-----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, S6mvbn739MKWwcLB7df3+Ot+I20CVECE+Cmhb7TSCHlOkZU8CWMaFc9AQUMlgYc4 eocthwsloRDFLmRQrfgzgQ== 0001160661-03-000002.txt : 20031114 0001160661-03-000002.hdr.sgml : 20031114 20031114132550 ACCESSION NUMBER: 0001160661-03-000002 CONFORMED SUBMISSION TYPE: S-4 PUBLIC DOCUMENT COUNT: 14 FILED AS OF DATE: 20031114 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: S-4 SEC ACT: 1933 Act SEC FILE NUMBER: 333-110498 FILM NUMBER: 031002581 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 S-4 1 southernpower.txt AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON NOVEMBER 14, 2003 SUBJECT TO AMENDMENT REGISTRATION NO. 333- - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 --------------------- FORM S-4 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 --------------------- SOUTHERN POWER COMPANY (Exact name of registrant as specified in its charter) DELAWARE 4911 58-2598670 (State or other jurisdiction of (Primary standard industrial (I.R.S. Employer incorporation or organization) classification code number) Identification Number)
270 PEACHTREE STREET, N.W. ATLANTA, GEORGIA 30303 (404) 506-5000 (Address, including zip code, telephone number, including area code, of the registrant's principal executive offices) --------------------- TOMMY CHISHOLM SECRETARY SOUTHERN POWER COMPANY 270 PEACHTREE STREET, N.W. ATLANTA, GEORGIA 30303 (404) 506-0544 (Name, address, including zip code, and telephone number, including area code, of agent for service of the registrant) --------------------- COPIES TO: THOMAS A. FANNING CLIFF S. THRASHER WALTER M. BEALE, JR. EXECUTIVE VICE PRESIDENT, CHIEF FINANCIAL OFFICER BALCH & BINGHAM LLP CHIEF FINANCIAL OFFICER SOUTHERN POWER COMPANY 1901 SIXTH AVENUE NORTH AND TREASURER 270 PEACHTREE STREET, N.W. SUITE 2600 THE SOUTHERN COMPANY ATLANTA, GEORGIA 30303 BIRMINGHAM, ALABAMA 35203 270 PEACHTREE STREET, N.W. ATLANTA, GEORGIA 30303
--------------------- APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after the effective date of this Registration Statement. If the securities being registered on this form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. [ ] If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] ____________ If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] ____________ --------------------- CALCULATION OF REGISTRATION FEE
- ---------------------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------------------- TITLE OF AMOUNT PROPOSED MAXIMUM PROPOSED MAXIMUM AMOUNT OF EACH CLASS OF SECURITIES TO BE OFFERING PRICE AGGREGATE OFFERING REGISTRATION TO BE REGISTERED REGISTERED PER UNIT(1) PRICE(1) FEE(2) - ---------------------------------------------------------------------------------------------------------------------- 4.875% Senior Notes, Series D due July 15, 2015................... $575,000,000 100% $575,000,000 $46,518 - ---------------------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------------------
(1) The proposed maximum aggregate offering price represents the total value of the notes being exchanged under this Registration Statement. (2) The registration fee has been calculated pursuant to Rule 457(f)(2) under the Securities Act. THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF THE SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A), MAY DETERMINE. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF THE SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A), MAY DETERMINE. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the securities and exchange commission is effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted. SUBJECT TO COMPLETION, DATED NOVEMBER 14, 2003 PRELIMINARY PROSPECTUS $575,000,000 SOUTHERN POWER COMPANY A SUBSIDIARY OF (SOUTHERN COMPANY LOGO) OFFER TO EXCHANGE ALL OUTSTANDING 4.875% SENIOR NOTES, SERIES C DUE JULY 15, 2015 FOR 4.875% SENIOR NOTES, SERIES D DUE JULY 15, 2015 (REGISTERED UNDER THE SECURITIES ACT OF 1933) THE EXCHANGE OFFER WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON ___________ , 200 _ , UNLESS EXTENDED We are offering you the opportunity to exchange your 4.875% Senior Notes, Series C due July 15, 2015 that are not registered under the Securities Act of 1933 for our new 4.875% Senior Notes, Series D due July 15, 2015 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 ____________ , 200 __ , 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 47 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 ____________ , 200 __ 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 4.875% Senior Notes, Series C due July 15, 2015 issued in a private offering on July 8, 2003, we will refer to them collectively as the "Original Senior Notes" and each individually as an "Original Senior Note." Whenever we refer to the 4.875% Senior Notes, Series D due July 15, 2015 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............................................. 19 Capitalization.............................................. 19 Selected Historical Financial Data.......................... 20 Our Business................................................ 21 The Exchange Offer.......................................... 27 Description of The Exchange Senior Notes and The Indenture................................................. 36 Material U.S. Federal Income Tax Considerations............. 47 Ratings..................................................... 48 Plan of Distribution........................................ 48 Experts..................................................... 48 Independent Engineer........................................ 49 Independent Market Expert................................... 49 Legal Matters............................................... 49 Annex A -- Independent Engineer's Report.................... A-1 Annex B -- Independent Market Expert's Report............... B-1
