said, the burden should be split between ratepayers and stockholders. - - While cooperatives and municipal power groups sided with Alabama Power in saying the state should go slow on restructuring, they sided with the industrial consumers on the issue of mitigating Alabama Power's market power once restructuring occurred by creating a regional ISO to run the transmission grid and requiring Alabama Power to unbundle or divest its generation assets. In November 1999, the Alabama PSC opened a proceeding, which it closed in October 2000, deciding that deregulation was not in the public interest. It stated that research did not demonstrate all consumers in Alabama would continue to receive adequate, safe, reliable, and efficient energy services at fair and reasonable prices under a restructured retail market. The Alabama PSC also stated that it "cannot mandate or otherwise allow retail competition or electric industry restructuring without state enabling legislation" and that its own role during and after a transition would depend on the form restructuring takes in Alabama. Southern Power - June 5, 2002 2-3 2.3.2 FLORIDA Florida has yet to restructure its utility industry to introduce competition. In March 2000, a restructuring study bill was introduced that created a commission to examine state rules on generation, transmission, and delivery of electricity as well as study other states' restructuring policies. The bill was defeated because it contained an amendment requiring a moratorium on merchant plants while the study was conducted. However, the governor subsequently created the Florida Energy 2020 Study Commission by executive order. In September 2000, the 17-member study commission began studying Florida's electric energy needs over the next 20 years and determining how best to supply those needs while ensuring adequate electric reserves. In its February 2001 interim report, the study commission unanimously recommended a plan to restructure Florida's wholesale power market, permitting construction of merchant plants and requiring IOUs to move all generating assets to affiliated exempt wholesale generators. The output from the transferred assets would be committed to the utilities under long-term contracts. The amount of power under contract would decline over time, which would increasingly open the market for merchant power plants. Legislation enacting the plan remained in committee during the 2001 session. With the slow pace of regulatory change, current Florida law, and recent court rulings in the region, merchant power plant development has been severely hampered in Florida. An April 2000 ruling by the Florida Supreme Court upheld a plant siting law which discouraged the development of merchant plants and given incumbent firms the advantage in new plant construction. The U.S. Supreme Court declined to hear the case in March 2001. In its written November 2001 report, the study commission did not recommend repealing the plant siting law, but encouraged the removal of barriers to merchant plant development. The study commission released its final report on December 11, 2001. The report presented the commission's "strategy for assuring that Florida will have an adequate, reliable and affordable supply of electricity." The commission recommended removing barriers to entry for merchant plants to facilitate the development of new generation capacity, providing nondiscriminatory access to the transmission system through the creation of an RTO, fully implementing wholesale competition within six years, and establishing a new study commission in 2004 "to assess the status of wholesale competition and make recommendations as to whether retail competition should be allowed." 2.3.3 GEORGIA Georgia was a pioneer in retail competition. It was the first state to allow choice for electric customers with loads greater than 900 kW (1973) and also the first to legislate retail access for IOUs' natural gas customers (1997, modified in 1999). In 1997, the Georgia PSC conducted a series of restructuring hearings on consumer impacts, the environment, energy efficiency, stranded costs, and changes in public policy. In January 1998, the PSC issued a report that set forth an action plan to continue investigations into asset recovery practices and cost-of-service versus unbundled rates and to initiate new dockets on planning, reliability, and stranded cost recovery. However, Georgia's retail electric rates are currently at or below the national average, providing little momentum to any industry restructuring effort. Legislation to create a study committee on competitive electricity markets failed to pass in 1997, while no retail choice bills were introduced in either 1999 or 2000. In January 2001, the Georgia PSC chairman told a legislative committee that gas deregulation was a failure in that it did not protect residential and small commercial customers from price spikes. Georgia has been plagued by high gas prices, consumer complaints, loss of competing sellers, and a high rate of unpaid bills. Based on the sour gas deregulation experience, the chairman did not support electricity deregulation. In March 2001, the governor signed SB 93, which provides net metering for solar, wind, and fuel cell systems. The Georgia legislature and governor have pledged to take action in the 2002 session to fix the gas deregulation problem. Several options are being considered, including introduction of a large, regulated supplier into the market as a stabilizing force. 2-4 Southern Power - June 5, 2002 2.4 RELIABILITY AND COMPETITIVE MARKETS 2.4.1 INTRODUCTION Much of the development of competitive market structures and system operations in recent years has involved the balancing of system reliability concerns with the desire to allow the market to drive the development of the electricity industry. This balancing of market forces and reliability concerns is evident in shape of the transmission industry and evolving competitive electricity markets today. 2.4.2 OVERVIEW OF REGIONAL MARKETS In the United States, competition in the wholesale markets is, in part, defined and shaped by North American Electric Reliability Council (NERC) regions, shown in Figure 2-2. - - ECAR - East Central Area Reliability Coordination Agreement - - ERCOT - Electric Reliability Council of Texas - - FRCC - Florida Reliability Coordinating Council - - MAIN - Mid-America Interconnected Network - - MAPP - Mid-Continent Area Power Pool - - NPCC - Northeast Power Coordinating Council - NEPOOL - New England Power Pool - NEW YORK - New York Power Pool - - PJM - Pennsylvania-New Jersey-Maryland Interconnection LLC (defined as Mid-Atlantic Area Council or MAAC by NERC) - - SERC - Southeastern Electric Reliability Council - - SPP - Southwest Power Pool - - WSCC - Western Systems Coordinating Council - CALIFORNIA - NORTHWEST - AZ-NM-NV - Arizona-New Mexico-Northern Nevada - CO-WY - Colorado-Wyoming. The high-voltage transmission system and the corresponding bulk power markets in the United States were originally developed to ensure reliability of supply within franchised utility territories. They were not designed specifically to support commercial transactions and power trading. FIGURE 2-2 NERC REGIONS IN THE UNITED STATES [MAP] Southern Power - June 5, 2002 2-5 Stemming from the Northeast blackout of 1965, the utility industry organized voluntary regional reliability councils to coordinate reliability practices in the United States and parts of Canada and Mexico. The continental United States is currently divided into ten voluntary regional reliability councils whose policies are, in turn, coordinated by NERC. The reliability councils establish guidelines for all member utilities and suppliers. Two of the principal guidelines established by each council concern: - - MINIMUM OPERATING RESERVES. Operating reserves represent generating units that are maintained in a spinning or fast-start condition so that they can rapidly respond to an outage at another unit or some other emergency condition. - - MAXIMUM AREA CONTROL ERROR. Area control error is a measure of the difference between actual and scheduled power flows. It is controlled to maintain the standard operating frequency of the alternating current power supply system and to prevent damage to generators and other equipment connected to the grid. The ten regional reliability councils are part of three, larger, interconnected and synchronized electric power systems: - - The Eastern Interconnection (ECAR, MAIN, MAPP, NPCC (excluding Quebec), PJM, SERC, SPP, and FRCC) - - The Western Interconnection (WSCC) - - Electric Reliability Council of Texas Interconnection (ERCOT). These three systems are interconnected through limited direct current (DC) transmission ties. However, the alternating current (AC) systems of these three systems are not synchronized and operate independently of one another. 2.4.3 POWER POOLS While regional reliability councils provide standards and guidelines, they do not provide actual electricity dispatch, scheduling, or other transmission system operational services. To capture the economies of scale associated with load and resource pooling as well as joint-dispatch and transmission operations, utilities in several regions voluntarily established power pools, the first of which, the PJM Power Pool, was established in 1927. Power pools attempt to capture the benefits associated with being part of a larger generation and transmission system (including improved reliability) through coordinated maintenance planning and shared operating reserves, as well as the blending of load profiles and generating resources. Power pools vary widely throughout the United States in terms of the degree to which they provide coordination and services. 2.4.4 ISOS -- INDEPENDENT SYSTEM OPERATORS FERC's landmark Order No. 888 actively encouraged the formation of ISOs to replace power pools in scheduling, dispatching, and operating regional transmission systems. The intent was, and continues to be, that the ISO provide independent grid management through a process in which all system users are treated equally. Many of the utilities in the most tightly coordinated power pools in the United States were among the first to file ISO applications with FERC, but the ISO trend is now progressing through the industry as an increasing number of states enact legislation implementing retail access. However, with the advent of Order 2000 the current movement in the industry is from ISOs to RTOs. 2.4.5 RTOS -- REGIONAL TRANSMISSION ORGANIZATIONS While ISOs provided a starting point for the restructuring of electricity markets, FERC's drive to increase the open access to the transmission system and to expand dissemination of transmission system information led the Commission to call for the creation of RTOs. In Order 2000, FERC required that every FERC jurisdictional utility that owns, operates, or controls transmission facilities must join an independent RTO. FERC was flexible in the design process, stating that ISOs, transcos, combinations of the two, or other organizational forms would be accepted for consideration. FERC established minimum characteristics and functions of RTOs, but left it to individual entities to determine how they are to meet such requirements. The minimum characteristics that an RTO must satisfy include: - - independence from "market" participants" - - geographic scope and regional configuration 2-6 Southern Power - June 5, 2002 - - operational authority (the RTO must serve as the security coordinator for its region) - - short-term reliability (through scheduling and re-dispatch. The minimum functions that an RTO must satisfy include: - - tariff administration and design - - congestion management - - parallel path flow - - ancillary services - - open-access same-time information system (OASIS), including the calculation and posting of total transmission capability (TTC) available transfer capability (ATC) - - market monitoring - - planning and expansion - - interregional coordination. While FERC allows for flexibility in structuring RTOs that satisfy the minimum characteristics and functions, there are three fundamental models that have been proposed in varying forms: - - ISO MODEL. A non-profit, independent entity operates and assumes control of transmission assets owned by multiple transmission owners. In addition to the functions that operational ISOs currently perform, an ISO also would have to assume planning and expansion functions to meet RTO requirements. This model is representative of the traditional ISO entities: ISO-NE, New York ISO, CA-ISO, and PJM (prior to the creation of PJM West). - - HYBRID MODEL. Under a hybrid model, a non-profit entity would serve as an umbrella organization over one or more for-profit, independent transmission-owning companies (ITCs) or gridcos. The non-profit entity and the ITCs/gridcos would share functions and collectively constitute an RTO. MISO and the current PJM structures are both examples of hybrid models. - - TRANSCO MODEL. A single for-profit, independent entity (ITC/gridco) operates and controls a collective pool of transmission assets. The transco would perform all RTO functions. The proposed Alliance RTO would have operated as a transco. Initially, Order 2000 required all transmission owners (with the exception of those participating in an approved ISO) to file with FERC, by October 15, 2000, a proposal to form an RTO. All RTOs were to be operational by December 15, 2001. Alternatively, owners could describe efforts to participate in an RTO, any existing obstacles to RTO participation, and any plans to work toward RTO participation. However, this schedule has slipped considerably and FERC is no longer publicly establishing dates for RTO formation and operation goals. Through Order 2000, FERC proposed a number of innovative transmission rate mechanisms to encourage the formation of compliant RTO entities by transmission owners. FERC has recently begun to follow through on some of its promised innovative rate mechanisms now that it has seen several proposals that meet its general RTO criteria. However, while FERC is offering financial incentives for RTO participants, it has also threatened financial punishments (such as the loss of market-based rate authority for a company's generating assets) for those utilities that refuse to join approved RTOs. Figure 2-3 illustrates the current status of RTOs in the United States. The status of proposed RTO groups is in flux and considerable activity in RTO development is likely