------------------------------------------------------ WHERE TO FIND MORE INFORMATION We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and in accordance therewith file reports and other information with the Securities and Exchange Commission (the "SEC" or the "Commission"). Such reports and other information can be inspected and copied at the Public Reference Room of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549, and at the SEC's Regional Offices at 801 Brickell Avenue, Suite 1800, Miami, Florida 33131 and 233 Broadway, New York, New York 10279. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. Copies of such material can also be obtained at prescribed rates by writing to the Public Reference Section of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549. The SEC maintains a Web site that contains reports and other information regarding registrants including us that file electronically at http://www.sec.gov. The SEC allows us to "incorporate by reference" the information we file with them, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is considered to be part of this prospectus, and later information that we file with the SEC will automatically update and supersede this information. We incorporate by reference the documents listed below and any future filings made with the SEC under Sections 13(a), 13(c) 14 or 15(d) of the Exchange Act until we complete the Exchange; provided, however, we are not incorporating any information furnished under Items 9 or 12 of any Current Report on Form 8-K. (a) Annual Report on Form 10-K for the fiscal year ended December 31, 2002; (b) Quarterly Reports on Form 10-Q for the quarters ended March 31, 2003, June 30, 2003 and September 30, 2003; (c) Current Reports on Form 8-K dated April 21, 2003 and May 21, 2003. ii You may request a copy of these filings, 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 , 200 , 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, scheduled completion of new generating facilities, 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; - contract counterparty risk; - 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; - 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; - current and future litigation; or iii - the direct or indirect impact on our Company's business resulting from the August 2003 power outage in the northeast or any similar such incidents. 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 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"). We provide the means by which Southern can own, develop, construct and acquire new generation assets outside of the traditional rate-based state regulated generation structure. Consequently, our business activities are not subject to traditional state regulation of utilities, but are subject to regulation by the Federal Energy Regulatory Commission (the "FERC"). We are the primary vehicle to develop Southern's position in the energy markets in the Southeastern United States, with substantially all of our generating capacity 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 SEC 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 operating companies, including us, and its service company: (SOUTHERN CO. FLOW CHART) We acquired substantially all of our operating or under construction generating facilities and facility sites from affiliates of Southern. 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 own, develop, construct and acquire generating facilities in the "Super Southeast" region (as described below) of the United States and sell the output of our generating facilities primarily under long-term, fixed-price power 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 Carolina, South Carolina, Tennessee and Virginia. Although we 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. 1 As of October 1, 2003, we had 4,795 megawatts ("MW") of generating capacity in commercial operation and 1,240 MW in preliminary stages of construction. By the end of 2005, we expect to have approximately 6,000 MW of generating capacity in commercial operation. Currently, substantially all of our existing and under construction generating capacity from these facilities is committed under long-term PPAs, mostly with the Operating Companies, but also with certain unaffiliated third parties (collectively, the "PPA Counterparties"). All of the PPA Counterparties have solid investment grade credit ratings. 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 are 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. As a member of the Southern Pool, we also realize other benefits traditionally associated with pooling arrangements, such as economies of scale and geographic load diversity. The Southern Pool includes approximately 42,000 MW of generating capacity. For each of our generating facilities located in the service territory of an Operating Company, there is or 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. However, for the most part, such interchange transactions are now conducted under market-based tariff arrangements. We expect that any 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 located inside 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 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 provide operation and maintenance services for that facility. Additionally, under the terms of a services agreement, SCS performs overall project management of the construction process of our generating facilities. 2 BUSINESS STRATEGY Our strategy is to continue to own, develop, construct and acquire additional generating facilities to compete for and serve 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 approximately 6,000 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 HISTORICAL FINANCIAL INFORMATION Southern Power commenced operations effective January 8, 2001. The following table sets forth our summary historical financial information as of December 31, 2002 and 2001 and for the periods then ended and as of September 30, 2003 and for the nine months ended September 30, 2003 and 2002. This summary financial information has been derived from our financial statements and related notes incorporated by reference in this prospectus. The information set forth below is qualified in its entirety by reference to and should be read together with management's discussion and analysis of results of operations and financial information, the financial statements and related notes and other financial information incorporated by reference in this prospectus.
NINE MONTHS ENDED PERIOD FROM SEPTEMBER 30 INCEPTION -------------------- YEAR ENDED (JANUARY 8, 2001) TO 2003 2002 DECEMBER 31, 2002 DECEMBER 31, 2001 -------- -------- ----------------- -------------------- (UNAUDITED) ($ IN THOUSANDS) INCOME STATEMENT DATA Operating Revenues...................... $554,344 $213,271 $298,768 $29,301 Operating Expenses...................... 315,701 143,840 202,573 18,814 -------- -------- -------- ------- Operating Income........................ 238,643 69,431 96,195 10,487 Other Income (Expense), net............. (1,159) (4,595) (4,582) 658 Total Interest Expense, net............. (17,930) (4,362) (8,886) (427) -------- -------- -------- ------- Earnings Before Income Taxes............ 219,554 60,474 82,727 10,718 Income Taxes............................ 77,367 19,832 28,457 2,511 -------- -------- -------- ------- Earnings Before Cumulative Effect of Accounting Change..................... 142,187 40,642 54,270 8,207 Cumulative Effect of Accounting Change -- Less Income Taxes of $231... 367 -- -- -- -------- -------- -------- ------- Net Income.............................. $142,554 $ 40,642 $ 54,270 $ 8,207 OTHER FINANCIAL DATA Ratio of Earnings to Fixed Charges (1)................................... 4.95x 2.19x 2.07x 3.36x
AS OF AS OF SEPTEMBER 30 DECEMBER 31 ------------ --------------------- 2003 2002 2001 ------------ ---------- -------- (UNAUDITED) ($ IN THOUSANDS) BALANCE SHEET DATA Total Current Assets........................................ $ 165,494 $ 73,622 $ 27,639 Plant in Service, net....................................... 1,628,484 874,573 261,862 Construction Work in Progress............................... 593,826 1,082,987 500,358 Other Assets and Deferred Charges........................... 55,808 54,794 32,998 ---------- ---------- -------- Total Assets................................................ $2,443,612 $2,085,976 $822,857 ========== ========== ======== Current Liabilities, excluding Subordinated Note Payable to Parent.................................................... $ 164,515 $ 74,895 $ 31,693 Deferred Credits and Other Liabilities...................... 60,301 98,110 30,016 Long-Term Debt.............................................. 1,149,060 955,879 293,205 Subordinated Note Payable to Parent......................... 500 210,488 950 Common Stockholder's Equity................................. 1,069,236 746,604 466,993 ---------- ---------- -------- Total Liabilities and Stockholder's Equity.................. $2,443,612 $2,085,976 $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 2023. You should read the entire 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. 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 prospective purchasers 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. In addition to our generating facilities in commercial operation as of the date of the report, Stanton A and McIntosh 10 and McIntosh 11 have been incorporated into these projections as of their scheduled in-service dates. The following information reflects the base case assumptions set forth in the Independent Engineer's Report.
YEAR ENDING DECEMBER 31, ---------------------------------------------------------------------------- 2003(1) 2004 2005 2006 2007 2013 2018 2023 ------- ------ ------ ------ ------ -------- -------- -------- ($ IN MILLIONS) SELECTED PROJECTED FINANCIAL DATA Total Revenues........... $272.8 $444.0 $500.2 $554.1 $549.1 $1,041.0 $1,001.9 $1,182.6 Fuel Expenses.......... $ 46.6 $ 29.7 $ 0.0 $ 0.4 $ 1.8 $ 412.7 $ 382.6 $ 545.7 Non-Fuel Expenses...... $ 88.9 $101.1 $128.6 $146.2 $159.4 $ 150.1 $ 145.2 $ 162.7 Total Expenses........... $135.5 $130.8 $128.6 $146.7 $161.2 $ 562.8 $ 527.8 $ 708.4 Cash Flow Available for Debt Service (CFADS)... $137.3 $313.2 $371.7 $407.4 $387.9 $ 478.3 $ 474.2 $ 4 74.1 CFADS Interest Coverage Ratio.................. 3.99x 4.55x 4.46x 4.17x 3.97x 4.90x 4.86x 4.86x 2003-2015 Average........ 4.41x 2003-2023 Average........ 4.60x
YEAR ENDING DECEMBER 31, --------------------------------------- AVERAGE AVERAGE 2003(1) 2004 2005 2006 2007 2003-2007 2003-2015 ------- ----- ----- ----- ----- --------- --------- Percent of Cash Flow under Contract..... 90.9 97.1 98.5 98.6 98.8 96.8 72.0(2)
- --------------- (1) For purposes of the above data, the year 2003 commenced in July 2003 and accordingly only includes six months. (2) The table above 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 4.875% Senior Notes, Series D due July 15, 2015, or Exchange Senior Notes, which have been registered under the Securities Act, for a like amount of our outstanding 4.875% Senior Notes, Series C due July 15, 2015, or Original Senior Notes, which we issued on July 8, 2003 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 , 200 , 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 July 8, 2003, 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: Mr. Bernard Arsenec By facsimile: (212) 298-1915 For information or confirmation by telephone: (212) 815-5098 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 4.875% Senior Notes, Series D due July 15, 2015. INTEREST...................... Interest will accrue on the Exchange Senior Notes from the date of delivery at a rate of 4.875% per year and will be payable semiannually in arrears on January 15 and July 15 of each year, commencing January 15, 2004. FINAL MATURITY................ July 15, 2015 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") and "BBB+" by Standard and Poor's, a division of The McGraw-Hill Companies, Inc. ("S&P"). 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 government regulation. 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 risk factors contained in Part I, Item 1 of our annual report on Form 10-K for the fiscal year ended December 31, 2002 which is incorporated by reference in this prospectus and the information contained elsewhere 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. The risks and uncertainties not presently known to us or that we deem immaterial may also impair our business operations, financial results and the value of the Senior Notes. 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 from power 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 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 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. 11 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 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. THE FAILURE OF ONE OF OUR PPA COUNTERPARTIES TO PERFORM ITS OBLIGATIONS, OR THE FAILURE TO RENEW THE PPAS, COULD HAVE A NEGATIVE IMPACT ON OUR EARNINGS. We have agreed to sell substantially all of our existing and under construction generation capacity to the PPA Counterparties under PPAs having initial terms of five to 15 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 negative impact on our earnings. 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 continue to 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 April 2006), issuance of commercial paper 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, fuel transportation, electric transmission and market price 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 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. 12 - 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. - 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. OUR COSTS OF COMPLIANCE WITH ENVIRONMENTAL LAWS ARE SIGNIFICANT. THE COSTS OF COMPLIANCE WITH FUTURE ENVIRONMENTAL LAWS AND THE INCURRENCE OF ENVIRONMENTAL LIABILITIES COULD HARM OUR CASH FLOW AND PROFITABILITY. 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. Additionally, existing environmental laws and regulations may be revised, or new laws and regulations may be adopted or become applicable to us. 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 IS SUBJECT TO SUBSTANTIAL ENERGY REGULATORY REQUIREMENTS. COMPLIANCE WITH CURRENT AND FUTURE REGULATORY REQUIREMENTS AND PROCUREMENT OF NECESSARY APPROVALS, PERMITS AND CERTIFICATES MAY RESULT IN SUBSTANTIAL COSTS TO US. We are 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 13 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. OUR RATES ARE SUBJECT TO REVIEW AND APPROVAL BY THE FERC. THE FERC COULD TAKE ACTION THAT REDUCES THE RATES WE CAN CHARGE OR INCREASES OUR ADMINISTRATIVE EXPENSES, OR BOTH, EITHER OF WHICH COULD HAVE A DETRIMENTAL EFFECT ON OUR BUSINESS. The Federal Power Act gives the FERC exclusive ratemaking jurisdiction over wholesale sales of electricity in interstate commerce, including the rates we charge the Operating Companies and other third parties. While we currently have general authorization from the FERC to sell wholesale electricity to non- affiliates at market-based prices, we are required to obtain specific authorization from the FERC to make such sales to affiliates, including the Operating Companies. The FERC has authorized us to charge market-based rates in connection with all of our PPAs with affiliates except for the PPAs that relate to McIntosh 10 and McIntosh 11, which were submitted to the FERC for review in April 2003. Although we believe the FERC should approve the McIntosh PPAs, some entities have opposed their approval, and the FERC has recently issued certain orders expressing its intention to apply careful scrutiny to affiliate transactions. It is possible that the FERC will not approve the McIntosh PPAs as submitted. For more information regarding the McIntosh PPAs, see -- MANAGEMENT'S DISCUSSION AND ANALYSIS -- "Future Earnings Potential" and Note Q to the financial statements of the Company in the Form 10-Q for the quarter ended September 30, 2003. The FERC retains the authority to suspend, modify or revoke our market-based rate authorization (for non-affiliate transactions and affiliate transactions) on a prospective basis, and might claim to have such authority with respect to previously approved market-based rate transactions. The FERC might suspend, modify or revoke our market-based rate authorization if, for example, it determines: (i) that the markets in which we sell generation are not workably competitive, (ii) that we, individually or together with the Operating Companies, possess market power that is not mitigated or