in the near term as the approval status and membership of various RTO groups continues to change. While proposal specifics continue to evolve, the following is a brief summary of the some of the current RTO filings submitted to FERC: CONDITIONALLY APPROVED RTOS - - ALLIANCE RTO. Several Midwest utilities filed to form a for-profit transco, in which they would hold some passive ownership, and FERC conditionally approved the filing on July 12, 2001. However, on December 19, 2001, FERC rejected the Alliance RTO proposal and recommended that the Alliance RTO pursue joining MISO. FERC expressed confidence that the Alliance RTO's desire to be a for-profit RTO could still be accommodated under the MISO umbrella. The commission justified its ruling not to approve the Southern Power - June 5, 2002 2-7 FIGURE 2-3 RTOs IN THE UNITED STATES [MAP] Alliance RTO because it lacked sufficient scope and customers would be better served by a single Midwestern RTO. Recently American Electric Power (AEP), one of the founding members of the Alliance RTO, has announced its intention of now joining PJM. - - GRID FLORIDA, LLC. FP&L, PFC, and TEC filed to form a for-profit company to own and operate assets of FP&L and operate facilities retained by the other two utilities. The application was conditionally approved by FERC on March 28, 2001. However, in November 2001, the Florida Public Service Commission (PSC) ruled that Grid Florida must file as a not-for-profit RTO. Grid Florida filed a plan for service as a non-profit entity on March 20, 2002. - - GRID SOUTH LLC. CP&L, Duke Energy, and SCE&G filed to form a for-profit company (in which transmission owners would hold a passive interest) to operate their grid facilities. Grid South conditionally was approved by FERC on March 14, 2002. However, due to uncertainties surrounding RTO development, the Grid South companies withdrew their applications before the North Carolina and South Carolina Utilities Commissions and are awaiting further direction before re-filing. OTHERS - - SETRANS GRID COMPANY, LLC. The five Southern Company subsidiaries filed to form an RTO to operate their transmission facilities. Subsequently, Entergy TRANSCO, CLECO Corp., and several southeastern cooperatives and municipalities have also joined the SeTrans RTO group. ITCS/GRIDCOS In addition to the RTO filings before FERC, there are also a number of ITCs/gridcos that have been formed or are being formed to operate under various RTOs, including: - - ENTERGY TRANSCO LLC. The five Entergy subsidiaries filed to transfer ownership of their assets to an independent, for-profit entity. Entergy TRANSCO is currently a member of the proposed SeTrans RTO along with Southern Company and several other southeastern utilities. 2-8 Southern Power - June 5, 2002 In general, the development of appropriate regional transmission institutions should improve open access and lead to more efficient transmission grid operation, improve grid reliability, remove the remaining opportunities for discriminatory transmission practices, improve wholesale market performance, and facilitate increased transmission investment. While each of the proposed RTOs are developing individually and currently have different market products, the final resulting economies should be similar. Thus, PA approaches all regions with the same fundamental analysis. 2.4.6 ADDITIONAL RTO-RELATED ACTIONS BY FERC In addition to the RTO efforts, several other recent FERC initiatives promise to have profound effects on the existing wholesale energy markets. A. STANDARD MARKET DESIGN One initiative that FERC is actively pursuing in conjunction with RTO formation is the creation of a standard market design (SMD) for all centralized wholesale energy markets. FERC believes that having standardized wholesale market structures across the country will greatly facilitate electricity trading. To this end, on March 13, 2002, FERC staff released a report on standard market design. In the report, the FERC staff stated their preference for locational marginal pricing (LMP), the separation of market monitoring units from RTO management, and RTO operation of day-ahead and real-time energy markets. FERC is expected to release a Notice of Public Ratemaking on SMD during the summer of 2002. B. SUPPLY MARGIN ASSESSMENT On November 20, 2001, FERC decided to abandon the hub-and-spoke analysis for determining market power in wholesale energy markets and instead embrace the Supply Margin Assessment (SMA) methodology. FERC stated that if utilities do not pass the SMA test, they would be stripped of their abilities to sell power at market-based rates in their control areas. However, utilities that belonged to FERC-approved RTOs would not be subject to such proceedings. Southern Company, Entergy, and AEP were the first utilities listed by FERC as failing the SMA test. However, due to considerable industry criticism stemming from its SMA decree, FERC delayed SMA mitigation indefinitely on December 19, 2001. The three companies were still required to address the order and provide status reports to FERC by January 10, 2002. Southern Power - June 5, 2002 2-9 This page intentionally left blank. 2-10 Southern Power - June 5, 2002 3. APPROACH TO MARKET PRICE FORECASTING 3.1 INTRODUCTION PA has developed a proprietary approach to market valuation and price forecasting. This market valuation process (MVP) applies best practice forecasting principles and leverages deep insight into energy market dynamics to deliver sound independent results. PA's proprietary Merchant Generation Database serves as the backbone of this process by ensuring that PA's expert opinion is supported by an accurate view of the ever-changing merchant energy market landscape. At the highest level, MVP is a five-step process: 1. REVIEW MARKET CHARACTERISTICS. PA scans industry-leading market data sources, assesses internal data repositories and considers recent market developments and their impact on the merchant generation industry. 2. ESTABLISH ASSUMPTIONS. PA works with the stakeholders to review and validate critical plant-specific characteristics and reach consensus on the interpretation of market information. 3. COMPLETE BASELINE FUNDAMENTAL ANALYSIS. To examine the relationship between supply and demand for each region, PA assesses the impact of critical market drivers, including generation characteristics, fuel price forecasts, generation costs of new entrants, and costs of existing plants. 4a. CONDUCT PLANT-LEVEL DISPATCH ANALYSIS. Based on the outcome of the fundamental analysis, PA assesses from a cost vs. price forecast perspective how the generating plants in question are likely to respond to price signals in the market. 4b. REFINE PLANT DISPATCH WITH VOLATILITY ANALYSIS (OPTIONAL). Depending on the type and location of plants in question, PA will refine the price forecast to account for price volatility by projecting multiple price paths calibrated to historical price patterns. This optional price forecasting step provides for a more refined base from which to conduct dispatch analysis for specific plants where volatility is relevant. Based on the specific plants under review and the fact that the Southern Power units are under contract for the near term for this analysis, dispatch analysis utilizing volatility was not necessary. FIGURE 3-1 OVERVIEW OF PA'S MARKET VALUATION PROCESS [CHART] This approach is designed to forecast generating unit and or portfolio revenue streams with the highest degree of accuracy that is possible based on market and plant information available at a specific point in time. Analytical results do not guarantee actual performance, however, PA is confident that the analysis most accurately reflects the present industry outlook. To support this claim, it is important to clarify how PA's approach stands apart from other market valuation methodologies: - - PA's proprietary merchant generation database is recognized by market participants as the most accurate, comprehensive and up to date view on industry activity. - - PA's approach uses traditional cost-based fundamental analysis to estimate the market value of generating units. - - PA assumptions on market entry and exit address the need for total cost recovery for new entrants and partial cost recovery for existing plants. Compared to other pure production-cost-based forecasts, this simple assumption provides for a much more realistic market view by addressing the likelihood of partial cost recovery when energy and capacity prices fall. Southern Power - June 5, 2002 3-1 This chapter describes in detail PA's market valuation process. Section 3.2 outlines the forecasting principles that serve as the analytical foundation to the MVP approach, namely economic equilibrium, the distinction between capacity and energy markets and the evolution of market structures. Section 3.3 marks the beginning of the approach description with an overview of the market characteristics review step. Section 3.4 outlines the process for developing the assumptions (which are covered in detail in Chapter 4). Section 3.5 summarizes the methodology used for estimating market prices for electricity in the fundamental analysis. Section 3.6 follows with a description of the dispatch analysis. 3.2 MARKET PRICE FORECASTING PRINCIPLES To fully understand PA's market price forecasts and generation portfolio revenue projections, it is important to consider the critical principles that drive the analytical approach. While PA has adopted numerous economic principles, three warrant specific explanation: - - The concept of economic equilibrium and how this impacts the market reaction to returns on equity (or lack thereof) as driven by market prices. - - The capacity component of generation revenue and how energy prices may or may not account for this cost of delivery. - - The cost of generation and the impact that this cost has on market price forecasts. These principles are addressed below. 3.2.1 ECONOMIC EQUILIBRIUM A fundamental tenet of PA's market price forecasting approach is that market participants will continuously adjust to support economic equilibrium conditions. PA defines economic equilibrium as the market's attempt to exploit or capture excess margins through entry (e.g., when the return on equity is above market) or exit (e.g., when expected returns fall below market). In other words, excess returns should not persist because participants will enter markets to capture a portion of the above market return until equilibrium is reached. In this explanation, above market return is defined as a return above the agreed upon market rate of return. The agreed upon market rate of return is specified in Chapter 4. While the concept of economic equilibrium is sound in principle, actual markets may not follow economic equilibrium exactly. Many industries have shown a pendulum of cycling returns, where above market returns are followed by excess entry resulting in low returns which are followed by a disincentive to invest which results in high returns. While such cycling and overshooting is often a characteristic of commodity markets, market participants are, in general, attempting to adjust to a level commensurate with economic equilibrium - that is, they cycle around the price level suggested by economic equilibrium. To explore the implication of "disequilibrium" conditions, PA generally constructs an overbuild scenario where excess entry is presumed to occur. PA forces excess entry early in the study period, as the impacts on generation assets are likely to be most severe in this timeframe. Potential near term impacts include: - - decreased energy prices or less attractive spark spread - - diminished capacity revenue - - increased plant retirements. Subsequent to this period of capacity abundance, PA then examines how the market might return to economic equilibrium. Key considerations in this analysis include: - - regional load growth - - unit retirements during periods of diminished returns - - capacity price recovery. In summary, PA's market valuation process assumes that markets pursue economic equilibrium conditions. In this pursuit, participants will overreact to both below- and above-market returns. These reactions can cause pendulum-like price variations over the long term. PA captures the overreaction to above-market returns in an overbuild scenario where supply exceeds demand for a short timeframe that is followed by a return to equilibrium through exit and demand growth in subsequent years. 3-2 Southern Power - June 5, 2002 3.2.2 CAPACITY AND ENERGY MARKETS PA adopts the view that price forecasts must account for differences in market structure from a generator compensation perspective. There are two main types of generator compensation structures: (1) separate mechanisms for energy and capacity, and (2) energy-only compensation. Examples of markets with separate compensation mechanisms for energy and capacity include New York, PJM, and England and Wales. In these markets, load-serving entities are required (by administrative rule) to own or contract for a minimum generating capacity reserve level. This capacity obligation creates a market between those that are short capacity and those that have surplus capacity. In a competitive market, potential suppliers compete to provide this capacity. Competition has spawned capacity trading in the form of daily, monthly or annual capacity obligations. In capacity markets, generators receive compensation for generation availability, i.e., an obligation to produce an agreed upon amount if and when required. In capacity and energy markets, generators attempt to cover their total going-forward costs through a combination of potential revenue sources, including energy markets, capacity markets, ancillary services markets, and options and forwards on a bilateral basis. This type of market provides generators with multiple opportunities to recover variable costs (e.g., fuel costs, variable maintenance expenses, emission costs) and going-forward costs(2) from the energy market and in the capacity market. One could claim that such a market structure offers a stronger incentive for investment in generating capacity as compared to the energy-only market compensation mechanism. In market structures without an explicit capacity market (e.g., Australia, New Zealand, California) there is no separate payment to generators for their installed capacity.