have erected barriers to entry by competitors, (iii) that we are not charging just and reasonable rates, (iv) that we have violated affiliate abuse or reciprocal dealing standards, or (v) that we have engaged in market manipulation, fraud, deception or misrepresentation. In November 2001, the FERC announced that it might revise its analysis of whether a seller seeking to sell (or to continue to sell) power at market-based rates possesses generation market power within a particular market. The FERC also announced a new interim screening mechanism to assess such market power, along with several mitigation measures for entities that the FERC determines fail the interim screen. The FERC applied this interim screen to Southern and its affiliates with market-based rate 14 authorization, including us. It found that Southern failed the interim screen within its control area, and consequently imposed the mitigation measures on Southern and certain affiliates, including us. The FERC subsequently deferred the mitigation measures indefinitely (except for certain transmission-related mitigation measures that do not apply to us), and in January 2002 the FERC announced it would reconsider the interim screen and related mitigation measures. If the FERC were to reject market-based rate authorization for a proposed affiliate transaction, or if the FERC were to suspend, modify or revoke our market-based rate authorization for non-affiliate or previously approved affiliate transactions, we may be required to set some or all of our rates based on "cost-of-service" principles. Cost-of-service rates may be lower than market-based rates. In addition, cost-of-service rates are more expensive and difficult to administer because they require additional accounting, record keeping and reporting. In addition, on June 26, 2003, the FERC issued an order seeking comments on proposed revisions to all new and existing market-based rate tariffs and authorizations. The FERC proposes to add six specific "behavioral rules" to address potential market abuses. The order sets forth certain time limits within which market participants could bring a complaint based on these rules, but no such time limits would apply to FERC-initiated proceedings. A market-based rate seller found in violation of these rules could be subject to disgorgement of unjust profits and other non-monetary remedies, including the revocation of its market-based rate authority. Because the FERC is just beginning to receive comments on its proposal, it is not possible to predict whether or when behavioral rules might ultimately be placed in effect or the precise form or content of such rules. We cannot predict whether the FERC will revise its market power analysis or the ultimate outcome of the FERC's interim screen and related mitigation measures, nor can we predict whether the FERC will allow us to charge market-based rates for the McIntosh 10 and McIntosh 11 PPAs. However, any FERC action that suspends, modifies or revokes our market-based rate authorization for non-affiliate transactions or previously approved affiliate transactions, or denies market-based rate authorization for proposed affiliate transactions, could reduce revenues or increase administrative expenses, or both. RECENT EVENTS IN THE ENERGY MARKETS THAT ARE BEYOND OUR CONTROL HAVE INCREASED THE LEVEL OF PUBLIC AND REGULATORY SCRUTINY IN THE ENERGY INDUSTRY AND IN THE CAPITAL MARKETS. THE REACTION TO THESE EVENTS MAY RESULT IN NEW LAWS OR REGULATIONS RELATED TO OUR BUSINESS OPERATIONS OR THE ACCOUNTING TREATMENT OF OUR EXISTING OPERATIONS WHICH COULD HAVE A NEGATIVE IMPACT ON OUR NET INCOME OR ACCESS TO CAPITAL. As a result of the energy crisis in California during the summer of 2001, the filing of bankruptcy by Enron Corporation, investigations by governmental authorities into energy trading activities and the recent power outage in the northeast, companies generally in the regulated and unregulated utility businesses have been under an increased amount of public and regulatory scrutiny. The capital markets and rating agencies also have increased their level of scrutiny. This increased scrutiny could lead to substantial changes in laws and regulations affecting us, including new accounting standards that could change the way we are required to record revenues, expenses, assets and liabilities. These types of disruptions in the industry and any resulting regulations may have a negative impact on our net income or access to capital. WE RELY UPON AFFILIATES AND THIRD PARTIES TO CONDUCT IMPORTANT PARTS OF OUR BUSINESS. WE WOULD REQUIRE SUBSTANTIAL ADDITIONAL RESOURCES IF WE WERE REQUIRED TO PERFORM SUCH FUNCTIONS OURSELVES. 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 the 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 15 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 AND DECISIONS COULD BE MADE FROM PERSPECTIVES OTHER THAN THE INTERESTS SOLELY OF OUR COMPANY OR OUR CREDITORS. 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 AND SOUTHERN COULD EXERCISE THIS POWER TO THE DETRIMENT OF OUR CREDITORS. 