(3) In this type of market, generators must place greater weight on recovering their going-forward costs solely from the energy market. This heightened attention on a single energy-only compensation mechanism suggests that price volatility may be greater for energy-only markets. To explain further, in an energy-only market, marginal plants (i.e., the last few generators needed to support reliability) would need to increase their bids above their costs to cover their going-forward costs and earn a sufficient margin when they are called upon to generate. In low load hours, however, there is an abundance of capacity present in the marketplace, and prices are more likely to be driven to marginal cost. Volatility in the spot market affects pricing in the forward market and for options. Because of the volatility in spot prices, marginal generators, who might not be expected to run but for a few hours, may be able to sell call options for power with high strike prices. These options may or may not actually be "in the money," but market participants may be willing to buy these call options as a hedge against the possibility of even higher market prices. These contracting mechanisms, fostered from volatile spot prices, provide the means for some of the marginal plants to recover their going-forward costs. They also provide the mechanism for the market to secure an economic level of reserves to meet peak demand. In addition to option contracts and energy prices being set above the marginal cost of the price setting plant, generators can also be compensated for capacity through ancillary services. Even in markets with capacity obligations and a traded capacity market, energy prices have been quite volatile. This price volatility stems from an intrinsic characteristic of electricity: because there is no inventory, electricity must be produced in real time. This means that errors in forecasting demand or plant commitment, failures in equipment, and market perceptions amplify price movements. This has led to electricity having the most volatile spot prices of any commodity traded. - -------- (2) Going-forward costs are those costs that a generator cannot avoid if it remains in the market, such as fixed operation and maintenance (O&M), property taxes, employee benefits, and incremental capital expenditures. These costs do not include a return on capital or debt service, as these costs are deferrable on capital that is already committed to the marketplace (e.g., sunk). (3) Forms of energy-only pricing systems also may include payments for spinning and operating reserves. However, payments for ancillary services are differentiated from capacity reserve payments for purposes of this discussion. Southern Power - June 5, 2002 3-3 Economic theory suggests that, an energy only market will over time lead to economically efficient capacity levels. As long as prices rise sufficiently to allow the generators in the market to recover their variable costs and going-forward costs, the average energy price should cover the costs of new capacity, even if there is no separate capacity payment delivered from either a traded capacity market or administered by the market operator. As described above, regional market structure will determine the composition of generator revenue streams and will impact the mix and timing of new generating units. However, it is important to note that the financial return on new assets is likely to be similar in both types of markets as generators seek to cover their total going-forward costs. PA recognizes the differences in these structures and accounts for these variations in the market valuation process as described in subsequent sections. Further, PA anticipates that market structures will continue to evolve. Recent events suggest that all markets regardless of maturity level are susceptible to change. Events in California demonstrate how markets may change during a transition period. Likewise, recent activity in the UK and Wales suggest that mature markets can also undergo change. 3.2.3 PRICE BIDDING AND FORMULATION PA generation service compensation forecasts address two primary revenue components: - - Energy based on a production-cost model with prices reflecting marginal cost in each hour. - - Compensation for capacity, which represents the additional margin necessary to keep an economic amount of capacity in the market. This compensation for capacity is not the same as a capacity price in a traded capacity market. FIGURE 3-2 PRICE VS. LOAD -- PJM WEST, FEBRUARY 2000 [CHART] Compensation for capacity may take many forms. Payments could be in the form of a capacity price arising from a capacity market, a regulated payment fee, bilateral option contracts, payments by the ISO for ancillary services, or in the form of energy prices above the marginal cost of the price-setting plant. Regardless of the form, the sum of the compensation for capacity and the market price for energy will ultimately reflect what customers are willing to pay for both energy services and reliability. PA believes that the majority of the compensation for capacity actually arises through energy prices that are higher than marginal cost (and hence PA's energy price forecast) for some substantial portion of hours. Actual market price results support this belief. Figure 3-2 presents a graph of market prices in the PJM market in February 2000. This month was selected for its low load characteristics. For this reason, prices should not reflect much in the way of a "scarcity premium" associated with insufficient generation to cover demand. It is clear from the graph that generators do not simply bid their marginal cost of generation under all circumstances. Were it the case that such bidding strategies were employed, one would expect that the price results in Figure 3-2 would be closely clustered around the marginal cost line. Rather, there is considerable dispersion in the data, particularly in the higher load hours where marginal generation has a greater ability to support a price above marginal cost. 3-4 Southern Power - June 5, 2002 The terms "compensation for capacity" and "energy price" as used in this report reflect the prices needed by the marginal units to recover their variable and going-forward costs. These prices together form the all-in price that generators have determined as necessary to meet all of their going-forward costs. 3.3 STEP 1 - REVIEW OF MARKET CHARACTERISTICS PA's first step in the market valuation process is to understand the nature and parameters of the relevant markets and the generation assets that participate in that market. As illustrated in Figure 3-3, to characterize the market, PA uses a variety of data sources: - - PUBLISHED DATA. These data sources identify the generating units, consumer demand and load, and production capacities of existing plants. PA has built an extensive data scanning effort to maintain a current view of the marketplace. - - FUEL PRICE FORECASTS. PA continuously reviews published fuel price forecasts from a number of known industry groups, including the Energy Information Administration, The Gas Technology Institute, Standard and Poor's, and DRI/WEFA. - - PLANNED ADDITIONS. PA identifies new additions that are assumed to be online prior to 2005, based on a detailed review of the announced plans of developers (tracked in the PA Independent Power Producer Database) and utilities (contained in planning council reports). Capacity additions after 2004 are tested in the entry and exit logic. The market characterization process centers on several critical drivers including the electric generating units currently in operation, their production efficiencies (including heat rate curves), a projection of plant additions (based in part on announcements and in part on an equilibrium evaluation of market price signals and new investments), consumer demand and load, and generation fuel prices. FIGURE 3-3 PA MARKET CHARACTERISTICS REVIEW [CHART] 3.4 STEP 2 - DEVELOPMENT OF ASSUMPTIONS Once the raw data is gathered and assembled for the plants and regional markets in question, PA works with the developer and financial institutions to translate the market and plant data into assumptions for the MVP initiative. As part of this process, PA takes the lead position in screening and validating all assumptions. Assumptions for this analysis are described in detail in Chapter 4. 3.5 STEP 3 - FUNDAMENTAL ANALYSIS To examine the relationship between supply and demand for each region, PA prepares a baseline fundamental analysis that assesses the impact of critical market drivers, including generation characteristics, fuel price forecasts, cost of new entry, and costs of existing plants. These impact assessments are completed in a series of simulation exercises. Projecting electric market prices and generation product sales requires PA to consider not only price formation in the market, but also the issues of market entry and exit. Figure 3-4 provides a graphical view of PA's Fundamental Analysis process. The outcome of the analysis is the baseline price forecast as driven by the assumptions developed in Step 2. Southern Power - June 5, 2002 3-5 FIGURE 3-4 PA FUNDAMENTAL ANALYSIS SIMULATION EXERCISES [CHART] The price forecasts developed are based on a dynamic examination of market entry and exit (including retirement) decisions made by the supply-side players in the market. The following sections will briefly discuss PA's approach to the three main simulation exercises that make up the Fundamental Analysis. 3.5.1 ENERGY PRICE AND DISPATCH SIMULATION PA uses a detailed chronological production-cost model to simulate energy price formation in the market area of interest. Price formation is based on the sequential dispatch of generation units according to short-run marginal costs. From the energy price analysis, PA determines the net energy margins (price minus variable cost) for each generating unit in the market. These margins, along with estimates of "going-forward costs," are used in the Capacity Compensation Simulation Model to predict the additional margins related to the provision of capacity. 3.5.2 CAPACITY COMPENSATION SIMULATION Compensation for capacity is a mechanism for supporting an appropriate amount of generating capability in the system. There are two reasons for including a measure of the compensation for capacity or shortage payment in the projection of market prices. First, if generators bid their short-run marginal costs into an energy market, only inframarginal plants (those not on the margin) earn a contribution toward their going-forward costs. Plants at the top of the supply curve receive little, if any, contributions toward their going-forward costs. In addition, some of the baseload and cycling plants that are not at the top of the supply curve but have high going-forward costs may not earn a sufficient operating margin from the energy market alone to cover all of those costs. PA predicts a value for compensation of capacity using its proprietary Capacity Compensation Simulation Model. This model presumes that the market will retain a sufficient amount of capacity to meet economic reliability targets. In other words, PA simulates a capacity market consisting of a supply curve and a demand curve for reliability (or capacity) services. PA assumes a competitive market, and that the market clearing compensation for capacity is determined by the intersection of the supply and demand curves. PA constructs supply and demand curves for each year in the simulation time horizon. The supply curve is developed based on all of the generators in the market. For each generating unit, the net of going-forward costs and energy market margins, expressed on a per-kilowatt basis, are calculated. These net costs represent the minimum amount a generating unit needs to go forward. Ranking these net costs in ascending order produces a supply curve for capacity. Next, the demand curve is estimated. The demand curve is estimated by representing the capacity associated with a target reliability level. The demand curve is a vertical line derived using a target reserve margin. Finally, the intersection of the demand curve and the supply curve represents the capacity contribution that the market would support in that year. The capacity contribution forecast is the capacity payment derived for each year of the study period. This capacity payment is limited by the entrance cost of a combustion turbine. A sample supply and demand curve for a hypothetical year is shown in Figure 3-5. 3.5.3 CAPACITY ADD/RETIRE SIMULATION It is necessary to assess the feasibility and timing of new capacity additions as well as the exit of uneconomic existing capacity. PA's proprietary modeling approach serves two purposes: - - First, it identifies generating units that are not able to recover their going-forward costs in the energy and capacity market and are therefore at risk of abandoning the market. 