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 Senior Notes. WE HAVE A LIMITED OPERATING HISTORY AS A STAND-ALONE POWER GENERATION COMPANY. 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 AND SUCH REGULATION MAY LIMIT OUR ABILITY TO PURSUE ACQUISITIONS OR DEVELOPMENT OPPORTUNITIES. 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. WE MAY INCUR ADDITIONAL COSTS OR DELAYS IN POWER PLANT CONSTRUCTION AND MAY NOT BE ABLE TO RECOVER OUR INVESTMENT. We are in the process of constructing new 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; 16 - 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, or if we decide to delay or cancel 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. For information regarding Franklin Unit 3's delayed construction schedule, see -- MANAGEMENT'S DISCUSSION AND ANALYSIS -- "Future Earnings Potential" and Note N to the financial statements of the Company in the Form 10-Q for the quarter ended September 30, 2003. WE ARE SUBJECT TO RISKS ASSOCIATED WITH A CHANGING ECONOMIC ENVIRONMENT, INCLUDING OUR ABILITY TO RAISE CAPITAL AND OUR ABILITY TO OBTAIN INSURANCE. In response to the September 11, 2001 terrorist attacks on the United States and the ongoing war against terrorism by the United States, the nation's economy and 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, events related to the California electric market crisis and the recent power outage in the northeast. 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. The insurance industry has also been disrupted by these events. The availability of insurance covering the risk our Company and our competitors typically insure against may decrease, and the insurance that we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms. OUR BUSINESS IS DEPENDENT ON OUR ABILITY TO SUCCESSFULLY ACCESS CAPITAL MARKETS. OUR INABILITY TO ACCESS CAPITAL MAY LIMIT OUR ABILITY TO EXECUTE OUR BUSINESS PLAN OR PURSUE IMPROVEMENTS AND MAKE ACQUISITIONS THAT WE MAY OTHERWISE RELY ON FOR FUTURE GROWTH. We rely on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from our operations. If we are not able to access capital at competitive rates, our ability to implement our business plan or pursue improvements and make acquisitions that we may otherwise rely on for future growth will be limited. We believe that we will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions or a downgrade of our credit rating may increase our cost of borrowing or adversely affect our ability to raise capital through the issuance of securities or other borrowing arrangements. Such disruptions could include: - an economic downturn; - the bankruptcy of an unrelated energy company; - capital market conditions generally; - market prices for electricity; - terrorist attacks or threatened attacks on our facilities or unrelated energy companies; - war or threat of war; or 17 - the overall health of the utility industry. REGULATORY INITIATIVES AND CHANGES IN TECHNOLOGY MAY MAKE US LESS COMPETITIVE. 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. 18 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 $568 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 (i) reduce our outstanding short-term indebtedness, (ii) to settle interest rate hedges associated with the sale of the Original Senior Notes that totaled $93.3 million and (iii) for general corporate purposes. CAPITALIZATION The following table sets forth our capitalization as of September 30, 2003. The following data is qualified in its entirety by reference to, and therefore should be read together with, the detailed information and financial statements appearing in the documents incorporated herein by reference in this prospectus.
AS OF SEPTEMBER 30, 2003 ------------------ (UNAUDITED) ------------------ ($ THOUSANDS) Long-Term Debt: Senior Notes................................................ $1,150,000 Other Long-Term Debt........................................ 1,685 Unamortized debt discount, net.............................. (2,625) ---------- Total Long-Term Debt.............................. 1,149,060 Common Stockholder's Equity................................. 1,069,236 ---------- Total Capitalization(1)..................................... $2,218,296 ==========
- --------------- (1) Total Capitalization excludes notes payable (including commercial paper), the subordinated note payable to parent and securities due within one year that totaled $102.7 million, $0.5 million and $0.2 million, respectively, at September 30, 2003. 19 SELECTED HISTORICAL FINANCIAL DATA Southern Power commenced operations effective January 8, 2001. The following table sets forth our selected historical financial data as of December 31, 2002 and 2001 and for the periods then ended and as of September 30, 2003 and the nine months ended September 30, 2003 and 2002. The information set forth below is qualified in its entirety by reference to and, therefore, should be read together with management's discussion and analysis of results of operations and financial information, the financial statements and related notes and other financial information incorporated by reference in this prospectus.