3-6 Southern Power - June 5, 2002 FIGURE 3-5 EXAMPLE SUPPLY AND DEMAND CURVE [CHART] - - Second, it provides a rational method for ascertaining the amount, timing, and type of capacity additions. Capacity additions through 2004 are based on PA's proprietary database and decision criteria for additions. Additions must meet PA's criteria for inclusion into the model, including, but not limited to, financing and/or ground-breaking. Thereafter, PA's approach uses a financial model to assess the decision to add new capacity and to retire existing capacity. The approach to plant additions is based on a set of generic plant characteristics, financing assumptions, and economic parameters. This "add/retire" analysis is an iterative process performed simultaneously with the development of the energy price forecast and the projected compensation for capacity. The methodology assesses the feasibility of annual capacity additions based on a Discounted Cash Flow (DCF) model using net energy revenues determined in the production-cost simulations and compensation for capacity determined from the Capacity Compensation Simulation approach. For each increment of new capacity investment, a "Go" or "No Go" decision is made based on whether the entrant would experience sufficient returns (developed in the DCF model) to merit entry. In addition, economic retirement decisions are made at each step in the iterative process based on the specific financial and operating characteristics of the existing plant. The iterative process begins with the addition of new capacity as needed. A production-cost run is executed to determine energy prices, dispatch, and operating costs. The Capacity Compensation Simulation is then performed. Results for energy and capacity compensation are combined in the DCF model to determine whether the new unit is a "Go" or "No Go." If the new unit is a "Go," another new unit is added in that year and the process repeated. This occurs until the next new unit returns a "No Go." Should the analysis show "No Go," the unit is removed (e.g., not added). Annual retirements are determined after new units are added for that year. A financial analysis of each unit is performed beginning in 2002, combining the results of the energy and capacity compensation. If the operating profit (loss) for an existing unit is negative for any five-year consecutive period, it is retired at the end of the third year of consecutive operating loss. PA interprets this rather subjective retirement decision criteria conservatively to allow plants every chance to remain active in the market. Thus, if a unit loses money for two years, is profitable over the third year, and then loses money for two more years, the unit is maintained online. This "Go" No-Go" approach reflects a game theoretic concept of market equilibrium. If units are retired, the iterative process begins again with the addition of new capacity. In this way, the introduction of new units influences the retirement of existing units, and the retirement of existing units enables the introduction of new units. Since the addition of new units is "lumpy," the iteration generally stops with new generators earning a small increment above their cost of debt and equity. The addition of one more new unit then pushes many of the previous additions into losses. This process is repeated chronologically through the end of the analysis for each year continuing to show a deficiency after the most recent new unit addition. Southern Power - June 5, 2002 3-7 3.6 STEP 4 - PLANT-LEVEL DISPATCH ANALYSIS The final step in PA's Market Valuation Process is the dispatch of the specific plants in question based on the price formation outcome of the fundamental analysis. PA assesses from a cost vs. price forecast perspective how the generating plants in question are likely to respond to price signals in the market. First, the plants in question must have the ability to respond to price signals. The greater the flexibility, the greater the potential value the plants can extract by adjusting their operating strategies to take advantage of favorable prices while minimizing the losses from unfavorable prices. Second, the plants must be subject to price volatility that actually causes them to alter their operating strategy. Because the Southern Power units are under contract for the near term for this analysis, dispatch analysis utilizing volatility was not necessary. 3-8 Southern Power - June 5, 2002 4. KEY ASSUMPTIONS 4.1 INTRODUCTION This chapter describes the key assumptions used in the development of the annual energy and capacity market price forecasts. Based on the assumptions below, PA Consulting Group, Inc. (PA) simulates the hourly market-clearing price of energy using MULTISYM(TM) (developed by Henwood Energy Services, Inc.), a production-costing framework that allows the characterization of multiple pricing areas within larger transmission regions. Each major generating unit within a transmission area is represented individually in the MULTISYM(TM) production-costing model using unit-specific cost and operating characteristics. The MULTISYM(TM) model is used to perform an hour-by-hour chronological simulation of the commitment and dispatch of generation resources. The output of this model is then used in PA's Capacity Compensation Simulation Model to develop the annual capacity contribution. The key assumptions in this analysis are grouped into six categories: - - demand growth - - fuel prices - - NO(x) and SO(2) emissions costs - - electricity imports - - capacity additions and retirements - - and financial parameters. These assumptions drive the fundamental model of energy prices and capacity compensation. The following general assumptions were utilized in this study: - - The hourly market-clearing price of energy was developed using MULTISYM(TM), a production-cost model that allows the characterization of multiple transmission areas. - - The analysis has been prepared in 2001 real dollars. All results are in 2001 real dollars unless specified otherwise. 4.2 DEMAND AND ENERGY FORECASTS The projected average annual demand and energy growth for the period 2002 through 2021 is summarized in Table 4-1. TABLE 4-1 PROJECTED AVERAGE ANNUAL LOAD GROWTH RATES(1) (2002-2021)
REGION DEMAND ENERGY ------ ------ ------ SERC 2.0% 2.0% FRCC 2.3% 2.3%
(1) Source: EIA Annual Energy Outlook, 2002. The hourly data for the analysis is based on a synthetic hourly load shape based on five years of actual hourly data provided with the MULTISYM(TM) production-costing model to represent the native load requirements for each of the pricing areas. The annual demand and energy forecast values are applied to the native hourly load requirements to develop the forecasted hourly loads for each year of the analysis. 4.3 FUEL PRICES All fuel types were analyzed on either a regional (natural gas and oil) or plant location (coal) basis in order to capture pricing variations among major delivery points. The forecast prices for each fuel include the cost of transportation to the power plant site. Two additional sections describe hydroelectric and nuclear units. Southern Power - June 5, 2002 4-1 TABLE 4-2 HENRY HUB PROJECTIONS(1) (REAL 2001 $/MMBTU)
AVERAGE ANNUAL GROWTH 2002 2005 2010 2015 2020 RATE ---- ---- ---- ---- ---- ------- EIA 2.23 2.99 3.21 3.45 3.67 2.81% GTI 3.12 2.61 2.70 2.51 3.01 -0.20% DRI/WEFA 2.87 3.16 3.19 3.31 3.38 0.91% CONSENSUS 2.74 2.92 3.03 3.09 3.35 1.13%
(1) An inflation rate of 2.16% was used to inflate the forecasts from 2000 dollars to 2001 dollars and 4.49% was used from 1999 to 2001 dollars in the analysis. Sources: EIA Annual Energy Outlook 2002, December 2001; GTI Baseline Projection and Databook 2001, March 2001; DRI/WEFA, November 2001. TABLE 4-3 NYMEX FUTURES PRICES(1) (REAL 2001 $/MMBTU)
YEAR NYMEX FUTURES ---- ------------- 2002 2.74 2003 3.16 2004 3.23
(1) Based on previous 90 calendar day closing prices ending 2/14/02. FIGURE 4-2 HENRY HUB GAS PRICES 1991-2001 [CHART] 4.3.1 NATURAL GAS The primary inputs into the analysis were forecasts from the Energy Information Administration (EIA),(4) The Gas Technology Institute (GTI), and DRI/WEFA. Table 4-2 outlines the Henry Hub projection from each of the three source forecasts as well as the consensus forecast of natural gas prices at the Henry Hub. The projections represent industry standard market information on long-run equilibrium price. Because natural gas prices can exhibit significant volatility in the short-run, forecasts derived exclusively from long-run price projections may not accurately reflect near-term market conditions. In order to correct for this consideration, PA overrides the consensus through 2004 using a 90-day average of NYMEX futures prices. Natural gas prices are expected to trend back to the long-run consensus by 2006. Table 4-3 displays the near-term price projection. Figure 4-1 shows historical gas prices for the Henry Hub from 1991 through December 2001. Although there has been unprecedented volatility over the past 18 months, recent pricing has exhibited less volatility and has trended back toward consensus forecasts. Regional prices throughout the United States were projected based on this consensus Henry Hub forecast. For all regions modeled, the delivered price is the sum of the Henry Hub projection, the projected regional basis differential, and other natural gas supply costs including all taxes. A. BASIS DIFFERENTIALS The commodity component of the dispatch natural gas price is comprised of the Henry Hub price plus a regional basis differential. PA assembled historic price data from several reliable sources including Natural Gas Week, Gas Daily, and Bloomberg. Regional price differentials were calculated by comparing price history for that location to price history at the Henry Hub. In some cases, the basis differentials are projected to change over time as a result of major pipeline construction and other factors that are expected to - -------- (4) The EIA does not present a Henry Hub price forecast. The EIA figure is an estimate based on a lower-48 wellhead forecast. 4-2 Southern Power - June 5, 2002 introduce discontinuity into the market. In other cases, market factors have already altered the regional pricing patterns. In these cases, PA has relied more heavily on recent price data. Each generating unit was assigned to its nearest upstream trading hub based on its pipeline access. However, modeling limitations prevent the use of plant-specific natural gas prices. As a result, each unit was also assigned to a region. PA generated a regional average basis differential from the unit-specific data based on a weighed average of the unit-level data. B. NATURAL GAS PRICE SEASONALITY Natural gas prices exhibit significant and predictable seasonal variation. Consumption increases in the winter as space heating demand increases and falls in the summer. Prices follow this pattern as well; the seasonal pattern is most striking in cold weather locations. Dispatch prices in the model reflect the seasonal effects based on five-year historic price patterns exhibited at the regional market centers. The advent of significant additions of natural gas fired generation throughout North America may shift the historic seasonality patterns over the forecast period. Insufficient data is available at this point to model any potential changes and therefore a historical seasonality pattern has been applied to develop monthly price projections. C. PIPELINE CHARGES Natural gas fired generation facilities are subject to incremental costs associated with moving gas from liquid regional trading points to the plant gate. In a process similar to that used for calculating regional basis differentials, PA has derived a regional estimate of this cost by mapping generating units to pipelines and calculating a plant specific pipeline charge based on the published firm tariff rates. The variable component of this cost is reflected on a regional, weighted-average basis. The fixed portion of this cost is treated as a component of the fixed O&M cost. D. LOCAL DISTRIBUTION COMPANY CHARGES The final component of the natural gas dispatch price is local distribution costs. Regional Local Distribution Company (LDC) prices were derived from surveys of representatives of the tariff groups at major natural gas distribution companies. Because the information on specific contracts for individual generating stations is considered confidential, detailed unit-level information was not available. As a result, PA used the survey results to estimate LDC charges at the NERC region level. Most of the charges collected reflect the tariff rates for electric generation customers or the largest volume industrial customer rate if an electric generation specific tariff was not available. While most of the LDCs have the ability to offer negotiated rates, negotiated rates will depend on the plant location, the LDC's cost to serve the facility and the facility's competitive options. Where it was possible, an estimated rate to serve an electric generation customer was used. In general, the tariff rates quoted should be viewed as the upper end of an expected range of pricing a facility would pay. As it will become increasingly difficult for units that incur LDC costs to remain competitive, it is expected that market pressure will result in this cost declining over time. For each region, the LDC charge is expected to decline over the forecast period. In addition to this decline, it is expected that this cost will not apply to new units, as competitive forces and operating pressure constraints will result in new facilities locating with direct access to the interstate pipeline network. As a result, not only will the actual LDC charge decline over time, but also a smaller percentage of units will include the charge in their dispatch price, limiting the impact of this cost on market prices. E. TOTAL DELIVERED NATURAL GAS PRICE The total delivered price of natural gas in each market region is based on the projected Henry Hub price, basis differentials, pipeline charges, and LDC charges (see Table 4-4). (New generation is assumed not to incur LDC charges.) TABLE 4-4 DELIVERED NATURAL GAS PRICE(1) (2001 $/MMBTU)
2002 2005 2010 2015 2020 ---- ---- ---- ---- ---- SERC-Southern 3.38 3.73 3.65 3.69 3.93 FRCC 3.44 3.78 3.70 3.75 3.98
(1) Gas prices include LDC charges and other delivery charges. Southern Power - June 5, 2002 4-3 4.3.2 FUEL OIL The fuel oil forecast methodology is described below for No. 2 Fuel Oil and No. 6 Fuel Oil. Prices are developed based on a consensus of crude oil by major forecasters as presented in Table 4-5. These widely used sources present a broad perspective on the potential changes in commodity fuel markets. Each forecast was equally weighted in an effort to arrive at an unbiased consensus projection of fuel prices. As is the case with natural gas, PA has modeled near-term prices to reflect recent actual oil prices and futures prices through December 2003, rather than the long-run equilibrium price. In this case, prices are expected to trend back to the long-run consensus by 2005. The near-term price projection is shown in Table 4-6. A. NO. 2 FUEL OIL Prices for No. 2 Fuel Oil were derived from EIA data on historical delivered-to-utility prices for a five-year period, on a regional basis. Fuel costs are comprised of commodity costs and transportation costs. Each region in the analysis was assigned to a reference terminal. The commodity component is calculated by escalating the historic reference terminal prices at the escalation rate implicit in the crude oil forecast outlined in Tables 4-5 and 4-6. Transportation costs are calculated as the five-year average premium for delivered fuel oil in each region above the market center price for the terminal assigned to that region. This transportation cost is held fixed over the forecast horizon. This methodology captures both the commodity and transportation components of delivered costs. Representative final delivered prices for No. 2 Fuel Oil are shown in Table 4-7. B. NO. 6 FUEL OIL Prices for No. 6 Fuel Oil were derived using an identical methodology as that employed for No. 2 Fuel Oil prices. Because residual oil is so thinly traded, it is difficult to identify significant regional price premiums. As a result, all eastern regions were assigned to the New York Harbor reference terminal. Commodity prices for all regions were based on 1% sulfur residual oil at New York Harbor and are therefore the same. Transportation costs and taxes for each region, however, do vary. TABLE 4-5 CRUDE OIL PRICE PROJECTIONS (REAL 2001 $/BBL)
AVERAGE ANNUAL GROWTH 2002 2005 2010 2015 2020 RATE ----- ----- ----- ----- ----- ------- EIA 21.57 23.22 23.86 24.52 25.21 0.87% GTI 23.60 19.12 19.12 19.12 19.12 -1.16% DRI/WEFA 21.03 24.21 24.54 25.93 27.42 1.48% CONSENSUS 22.07 22.18 22.51 23.19 23.92 0.45%
(1) An inflation rate of 2.16% was used to inflate the forecasts from 2000 dollars to 2001 dollars and 4.49% was used from 1999 dollars to 2001 dollars in the analysis. Sources: EIA Annual Energy Outlook 2002, December 2001; GTI Baseline Projection and Databook 2001, March 2001; DRI/WEFA, November 2001. TABLE 4-6 NYMEX FUTURES CRUDE OIL PRICE PROJECTION(1) (REAL 2001 $/BBL)
YEAR PRICE PROJECTION ---- ---------------- 2002 19.79 2003 20.16
(1) Based on previous 90 calendar day closing prices ending 2/14/02. TABLE 4-7 DELIVERED NO. 2 FUEL OIL PRICE (2001 $/MMBTU)
2002 2005 2010 2015 2020 ---- ---- ---- ---- ---- SERC-Southern 4.64 5.16 5.24 5.39 5.55 FRCC 4.68 5.20 5.27 5.41 5.57
4-4 Southern Power - June 5, 2002 The transportation costs for each region were based on an analysis of historic New York Harbor prices and delivered residual oil at electric generating stations in the region. Transportation costs equal the five-year average premium for delivered No. 6 Fuel Oil above the New York Harbor price. This transportation cost is held fixed in constant dollars over the forecast horizon. Final delivered prices for 1% sulfur No. 6 Fuel Oil are shown in Table 4-8. Price projections for lower sulfur oil products(5) were also calculated to generate model inputs for regions that have more stringent environmental regulations. The premium for lower sulfur products was derived from a comparison of historic price data. 4.3.3 COAL PA developed a forecast of marginal delivered coal prices (in real 2001 dollars) for the period 2002 through 2021 on a unit-by-unit basis for electric generators in each region and the corresponding SO(2) and NO(x) emission allowance prices. The SO(2) and NO(x) allowance prices are presented in Section 4.4. In cost-based electric dispatch modeling, the marginal cost of production is expected to determine dispatch order and the wholesale market price of electricity. For this reason, PA has provided marginal delivered coal prices. These prices reflect PA's projection of a particular unit's marginal coal selection and market pricing for that coal, as well as the rate for transportation for such marginal purchases. If a particular unit purchases some higher- or lower-priced coal under long-term contracts, the unit's average cost of coal acquisition will be different from its marginal coal acquisition cost. It is expected that the cost of contract coal will not be reflected in dispatch pricing or in market prices for electricity. Delivered coal prices were projected in two components: (1) coal prices on an FOB mine or FOB barge basis(6) and (2) transportation rates. Because individual units within a plant sometimes burn different coals, coal selections and delivered prices were developed on a unit-by-unit basis. TABLE 4-8 DELIVERED NO. 6 FUEL OIL PRICE (2001 $/MMBTU)
2002 2005 2010 2015 2020 ---- ---- ---- ---- ---- SERC-Southern 2.86 3.21 3.26 3.36 3.46 FRCC 2.95 3.29 3.34 3.44 3.54
The projected coal selection for individual units reflects differing requirements for compliance with emissions regulations over time, as well as economics. To determine the selected coal, PA considered the use of flue gas desulfurization equipment (scrubbers), requirements to comply with Phase I and/or Phase II of the Clean Air Act Amendments of 1990, and requirements for compliance with New Source Performance Standards and State Implementation Plan (SIP) limits, along with the variable costs of different methods of compliance. While a unit's historical coal selection was an important factor in the projections, substitutions of coal types were projected for some units over time as delivered price economics (including allowance prices) are expected to change. Coal selections were projected using a proprietary PA linear programming model known as the Multi-Pollutant Optimization Model (MPOM) which simultaneously solves for the optimal combination of coal selections, unit dispatch, and SO(2) and NO(x) allowance prices over the forecast period. The operation of the MPOM model is explained in more detail in Section 4.4. PA expects that the spike in coal prices which occurred in late 2000 and early 2001 will be temporary, and that coal prices will return to long-term levels over the next few years. In most cases, the long-term coal prices are close to the long-run marginal cost of mining (including a return on the incremental capital invested) for the marginal mine type in each coal mining region. (The major exceptions involve regions where substantially all of the coal production is sold under long-term contracts, which will cause prices higher than marginal mining costs to persist over a longer period of time.) FOB mine prices were projected based on proprietary models of long-run marginal mining costs in each major coal mining region, supply and demand economics for different coal types, and other market - -------- (5) Includes 0.3% residual oil, low sulfur No. 2 Fuel Oil, and jet fuel. (6) "Free on Board," indicating that the price includes the costs of loading coal onto a train, truck, or barge. Southern Power - June 5, 2002 4-5 knowledge available to PA, in an integrated market analysis. The forecast of long-run marginal mining costs includes an assessment of expected changes in mining productivity for each coal mining region. The forecast is conservative in that only about one-half of the historical rate of improvement in total factor productivity is reflected in the projected coal prices. Prices for most types of coal are expected to decline fairly steeply from the extraordinary 2001 levels over the following three years.(7) The expected annual rates of price decline for major coal types during 2001-2004 range from about 4-5%/year for some types of Northern Appalachian coal to about 15-20%/year for some types of Wyoming Powder River Basin and Central Appalachian coals. Real prices for most of the major coal types are expected to decrease further over the long term (2005-2021), although the expected rates of decline are much slower over the long term (ranging from 0.2%/year to 2.3%/year). The expected rate of change in prices for particular types of coal varies based on considerations specific to each coal type such as supply and expected depletion of reserves, market demand, and the sulfur content of the coals. The coal types which are expected to experience the steepest declines in long-term prices are Illinois Basin low- and mid-sulfur coals, and lignite. The Illinois Basin low- and mid-sulfur coals have historically enjoyed a price premium, but are expected to lose market share both to lower-sulfur Powder River Basin (PRB) coal and to higher-sulfur Illinois Basin coal burned at scrubbed plants. Many of the long-term contracts under which lignite production is typically sold have escalated to very high price levels, but PA expects that the competitive pressures of deregulated electricity markets (as well as more direct competition from PRB coal) will cause many of these contracts to be renegotiated over time to levels that more closely reflect marginal mining costs for lignite. The only significant exception to the anticipated general trend of declining real coal prices involves PRB coals.(8) Due to the very low mining costs and the very low sulfur content (typically ranging from 0.6 to 0.8 lbs. SO(2) per million Btu) associated with these coals, PA projects that demand for these coals will continue to increase strongly throughout the forecast period. Prices for the 8,800 Btu/lb. Wyoming PRB coal are expected to fall to about $6.15/ton by 2004, and continue declining slowly through 2010, but then increase in real terms during the remainder of the forecast period as reserve depletion and higher stripping ratios more than offset expected productivity gains.(9) Projected transportation rates are based on available delivery options at each plant for the coal types selected for each unit. Transportation modes included rail, barge, truck transportation, and conveyor transportation for minemouth plants. Rates for different transportation modes in different regions of the country are projected to vary at different rates over time. In cases where a multi-mode movement of coal is required (such as a combination rail and vessel movement), the rate for each mode of transportation is projected separately, and the total transportation rate is the sum of these separately escalated components. In addition, potential future changes in transportation options were considered. In some cases, for example, PA projected the addition of rail or vessel receiving capability at a particular plant. Potential future regulatory relief was also projected for some plants with sufficiently high rail rates which do not have access to competitive transportation options. Table 4-9 summarizes the expected annual rates of change in coal prices over the long term (2005-2020) for various coal types. - -------- (7) Note that there are a number of coal types which are used in highly localized markets (such as Arizona/New Mexico coals, Central Pennsylvania high sulfur coal, and lignite) and therefore were not as greatly affected by the coal price spike. The expected short-term price trajectories for these coals are much flatter. (8) Prices for Kansas, Missouri, and Oklahoma coals are expected to remain flat in real terms, but these are very small markets (totaling less than 1 million tons/year of utility coal consumption out of a national total of 971 million tons of coal used for electric generation in 2000.) (9) The stripping ratio refers to the amount of soil and rock (overburden, usually measured in cubic yards) which must be removed to surface mine (or strip mine) a ton of coal. 4-6 Southern Power - June 5, 2002 TABLE 4-9 ESTIMATED ANNUAL CHANGE IN COAL PRICES, 2005-2020
REAL ESCALATION RATE COAL PER ANNUM ---- -------------------- Western 0.3% to -2.3% Illinois Basin -0.2% to -1.1% Eastern -0.2% to -0.7%
4.3.4 HYDROELECTRIC The hydroelectric plants are consolidated by utility and categorized as peaking or baseload. Similar to the thermal units, the maximum capacity for each unit was taken from the sources cited above for summer and winter capabilities. Monthly energy patterns were developed from the six years of EIA Forms 759, which contain monthly generation and (for pumped storage units) net inflows. 4.3.5 NUCLEAR PA evaluated the operation of nuclear plants in the regions covered by this study on the basis of going-forward costs to determine which plants would remain in service based on their economic performance. PA estimated the annual going-forward costs (fixed O&M, property taxes, and annualized incremental capital costs) associated with each unit. The incremental capital costs do not include the original investment in the plant. The original investment is treated as a sunk cost and is not considered in the determination of the future competitiveness of a station. Incremental capital costs only include modifications made to the plant each year. These costs are very difficult to track due to the reporting methods. However, these costs are relatively low compared to O&M costs. There are a number of other non-economic issues that might affect a shutdown date. Politics of the region plays an important part in the premature shutdown of the units. Equipment failures and poor overall performance can also cause a utility to shut down a unit before its license expires. As the units age, the amount of investment required to continue operating the unit becomes an important factor. Historical performance as well as recent trends in forced outage rates at each unit were reviewed. Future forced outage rates were forecast for each year, and each unit's scheduled outages during the year were also considered. From this information, and noting that outages are becoming shorter as the industry improves outage planning, the duration of outages for each unit was forecast. For refueling outages, sources included refueling outage schedules, published every six months in Nuclear News for all U.S. units. The decision whether to retire a unit prior to its license expiration date was made based on a thorough review of the unit's projected future economic performance. Nuclear unit retirements were made based on the same process applied to all other units. Currently it is the consensus that nuclear units will have their licenses extended past our current study period. 4.4 SO(2)/NO(x) EMISSION ALLOWANCE PRICES 4.4.1 SULFUR DIOXIDE EMISSION ALLOWANCE PRICES PA's forecast of SO(2) allowance prices is shown in Table 4-10. The price of SO(2) allowances starts at $208 per ton in 2002, increases to $383 per ton by 2015, and then drops to $317 per ton by 2020. The drop between 2015 and 2020 results from new coal-fired units equipped with scrubbers projected to come into service during this period and displacing some existing coal-fired units which have higher SO(2) emissions. TABLE 4-10 SO(2) EMISSION ALLOWANCE PRICES (2001 $/TON SO(2))
YEAR SO(2) ---- ----- 2002 $208 2005 $243 2008 $286 2010 $322 2015 $383 2020 $317