NINE MONTHS ENDED PERIOD FROM SEPTEMBER 30 INCEPTION -------------------- YEAR ENDED (JANUARY 8, 2001) TO 2003 2002 DECEMBER 31, 2002 DECEMBER 31, 2001 -------- -------- ----------------- -------------------- (UNAUDITED) ($ IN THOUSANDS) INCOME STATEMENT DATA Operating Revenues...................... $554,344 $213,271 $298,768 $29,301 Operating Expenses...................... 315,701 143,840 202,573 18,814 -------- -------- -------- ------- Operating Income........................ 238,643 69,431 96,195 10,487 Other Income (Expense), net............. (1,159) (4,595) (4,582) 658 Total Interest Expense, net............. (17,930) (4,362) (8,886) (427) -------- -------- -------- ------- Earnings Before Income Taxes............ 219,554 60,474 82,727 10,718 Income Taxes............................ 77,367 19,832 28,457 2,511 -------- -------- -------- ------- Earnings Before Cumulative Effect of Accounting Change..................... 142,187 40,642 54,270 8,207 Cumulative Effect of Accounting Change -- Less Income Taxes of $231... 367 -- -- -- -------- -------- -------- ------- Net Income.............................. $142,554 $ 40,642 $ 54,270 $ 8,207 OTHER FINANCIAL DATA Ratio of Earnings to Fixed Charges (1)................................... 4.95x 2.19x 2.07x 3.36x
AS OF AS OF SEPTEMBER 30 DECEMBER 31 ------------ --------------------- 2003 2002 2001 ------------ ---------- -------- (UNAUDITED) ($ IN THOUSANDS) BALANCE SHEET DATA Total Current Assets........................................ $ 165,494 $ 73,622 $ 27,639 Plant in Service, net....................................... 1,628,484 874,573 261,862 Construction Work in Progress............................... 593,826 1,082,987 500,358 Other Assets and Deferred Charges........................... 55,808 54,794 32,998 ---------- ---------- -------- Total Assets................................................ $2,443,612 $2,085,976 $822,857 ========== ========== ======== Current Liabilities, excluding Subordinated Note Payable to Parent.................................................... $ 164,515 $ 74,895 $ 31,693 Deferred Credits and Other Liabilities...................... 60,301 98,110 30,016 Long-Term Debt.............................................. 1,149,060 955,879 293,205 Subordinated Note Payable to Parent......................... 500 210,488 950 Common Stockholder's Equity................................. 1,069,236 746,604 466,993 ---------- ---------- -------- Total Liabilities and Stockholder's Equity.................. $2,443,612 $2,085,976 $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. 20 OUR BUSINESS We are a wholly owned subsidiary of Southern. We provide the means by which Southern can own, develop, construct and acquire new generation assets outside of the traditional rate-based state regulated generation structure. Consequently, our business activities are not subject to traditional state regulation of utilities but are subject to regulation by the FERC. We are the primary vehicle to develop Southern's position in the competitive contract-based wholesale generation market, with substantially all of our generating capacity 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 SEC 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. We acquired substantially all of our operating or under construction generating facilities and facility sites from affiliates of Southern. 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 own, develop, construct and acquire generating facilities in the Super Southeast and sell the output of our generating facilities primarily 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 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 October 1, 2003, we had 4,795 MW of generating capacity in commercial operation and 1,240 MW in preliminary stages of construction. By the end of 2005, we expect to have approximately 6,000 MW of generating capacity in commercial operation. Currently, substantially all of our existing and under construction generating capacity from these facilities is committed under PPAs with the PPA Counterparties. All of the PPA Counterparties have solid investment grade credit ratings. 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 are 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 in the Southern system, a Southern Pool member has the right to purchase that lower variable cost energy. As a member of the Southern Pool, we also realize other benefits traditionally associated with pooling arrangements, such as economies of scale and geographic load diversity. The Southern Pool includes approximately 42,000 MW of generating capacity. For each of our generating facilities located in the service territory of an Operating Company, there is or 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. However, for the most part, such interchange transactions are now conducted under market-based tariff arrangements. We expect any 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 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. 21 In order to optimize efficiencies, we 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 provide operation and maintenance services for that facility. Additionally, under the terms of a services agreement, SCS performs overall project management of the construction process of our generating facilities. BUSINESS STRATEGY Our strategy is to continue to own, 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. We currently have and intend to maintain substantially all of our existing and under construction capacity committed under PPAs mostly with the Operating Companies, but also with certain unaffiliated third parties. Currently all of our PPA Counterparties have solid investment grade credit ratings. 