Southern Power - June 5, 2002 4-7 PA's forecast of SO(2) allowance prices was developed using its proprietary Multi-Pollutant Optimization Model (MPOM). MPOM is a linear programming model which simultaneously solves for the optimal combination of coal selections, unit dispatch, and SO(2) and NO(x) allowance prices over the forecast period. For coal-fired units, the model includes a list of possible coal selections for each unit (i.e., coals with various sulfur contents), delivered fuel price data for each of the possible coal selections, and estimates of the cost of retrofitting Flue Gas Desulfurization equipment (FGD or scrubbers) on each unit that is not already scrubbed. Given these inputs, MPOM solves for the least-cost solution which will meet the national SO(2) emissions caps(10) while also satisfying the other constraints in the model. The SO(2) allowance price is the cost per ton of SO(2) removed for the last (or marginal) scrubber that must be installed (or the cost of a switch to lower-sulfur coal that must be made) to meet the emissions cap. 4.4.2 DEVELOPMENT OF NO(x) EMISSION ALLOWANCE PRICES PA's forecast of NO(x) allowance prices is shown in Table 4-11. Unlike SO(2) allowances, which must be used year-round, NO(x) allowances are used only during the "ozone season" specified in EPA regulations, which extends from May 1 through September 30 of each year. Another important difference between SO(2) and NO(x) allowances is that NO(x) allowances cannot be "banked" or carried over from year to year without significant cost and limitations. Thus, NO(x) allowance prices are largely determined by the cost of the marginal NO(x) control technology (in dollars per ton of NO(x) removed) which is required to meet the NO(x) emissions cap. The forecast shown in Table 4-11 reflects two separate sets of NO(x) emissions regulations: the Ozone Transport Region (OTR) and the SIP Call region in the eastern United States. TABLE 4-11 NO(x) EMISSION ALLOWANCE PRICES (REAL 2001 $/TON NO(x))
YEAR NO(x) --------- ------ OTR 2002-2003 $1,023 SIP CALL 2004 $2,996 2008 $3,415 2010 $2,822 2015 $3,149 2020 $2,423
During 2002-2003, NO(x) emission allowances are required in the Ozone Transport Region (OTR), which includes 11 states in the Northeastern and Mid-Atlantic regions of the United States, plus the District of Columbia. Beginning with the 2004 ozone season, a larger region (including most of the states east of the Mississippi River) will be required to meet a stricter set of NO(x) emission regulations that were developed based on the EPA's call for NO(x) State Implementation Plans (SIP Call).(11) The NO(x) allowance price forecast was developed using a methodology very similar to the methodology used for the SO(2) allowance price forecast. Estimated capital and operating costs for retrofitting various NO(x) control technologies on each coal-fired generating unit were input into the MPOM model, and the model solved for the least-cost solution which met the NO(x) emissions caps while also satisfying the other constraints in the model. - -------- (10) The national caps on SO(2) emissions are 9.48 million tons of SO(2) per year for 2001-2009, and 8.95 million tons of SO(2) per year from 2010 forward. (11) The original deadline for implementation of the regulations developed based on the NO(x) SIP Call process was the beginning of the 2003 ozone season (May 1, 2003). The EPA is currently attempting to impose a set of NO(x) regulations similar to the SIP Call regulations on the 2003 deadline using an alternate regulatory process known as the Section 126 process. PA has assumed for purposes of this forecast that the NO(x) SIP Call regulations (or any similar regulations) will not be effective until 2004. 4-8 Southern Power - June 5, 2002 The marginal NO(x) control technology that is required under the OTR regulations is Selective Non-Catalytic Reduction (SNCR). As shown on Table 4-11, the installation and operating costs associated with retrofitting this technology on existing coal fired generating units are approximately $1,000/ton of NO(x) removed. The marginal NO(x) control technology which will be required to meet the SIP Call regulations is Selective Catalytic Reduction (SCR). The NO(x) allowance price for each year is determined by the NO(x) control costs for the marginal unit (i.e., the last unit that must take action to bring the fleet into compliance with the program's emission cap) that operates each year. Between 2004 and 2015, the NO(x) allowance price is expected to remain within a relatively narrow range of $2,996/ton to $3,149/ton. By 2020, the NO(x) allowance price is expected to drop to $2,423/ton as newly built coal-fired generating units with low NO(x) emissions displace some existing coal-fired units with higher NO(x) emissions. 4.5 ELECTRICITY IMPORTS Imports and exports between transmission areas are determined by the model using inputs for transfer capabilities, wheeling rates, and line losses. The transfer capabilities and wheeling rates between pricing areas are provided below. Line losses between all pricing areas are assumed to be 2%. 4.5.1 TRANSFER CAPABILITIES The transmission system is the transportation mechanism that moves power from where it is generated to where it is to be used. There are a number of technical factors that limit the amount of power between utilities, control areas, or large regions. While facility ratings are one key element, voltage levels or instability are other considerations that need to be considered in establishing transfer capabilities. In addition, transfers that involve two utilities or control areas will have an impact on the transfer capabilities of neighboring utilities because a portion of that transfer will flow on neighboring utilities' lines. In order to quantify transmission capabilities between NERC regions and major FIGURE 4-2 TRANSFER CAPABILITY(1)(MW) [CHART] Southern Power - June 5, 2002 4-9 subregions, seasonal analyses are performed that include current operating parameters, load patterns, and scheduled transfers to determine regional import and export capabilities. The transfer capabilities that are shown are non-simultaneous, meaning that for any given transfer at an identified limit, the other transfer limitations shown are unlikely to be attainable at the same time. Concurrent exports or imports for any particular region may not be technically feasible at the total of the capabilities listed. These values represent the ability of the transmission networks to accommodate the transfer of electricity from one area to another area for a single load and generation pattern. Therefore, the actual patterns of demands and generation can result in changes in transfer capabilities on both an hourly and daily basis. These transfer capabilities have been considered representative of the level of interchange that could occur between the various transmission areas. Figure 4-2 identifies the bulk transfer capabilities between regions and subregions included in this report. 4.5.2 WHEELING RATES Wheeling rates were applied based on assumptions associated with proposed or existing RTO, ISO, and transco organizations. In general, for transmission within transmission organizations, the wheeling rates are set at $0.00/MWh, which allows power to flow freely with transmission organizations. This assumes that the current pancaking issues will be eliminated or at least significantly reduced upon implementation of the new RTO organizations in accordance with FERC Order 2000. For transmission from one transmission organization to another, the wheeling rate is set at $3.00/MWh. 4.6 CAPACITY ADDITIONS AND RETIREMENTS It is necessary to assess the feasibility and timing of new capacity additions as well as the exit of uneconomic existing capacity. PA's proprietary modeling approach serves two purposes: - - First, it identifies generating units that are not able to recover their going-forward costs in the energy and capacity markets and are, therefore, at risk of abandoning the markets. - - Second, it provides a rational method for ascertaining the amount, timing, and type of capacity additions. Capacity additions through 2004 are based on publicly announced or planned additions. The additions assumed in this analysis are shown in Table 4-12. These capacity additions are a best estimate of what units will be developed during this period. Actual additions may differ from those indicated. From 2005 through 2021, PA's approach uses a financial model to assess the decision to add new capacity and to retire existing capacity. The approach to plant additions is based on a set of generic plant characteristics, financing assumptions, and economic parameters. This "add/retire" analysis is an iterative process performed simultaneously with the development of the energy price forecast and the projected compensation for capacity. The methodology assesses the feasibility of annual capacity additions based on a Discounted Cash Flow (DCF) model using net energy revenues determined in the production-cost simulations and compensation for capacity determined from the Capacity Compensation Simulation approach. For each increment of new capacity, a "Go" or "No Go" decision is made based on whether the entrant would experience sufficient returns (developed in the DCF model) to merit entry. In addition, economic retirement decisions are made at each step in the iterative process based on the specific financial and operating characteristics of the existing plant. The market entry and exit logic determines the amount and timing of new generation capacity added to the system as well as the retirement of existing units. Starting in 2005, the market entry and exit logic, at a minimum, builds enough new capacity to meet the estimated reserve requirements. Table 4-13 describes the timing and amount of market entry and exit (retirements) for the base case (best estimate) for the modeled regions. Nuclear unit retirement assumptions have changed dramatically since recent analysis. Currently it is the consensus that nuclear units will have their licenses extended past our current study period. 4-10 Southern Power - June 5, 2002 TABLE 4-12 CAPACITY ADDITIONS (MW), 2002-2004
ON- SIZE UNIT LINE DEVELOPER (PLANT) (MW)(1) TYPE YEAR ----------------- ------- ---- ---- SERC -- TOTAL = 33,061 MW Aquila Inc. (Crossroads 1) 320 CT 2002 Associated Electric Cooperative (Holden 1) 321 CT 2002 Calpine (Decatur 1) 794 CC 2002 Calpine (Morgan nrg 1) 790 CC 2002 Calpine (Parish 1) 577 CC 2002 Cleco/Calpine (Acadia b) 620 CC 2002 Cogentrix (Ouachita 1) 816 CC 2002 Cos-Mar (Carville 1) 440 CC 2002 Dow Chemical & American Power (Plaquemine 1) 900 CC 2002 Duke (Enterprise 1) 640 CT 2002 Duke (Hot Springs 1) 620 CC 2002 Duke (Marshall 1) 640 CT 2002 Duke (Murray 1) 1,240 CC 2002 Duke/Southhaven (Southaven 2) 640 CT 2002 Entergy (Lake Charles 1) 425 CC 2002 Georgia Power (Wansley 6) 567 CC 2002 Georgia Power (Wansley 7) 567 CC 2002 Mirant & CLECO (Perryville 2) 550 CC 2002 Mirant/Kinder Morgan (Wrightsville 1) 550 CC 2002 NRG (Bayou 1) 320 CT 2002 Oglethorpe Power Corp. (Talbot County 1) 435 CT 2002 Panda (El Dorado 1) 1,100 CC 2002 Panda (El Dorado 2) 1,100 CC 2002 Progress (Richmond 5-6) 550 CC 2002 Progress (Richmond 7) 186 CT 2002 Santee Cooper (Savannah 1) 512 CC 2002 Santee Cooper (Savannah 2) 168 CT 2002 Santee Cooper (Savannah 3) 168 CT 2002 Southern Company (Goat Rock 1) 571 CC 2002 Southern Company (Smith 1) 575 CC 2002 TECO (Dell 1) 600 CC 2002 TECO (Mcadams 1) 599 CC 2002 Tenaska (Lindsayhill 1) 846 CC 2002 Calpine (Columbia 1) 550 cogen 2003 Calpine (Hillabee 1) 770 CC 2003 Cogentrix (Caledonia 2) 830 CC 2003 Cogentrix (Southaven 1) 866 CC 2003 FPL Group (Calhoun 1) 616 CT 2003 Intergen (Cottonwood 1) 1,200 CC 2003 Intergen (Magnolia 1) 900 CC 2003 NRG (Pike 1) 1,200 CC 2003 Occidental Chemical (Taft 1) 778 cogen 2003 Progress (Effingham 1)(2) 376 CT 2003 Progress (Tiger Creek 1) 686 CC 2003 Reliant (Frenchcamp 1) 400 CC 2003 Reliant (Frenchcamp 2) 400 CC 2003 Southern Company (Harris 1) 618 CC 2003 Southern Company (Harris 2) 618 CC 2003 Southern Company (Goat Rock 2) 615 CC 2003 Tenask Inc. (Coral 1) 900 CC 2003 Williams (Memphis 1) 265 CC 2003 Progress (Effingham 1-2) 561 CC 2004 Progress (Rowan 4-5) 541 CC 2004 FRCC -- TOTAL = 7,015 MW City of Lakeland (McIntosh 5 expansion) 120 CC 2002 Seminole (Payne Creek) 500 CC 2002 Jacksonville (Northside 1) 297 ST 2002 Jacksonville (Northside 2) 297 ST 2002 Mirant (Pasco County) 480 CT 2002 Calpine (Auburndale) 115 CT 2002 Constellation (Oleander) 680 CT 2002 Progress Energy (DeSoto) 360 CT 2002 FPL (Fort Myers Expansion) 1,000 CC 2002 FPL (Sanford) 1,000 CC 2003 Calpine (Osprey) 529 CC 2003 Southern Company (Stanton) 617 CC 2003 Florida Power (Hines 2) 530 CC 2003 Orion Power (CPV Atlantic) 250 CC 2004 City of Lakeland (McIntosh 4) 240 ST 2004
- ----------- (1) Summer rating. (2) Retires when combined cycle comes online. Southern Power - June 5, 2002 4-11 TABLE 4-13 CAPACITY ADDITIONS AND RETIREMENTS (MW) 2005-2021
CC CT CUMULATIVE PLANTS PLANTS RETIRE- CAPACITY YEAR(1) ADDED ADDED MENTS(2) ADDITIONS ------- ------ ------ ---------- ---------- SERC 2005 0 0 0 0 2006 0 0 -7,304 -7,304 2007 0 0 -9 -7,313 2008 3,640 0 0 -3,673 2009 4,160 0 0 487 2010 4,680 0 0 5,167 2011 4,680 0 -76 9,771 2012 3,640 1,035 -116 14,330 2013 3,120 1,380 -79 18,751 2014 3,640 1,035 -42 23,384 2015 4,160 345 0 27,889 2016 2,080 2,070 0 32,039 2017 3,120 690 0 35,849 2018 2,600 1,725 0 40,174 2019 3,640 1,035 -280 44,569 2020 3,120 1,035 -116 48,608 2021 4,680 0 -391 52,897 ============================================================ TOTAL 50,960 10,350 -8,413 52,897 FRCC 2005 4,160 0 0 4,160 2006 1,560 0 0 5,720 2007 1,040 0 0 6,760 2008 1,040 0 0 7,800 2009 1,560 0 0 9,360 2010 1,040 0 0 10,400 2011 1,560 0 0 11,960 2012 1,040 0 0 13,000 2013 1,560 0 0 14,560 2014 1,560 0 0 16,120 2015 1,040 345 0 17,505 2016 520 690 0 18,715 2017 520 1,035 -1 20,269 2018 1,040 345 0 21,654 2019 520 1,035 -32 23,177 2020 1,040 345 0 24,562 2021 1,560 0 -65 26,058 ============================================================ TOTAL 22,360 3,795 -98 26,058
(1) 2002 through 2004 additions are shown in Table 4-12. (2) Retirements are assumed to occur on January 1 of year. SERC has no retirements in 2002-2004. 4-12 Southern Power - June 5, 2002 4.7 FINANCIAL ASSUMPTIONS 4.7.1 GENERIC PLANT CHARACTERISTICS The starting points for the DCF calculation are the generic unit-specific operating parameters for new combined cycles and combustion turbines. The generic parameters and assumptions assumed in the model are shown in Table 4-14. The first year in which new generic capacity can be added to the model is 2005. Capital costs are assumed to decrease at 1% per annum (real 2001 $). Table 4-15 indicates the assumed schedule and effect of technology improvement on new unit heat rates. TABLE 4-14 GENERATING CHARACTERISTICS OF NEW UNITS (REAL 2001 $)
CAPITAL FIXED VARIABLE COST O&M(1) O&M SIZE ($/KW) ($/KW-YEAR) ($/MWH) (MW) ------- ----------- -------- ---- NEW CCS SERC-Southern 530 10.5 $2.00 520 FRCC 530 10.5 $2.00 520 NEW CTS SERC-Southern 325 5.5 $5.00 345 FRCC 325 5.5 $5.00 345
(1) Fixed O&M does not include additional charges for pipeline reservation (where applicable). TABLE 4-15 FULL LOAD HEAT RATE IMPROVEMENT(1) (BTU/KWH)
2002-2003 2004-2008 2009-2013 2014-2018 2019+ --------- --------- --------- --------- ------ CC 6,834 6,697 6,564 6,432 6,304 CT 10,712 (W) 10,498 (W) 10,288 (W) 10,082 (W) 9,880 (W) 11,022 (S) 10,801 (S) 10,585 (S) 10,373 (S) 10,166 (S)
(1) Degradation of 2% for CC units and 3% for CT units was assumed. (W) = winter, (S) = summer. 4.7.2 OTHER EXPENSES Information on fixed costs, depreciation, and taxes is also developed and incorporated within the DCF analysis to determine the economic viability of the new unit additions. Environmental costs and overhaul expenses are not included, due to expectations that such expenses would be minimal in early years of operation. - - Property taxes are assumed to be 1% to 2% of the initial capital costs. - - Depreciation of the initial all-in cost of the new additions is based on a standard 20-year Modified Accelerated Cost Recovery System (150 DB) with mid-year convention. 4.7.3 ECONOMIC AND FINANCIAL ASSUMPTIONS - - Minimum internal rate of return is assumed to be 13.5%. - - Financing assumptions are assumed to be 60% debt and 40% equity for combined cycle units, and 50% debt and 50% equity for combustion turbine units. - - Debt interest rate is assumed to be 9.0%. Debt terms and project lives are 15 years with mortgage-style amortization for combustion turbine units and 20 years for combined cycle units. Southern Power - June 5, 2002 4-13 This page intentionally left blank. 4-14 Southern Power - June 5, 2002 5. REGIONAL ANALYSIS 5.1 INTRODUCTION Over the past two decades, the structure of the electric power industry has been dramatically changed by the emergence of a networked industry. A market trend that has paralleled the integration of the transmission network is the introduction of wholesale and retail competition in formerly regulated markets. These market developments have added new dimensions to the risk of owning and operating generation plants. This chapter examines the current and projected development of wholesale power markets in each target region before summarizing the market price projections for the pricing areas evaluated for Southern Power (see Table 5-1). TABLE 5-1 SOUTHERN POWER ASSET PRICING AREAS
NERC REGION PRICING AREA ----------- ------------ SERC Southern Company (Southern) FRCC FRCC
One mechanism for understanding risk is to examine how market prices and generation requirements could change under different scenarios, termed sensitivity cases. Sensitivity cases and their effect on the projected market power prices are described in this chapter. 5.2 RISK ISSUES AND SENSITIVITY CASES Analysis of possible variances in fundamental variables is essential when forecasting market prices in the United States today. Initially a base case was developed for each region using the assumptions outlined in Chapter 4. The base case is defined as the best estimate given the stated assumptions but not as the most likely case. Three sensitivity cases were then developed to aid in understanding some of the downside risks of operating generation assets. It should be recognized that these cases will vary to the extent the input assumptions change, and such assumptions should be reviewed with the same rigor as the resulting forecasts. The four cases are outlined below: - The BASE CASE incorporates the actual futures gas prices through December 2004 (2003 for oil). Prices then decrease linearly to the consensus forecast price in year 2006 (2005 for oil). This method is discussed in further detail in Chapter 4. - The LOW FUEL CASE evaluates the effects of lower gas and oil prices represented as a $0.50/MMBtu reduction in the 2002 consensus gas and oil prices with escalation remaining unchanged (coal prices are not changed). - The HIGH FUEL CASE evaluates the effects of higher gas and oil prices represented as a $0.50/MMBtu increase in the 2002 gas and oil prices with escalation remaining unchanged (coal prices are not changed). - The OVERBUILD CASE evaluates an exuberance of merchant plant development. For purposes of this case, excess entry is presumed to occur early in the study period. PA assumed additional capacity in 2003-2004 in SERC and FRCC. (See Table 5-2.) Subsequent to this period of capacity abundance, as the regions experience load growth, we assume the markets eventually return to economic equilibrium. TABLE 5-2 OVERBUILD CASE MERCHANT PLANT CAPACITY ADDITIONS(1) (MW)
REGION 2002 2003 2004 2005 ------ ---- ----- ----- ---- SERC 0 8,135 2,425 0 FRCC 0 5,700 1,560 0
(1) Overbuild capacity in addition to base case merchant capacity. These variances from the base case influence the resulting projections of market price forecasts and subsequent valuation of generation plants. It should be noted that the level of the sensitivities can vary and that there are other areas that can vary in the forecast, including but not limited to demand forecasts, new entrant technologies and construction costs, environmental costs, and regulatory structures. Southern Power - June 5, 2002 5-1 The remaining sections of this chapter provide discussions of each of the relevant regions. Each regional section contains the following information: - the region's background - the power market structures currently in place - current transmission system issues - market characteristics - price forecasts - critical market factors - dispatch curves. The market characteristics section for each region contains a figure illustrating the energy and capacity by fuel type. The energy generated by fuel type is estimated based on results of the PA regional models. The capacity by fuel type is based on Energy Information Administration (EIA) Form EIA-411 data or its equivalent. The capacity includes additional new generating capacity additions assumed by PA to be online in 2002. The specific sources from which the information was obtained and the year the information is based upon are provided in the sources listed under the figures. Information on state regulatory activities associated with deregulation of the electric industry can be found in Section 2.3. Each regional section of this chapter includes the results of the various cases. - The ENERGY PRICE forecast represents the average annual system marginal cost of generating energy in a particular market. - The COMPENSATION FOR CAPACITY forecasts estimates the total compensation for capacity that generators need to receive over and above the system marginal cost energy price in order to keep a minimum amount of generation in the market. It should be noted that not all generators will receive the full capacity compensation outlined herein. The compensation for capacity was derived for the entire SERC and FRCC market regions. - The ALL-IN PRICE forecast combines the energy price and the compensation for capacity (assuming 100% load). The all-in price reflects PA's estimate of the total market price that generators must receive to keep the market in equilibrium. To show recent trends in electricity prices, Figure 5-1 provides recent electricity price information obtained from Power Markets Week. The values are the on-peak daily index values for April 1999 through March 2002 for the regions of interest. FIGURE 5-1 HISTORICAL ELECTRICITY PRICES (DAILY ON-PEAK INDEX)(NOMINAL $) [CHART] 5-2 Southern Power - June 5, 2002 5.3 SERC 5.3.1 BACKGROUND This section describes the current, proposed, and potential structure of the power market within the SERC region. 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 maximize the efficiency of the planning and operation of individual electric systems within the region in order to ensure system stability and reliability. The SERC region is subdivided into pricing areas: Entergy, Southern Company (Southern), Tennessee Valley Authority (TVA), and Virginia and Carolinas (VACAR). Figure 5-2 shows the SERC region. From a national perspective, SERC lags behind the Northeast and California in terms of implementing RTOs and competitive market structures. The SERC energy market is characterized by largely informal market arrangements with the majority of power sold through bilateral agreements rather than through a power exchange or other formal marketplace. 5.3.2 POWER MARKETS Southern Power's assets in SERC are located in the Southern pricing area. (See Figure 5-2.) Unlike more tightly coordinated electrical markets in other regions, SERC lacks a generation or transmission market. The SERC wholesale market is informally organized with the majority of transactions completed through bilateral agreements. Within the region it is possible to conduct short-term financial trading of electricity futures contracts at the TVA and Entergy delivery points. These contracts are traded on the Chicago Board of Trade and New York Mercantile Exchange, respectively. SERC currently functions primarily as a bilateral market whereby buyers and sellers enter into short- and long-term contracts for capacity and energy. Typically these contracts include both an energy and capacity payment. The SERC Executive Committee is contemplating the creation of a market interface committee (MIC) to coordinate SERC's policies and activities with the national-level MIC organized by NERC. One reason for establishing such a committee is to allow greater participation by merchant power producers in SERC market policy and direction. The proposed MIC may FIGURE 5-2 GENERATION ASSETS IN THE SERC REGION [CHART] be responsible for drafting new market procedures, should SERC establish a formalized regional power market at some point in the future. 5.3.3 TRANSMISSION SYSTEM Several of the largest utilities in the United States (Southern Company, Entergy, and the TVA) dominate the region's generation and transmission facilities. Like all other transmission owning utilities, these utilities provide "open access" transmission service under FERC Order No. 888. Under Order No. 888, transmission owners are required to offer firm transmission capacity to the extent that they have any available, and to treat users of their transmission system on the same basis as they use the system for their own purposes. This is considered a "non-discriminatory" standard. While utilities in SERC offer "open access," transmission rate pancaking (when power crosses more than one transmission system and is subject to two or more tariffs) makes it challenging to move power more than a couple of transmission wheels. Most of the region's utilities are just beginning to explore new market structures, such as the creation of a regional ISO. However, Entergy has proposed the creation of a transmission company subsidiary to operate and manage its transmission assets in Arkansas, Mississippi, Texas, and Louisiana, and has filed this proposal with the FERC for approval. The Louisiana PSC has moved to block the Entergy TRANSCO. In addition, Dominion Resources initially joined the Alliance RTO, which failed to get FERC approval, so Dominion then joined the SeTrans RTO. Southern Power - June 5, 2002 5-3 5.3.4 MARKET CHARACTERISTICS A. FUEL MIX As illustrated in Figure 5-3, SERC is largely dependent on coal-fired and nuclear resources for baseload generation. Coal-fired generation is the predominant resource in terms of both the energy production and the installed capacity in SERC, accounting for 51% of the energy produced and 37% of the installed capacity in the region. Nuclear facilities produce 29% of the energy and account for 16% of the installed capacity. Gas- and oil-fired units produce 15% of the energy and account for 37% of the installed capacity. The remainder of SERC's installed capacity and baseload generation is composed of hydro units. FIGURE 5-3 SERC FUEL MIX ENERGY AND CAPACITY - 2002 [CHART] B. MARKET DYNAMICS Southern Power's assets evaluated in this report located in SERC include gas-fired plants representing 4,366 MW of capacity. The load and resource balance for the SERC region is shown below in Figure 5-4. Peak demand in the SERC market is forecasted to grow at an annual compound rate of approximately 2.0% per year from 2002 through 2021. A required system-wide reserve margin of 15% is assumed through 2006, and it drops to 13% from 2007 through the remainder of the study period. FIGURE 5-4 SERC LOAD AND RESOURCE BALANCE [CHART} 5-4 Southern Power - June 5, 2002 5.3.5 PRICE FORECASTS A. BASE CASE MARKET RESULTS Near-term fuel prices are modeled based on recent actual spot prices and futures prices through December 2004, decreasing linearly to the long-term consensus view by 2006. The all-in price represents a combined compensation for capacity and energy price (assuming a 100% load factor). The compensation for capacity contribution to the all-in price ranges between approximately $1.68/MWh and $6.23/MWh. The forecasts of energy prices, capacity compensation, and all-in prices are shown in Figure 5-5 for the SERC-Southern pricing area. FIGURE 5-5 SERC-SOUTHERN COMPENSATION FOR CAPACITY, ENERGY, AND ALL-IN PRICE FORECASTS(1) [CHART] Southern Power - June 5, 2002 5-5 B. SENSITIVITY CASES ANALYSIS The all-in prices for the sensitivity cases described in Section 5.2 are shown in Figure 5-6 for the SERC-Southern pricing area. The sensitivities evaluated were the low fuel, high fuel, and overbuild cases. These sensitivities are not meant to reflect bounding or worst case scenarios. The high fuel case yields consistently higher all-in prices (in the range of $2.00 to $3.80/MWh) as compared the base case. Conversely, the low fuel case yields consistently lower all-in prices, of the same magnitude, as compared to the base case. The additional merchant surplus in the overbuild case depresses all-in prices up to $3.80/MWh in 2008. The overbuild prices return to the level of the base case by 2011 as the market absorbs the additional surplus. FIGURE 5-6 SERC-SOUTHERN SENSITIVITY CASES ALL-IN PRICE FORECASTS(1) ($/MWH) [CHART] 5-6 Southern Power - June 5, 2002 C. PROJECTED GROSS MARGINS Figure 5-7 shows projected gross margins for Southern Power's SERC assets evaluated in this report for the base case and sensitivity cases for the period 2002-2022. FIGURE 5-7 GROSS MARGINS FOR SOUTHERN POWER'S SERC ASSETS BY CASE(1) (REAL 2001 $) [CHART] Southern Power - June 5, 2002 5-7 5.3.6 CRITICAL MARKET FACTORS A. SPARK SPREADS Figure 5-8 shows the base case spark spread, which is the avoided cost or the net price of electricity after fuel costs for a combined cycle. It is calculated by subtracting fuel costs from the market clearing price. Variable O&M costs are not included in PA's calculation of spark spreads. PA used a heat rate of 6,834 Btu/kWh for the base case spark spread. The spark spread for SERC in Figure 5-8 is depressed in early years because of the surplus of merchant capacity. As the market absorbs the excess capacity and moves to equilibrium, the spark spread for the base case stabilizes around $13/MWh. B. GAS PRICES Natural gas accounts for 34% and 15% of capacity and energy, respectively, in the SERC region in 2002. These resources significantly influence the marginal cost of energy. By 2021, natural gas is the marginal fuel over 85% of the time (see Figure 5-8). Consequently, regardless of the fuel burned by an individual unit, the revenue that is earned will be significantly influenced by the price of natural gas. Figure 5-9 shows the fuel forecasts overlaid on the base case price results. The fuel forecasts represent the delivered natural gas prices for a new unit. Again, because the market is in an overbuild situation, the rise in gas prices in 2003-2004 does not trigger a significant jump in all-in prices. C. NEW CAPACITY For 2002-2004, over 33,000 MW of merchant capacity is expected to be added to the SERC region. This merchant surplus creates an overbuild situation that depresses capacity compensation in the near term. Capital investment in merchant generation is treated as a sunk cost; therefore, an overbuild situation created by merchants depresses capacity compensation in the near term. The market absorbs the surplus and returns to equilibrium by 2008. The forecasted supply and demand can be seen in the load and resource graph in Figure 5-10. D. LOAD GROWTH Due to the factors described above, load growth is a key driver in the SERC region. A higher load growth allows any merchant capacity to be absorbed in the FIGURE 5-8 SERC - SPARK SPREADS & FUEL ON THE MARGIN [CHART] FIGURE 5-9 SERC - FUEL FORECASTS & MARKET RESULTS [CHART] FIGURE 5-10 SERC - LOAD & CAPACITY DEMAND [CHART] 5-8 Southern Power - June 5, 2002 capacity market. The average annual rate of 2.0% was taken from the 2002 EIA Annual Energy Outlook forecast. The load and resource graph in Figure 5-10 illustrates the load growth and reserve margin assumptions for the overbuild period. 5.3.7 DISPATCH CURVES Dispatch curves for the SERC region for 2006 and 2012 are shown in Figure 5-11. The dispatch curves show the annual average marginal dispatch cost of the target assets as compared to the other generators in the market. FIGURE 5-11 SERC DISPATCH CURVES FOR 2006 AND 2012 [CHART] Southern Power - June 5, 2002 5-9 5.4 FRCC 5.4.1 BACKGROUND FRCC was established on September 16, 1996, to ensure and enhance the reliability and adequacy of bulk electricity supply in Florida. FRCC became the tenth reliability region of NERC. FRCC is limited to the State of Florida and coexists with a single state regulatory environment where there is emerging wholesale competition but little interest in establishment of retail competition. There are currently 35 members in FRCC, including IOUs, cooperative systems, municipals, IPPs, and power marketers. However, the majority of the retail market is controlled by five utilities: Florida Power & Light Co. (FPL), Florida Power Corporation (FPC), Tampa Electric Company (TECO), Jacksonville Electric Authority (JEA), and Gulf Power Company (Gulf). Collectively, FPL, FPC, and TECO own or operate approximately 75% of the total generation capacity in the state. In addition, a number of small municipal utilities in the state purchase power from other utilities under wholesale power agreements. The state has twelve separate control areas. The electricity market in Florida, like other states dominated by IOUs, is organized around utility service territories. FPL dominates the southern and eastern portions of the state while FPC's service territory covers the central and northern areas. TECO is centered in the middle of the state near Tampa and JEA provides power to Jacksonville residents in the northeast. Gulf, a Southern Company, is located in the far west in the Florida panhandle. 5.4.2 POWER MARKETS Historically, the State of Florida has encouraged the development of non-utility generators through utility proposals for wholesale generation. Approximately 11% of Florida's electric capacity is served by non-utility generators.(12) The Florida Public Service Commission (FPSC) encouraged the use of wholesale market for inter-utility sales through the formation of the Florida Energy Broker. However, despite a profit incentive mechanism associated with its use, the mechanism is not widely used since most sales are made under long-term contracts. In recent years, reserve margins forecast in Florida have decreased. The FPSC became concerned with the decrease in reserve margins and the potential impact on reliability and it investigated the adequacy of reserve margins for all of the utilities in peninsular Florida. The investigation concluded in November 1999 when the FPSC approved an agreement by FPL, FPC, and TECO to adopt a voluntary 20% reserve margin starting in the summer of 2004. The reserve margin agreement does not extend to municipal or cooperative utilities who are allowed to maintain their current level of reserves. Given the forecast supply shortfall and the recent decision by FPL, FPC, and TECO to maintain a 20% reserve margin, there has been considerable interest by merchant plant developers. Several companies have announced plans to construct merchant plants in Florida over the next five years. Although there are a number of proposals for the construction of independent power plants to contractually serve both investor- and municipal-owned utilities, the IOUs mounted a successful legal challenge at the State Supreme Court level to deny FPSC's authority to license merchant plants that do not have contracts with utilities for their output (see discussion in the next section). 5.4.3 TRANSMISSION SYSTEM Before 1980, Florida primarily existed as an island transmission system with limited ties to the north. Currently, there are two major 500 kV transmission lines connecting Florida with the transmission system in Southern Company's service territory. Florida's entire transmission system is regulated by FERC and the FPSC, which has jurisdiction over planning, developing, and maintaining the transmission system throughout Florida. In December 2000, FPL, FPC, and TECO submitted their Order No. 2000 compliance filing providing for the creation of an RTO. The three applicants proposed the formation of a for-profit transmission company that will act as the RTO for the FRCC region. The proposed name for the TRANSCO was Grid Florida LLC. However, in November 2001, the Florida PSC stated that a for-profit entity would not benefit the state and ordered that the utilities devise a not-for-profit entity within 90 days. In March 2002, Grid Florida filed a compliance filing with the Florida PSC revising the form and function of Grid Florida to address the perceive problems. Specifically, Grid Florida filed to be a non-profit ISO structure. - -------- (12) Based on DOE/EIA-0095(99)/1, "Inventory of Electric Utility Power Plants in the United States 1999," September 2000, and DOE/EIA-0095(99)/2, "Inventory of Nonutility Electric Power Plants in the United States 1999," November 2000. 5-10 Southern Power - June 5, 2002 5.4.4 MARKET CHARACTERISTICS A. FUEL MIX As illustrated in Figure 5-12, in year 2002, 61% of the generating capacity in FRCC consists of gas- and oil-fired units with coal accounting for 24%. Nuclear facilities account for 9% of the generating capacity, with the remaining 6% attributable to other sources. Although gas and oil units account for the majority of the generating capacity, they only account for 32% of the energy produced. The fuel producing the largest portion of energy in FRCC is coal at 41%. The fuel mix of plants located in FRCC is unique due to the mix of baseload and peaking capacity. Additionally, facilities in FRCC are fueled by a unique but highly constrained gas distribution network. These constraints allow for opportunities and uncertainty around the delivery and potential redirection of fuel into load pockets to take advantage of valuation discrepancies. It is clear that as FRCC continues to develop, these gaps will be closed and financially firm contracts and distributed generation will absorb the uncertainty. FIGURE 5-12 FRCC FUEL MIX ENERGY AND CAPACITY - YEAR 2002 [CHART] FRCC is unique in that it needs a significant amount of gas pipeline capacity. Combined cycle units are purchasing pipeline capacity at significant rates (~$40/kW/yr). While gas is expected to be on the margin within the next 15 years, FRCC will need to loosen regulatory restrictions and allow combined cycles to be built to avoid a significant capacity shortage (e.g., California). B. MARKET DYNAMICS Southern Power's assets evaluated in this report located in FRCC include 411 MW (65% interest in 633 MW) of gas-fired capacity. Figure 5-13 illustrates the load and resource balance for FRCC through the end of the study period. Peak demand in the FRCC market is forecasted to grow at an annual compound rate of approximately 2.3% per year from 2002 through 2021. A required system-wide reserve margin of 17% is assumed through the study period. The load shape for FRCC has peaks in both the winter and summer. The summer peak occurs because of the expected hot weather in the summer; however, peak demand occurs in the winter because of Florida's winter tourism season. FRCC is forecasting this winter peak to occur over the next FIGURE 5-13 FRCC LOAD AND RESOURCE BALANCE [CHART] Southern Power - June 5, 2002 5-11 10 years. With this characteristic in load shape, peaking plants are able to take advantage of two periods of high-priced occurrences. 5.4.5 PRICE FORECASTS A. BASE CASE MARKET RESULTS Near-term fuel prices are modeled based on recent actual spot prices and futures prices through December 2004, decreasing linearly to the long-term consensus view by 2006. The all-in price represents a combined compensation for capacity and energy price (assuming a 100% load factor). The compensation for capacity contribution to the all-in price ranges between approximately $4.93/MWh and $7.80/MWh. The forecasts of energy prices, capacity compensation, and all-in prices are shown in Figure 5-14 for the FRCC region. FIGURE 5-14 FRCC COMPENSATION FOR CAPACITY, ENERGY, AND ALL-IN PRICE FORECASTS(1) [CHART] 5-12 Southern Power - June 5, 2002 B. SENSITIVITY CASES ANALYSIS The all-in prices for high fuel, low fuel, and overbuild sensitivity cases described in Section 5.2 are shown in Figure 5-15 for the FRCC region. These sensitivities are not meant to reflect bounding or worst case scenarios. The high fuel case yields consistently higher all-in prices (in the range of $2.80 to $3.80/MWh) as compared the base case. Conversely, the low fuel case yields consistently lower all-in prices, of the same magnitude, as compared to the base case. The additional merchant surplus in the overbuild case depresses all-in prices up to $7.10/MWh in 2004. The overbuild prices return to the level of the base case by 2010 as the market absorbs the additional surplus. FIGURE 5-15 FRCC SENSITIVITY CASES ALL-IN PRICE FORECASTS(1) ($/MWH) [CHART] Southern Power - June 5, 2002 5-13 C. PROJECTED GROSS MARGINS Figure 5-16 shows projected gross margins for Southern Power's FRCC assets evaluated in this report for the base case and sensitivity cases for the period 2002-2022. FIGURE 5-16 GROSS MARGINS FOR SOUTHERN POWER'S FRCC ASSETS BY CASE(1) (REAL 2001 $) [CHART] 5-14 Southern Power - June 5, 2002 5.4.6 CRITICAL MARKET FACTORS A. SPARK SPREADS Figure 5-17 shows the base case spark spread, which is the avoided cost or the net price of electricity after fuel costs for a combined cycle. It is calculated by subtracting fuel costs from the market clearing price. Variable O&M costs are not included in PA's calculation of spark spreads. PA used a heat rate of 6,834 Btu/kWh for the base case spark spread. The spark spread for FRCC in Figure 5-17 declines in early years because of the increase in natural gas as the marginal fuel. Once the market reaches equilibrium in 2005, the spark spread remains consistent at $14/MWh for the base case. B. GAS PRICES Natural gas accounts for 34% and 19% of capacity and energy, respectively, in the FRCC region in 2002. These resources significantly influence the marginal cost of energy. By 2021, natural gas is the marginal fuel over 85% of the time (see Figure 5-17). Consequently, regardless of the fuel burned by an individual unit, the revenue that is earned will be significantly influenced by the price of natural gas. Figure 5-18 shows the fuel forecasts overlaid on the base case price results. The fuel forecasts represent the delivered natural gas prices for a new unit. C. NEW CAPACITY For 2002-2004, over 7,000 MW of merchant capacity is expected to be added to the FRCC region. The market is expected to be in equilibrium starting in 2005. The forecasted supply and demand can be seen in the load and resource graph in Figure 5-19. D. LOAD GROWTH Due to the factors described above, load growth is a key driver in the FRCC region. A higher load growth allows merchant capacity to be absorbed more quickly in the capacity market. The average annual rate of 2.3% was taken from the 2002 EIA Annual Energy Outlook forecast. This load growth, coupled with a reserve margin of 17%, allows FRCC to avoid an overbuild situation in the base case. The load and resource graph in Figure 5-19 illustrates the load growth and reserve margin assumptions for the first ten years of the base case. FIGURE 5-17 FRCC - SPARK SPREADS & FUEL ON THE MARGIN [CHART] FIGURE 5-18 FRCC - FUEL FORECASTS & MARKET RESULTS [CHART] FIGURE 5-19 FRCC - LOAD & CAPACITY DEMAND [CHART] Southern Power - June 5, 2002 5-15 5.4.7 DISPATCH CURVES Dispatch curves for the FRCC region for 2006 and 2012 are shown in Figure 5-20. The dispatch curves show the annual average marginal dispatch cost of the target assets as compared to the other generators in the market. FIGURE 5-20 FRCC DISPATCH CURVES FOR 2006 AND 2012 [CHART] 5-16 Southern Power - June 5, 2002 $575,000,000 SOUTHERN POWER COMPANY A SUBSIDIARY OF (SOUTHERN COMPANY LOGO) OFFER TO EXCHANGE ALL OUTSTANDING 6.25% SENIOR NOTES, SERIES A DUE JULY 15, 2012 FOR 6.25% SENIOR NOTES, SERIES B DUE JULY 15, 2012 (REGISTERED UNDER THE SECURITIES ACT OF 1933) UNTIL DECEMBER 29, 2002, ALL DEALERS THAT EFFECT TRANSACTIONS IN THESE SECURITIES, WHETHER OR NOT PARTICIPATING IN THIS OFFERING, MAY BE REQUIRED TO DELIVER A PROSPECTUS. THIS IS IN ADDITION TO THE DEALERS' OBLIGATION TO DELIVER A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR SUBSCRIPTIONS. -----END PRIVACY-ENHANCED MESSAGE-----