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 utilize employees currently in the Southern system for our day-to-day operations at our generation facilities located in Southern's service territory. In 2001, 2002 and 2003, the employees of Southern and its affiliates achieved a peak season Equivalent Forced Outage Rate ("EFOR") of less than 2 percent, which is the lowest in Southern history. SCS will perform overall project management of the construction process of our generation facilities. MITIGATE MARKET PRICE, FUEL SUPPLY, FUEL TRANSPORTATION AND ELECTRIC TRANSMISSION RISK. By negotiating long-term PPAs for substantially all of our existing and under construction generating capacity, we have attempted to lessen our exposure to market risk. Additionally, our PPAs insulate us from significant fuel supply, fuel transportation and electric transmission risks by making such risks predominantly the responsibility of the counterparties. We intend to continue this business practice. FOCUS ON THE SUPER SOUTHEAST FOR ADDITIONAL GENERATION AND WHOLESALE MARKETING OPPORTUNITIES. We focus on the Super Southeast for additional generation opportunities because of our experience with, and established presence in, the region. Additionally, the Southeast has a stable regulatory environment for electricity. EXPAND OUR ASSET BASE TO APPROXIMATELY 6,000 MW IN COMMERCIAL OPERATION BY YEAR-END 2005, WITH POTENTIAL FOR FURTHER CAPACITY ADDITIONS THEREAFTER. We intend to continue to expand our generation capacity. We currently have approximately 4,795 MW of generating capacity in commercial operation. This includes our share of the generating capacity from Stanton A which began commercial operation on October 1, 2003. Our share of the capacity of Stanton A is 422 MW. McIntosh 10 and McIntosh 11 are in preliminary stages of construction with scheduled completion dates in June 2005. The expected capacity of McIntosh 10 and McIntosh 11 is 1,240 MW. The addition of these two units will increase our capacity to approximately 6,000 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 and under construction capacity is committed under long-term, fixed-price PPAs with initial terms of five to 15 years. 22 These PPAs are predominantly with the Operating Companies who all have 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 and, except for the McIntosh 10 and McIntosh 11 PPAs, by the FERC. For more information about the McIntosh PPAs, see -- MANAGEMENT'S DISCUSSION AND ANALYSIS -- "Future Earnings Potential" and Note N to the financial statements of the Company in the Form 10-Q for the quarter ended September 30, 2003. We believe that the 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 and under construction generating capacity. Additionally, our PPAs generally allocate fuel supply, fuel transportation and electric transmission risk to the 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 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 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 Southern's traditional service territory has adopted electric utility service restructuring. 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. 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 the Independent Engineer and the Independent Market Expert accept no liability for loss, whether direct or consequential, suffered by you in reliance on their reports 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 23 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 July 1, 2003 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. 2. Based on GE's previously demonstrated capability to address 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. Through the experience of Southern Power, Alabama Power, Georgia Power, Savannah Electric or other Southern Company subsidiaries, SCS has demonstrated the capability to operate the Generating Facilities. The operating programs and procedures which are proposed or currently in place for the Generating Facilities are consistent with generally accepted practices in the industry, and SCS has incorporated organizational structures that are comparable to other facilities using similar technologies for a similar service. 7. 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. 8. 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 24 resource, and should also be capable of achieving an average annual availability of 92 percent, which includes provision for forced and scheduled maintenance. 9. Based on Beck's Phase I environmental site assessment for the McIntosh Facility, it did not identify any environmental concerns related to site contamination issues. Because no updated ESAs of previous or recent environmental investigations regarding the potential for site contamination issues at the sites of the other Generating Facilities have been provided for our review, Beck can offer no opinion with respect to potential site contamination issues at the sites of the Dahlberg, Franklin, Harris, Stanton, and Wansley Facilities, if any, or the potential for future remediation. 10. 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. Beck notes that the modification of the NPDES Permit and the Surface Water Withdrawal Permit of the adjacent steam plant to accommodate the McIntosh Facility have not yet been issued and are under review by the Georgia Environmental Protection Division. As such, Beck has not reviewed the conditions to be set forth in the permits. 11. 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. 12. 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 3.97 times the annual interest requirement in each year during the term of the Senior Notes and a weighted average coverage of 4.41 times the annual interest requirement on the Debt over the term of the Senior 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. 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 May 28, 2003, a copy of which is attached as Annex B to this prospectus. Following is a summary of the report. You should read this summary in conjunction with the full text of the Independent Market Expert's Report. Southern Power owns or has ownership interests in companies with 6,024 MW of generation capacity. 5,613 MW are in the 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 and 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, and PA Consulting and its employees cannot accept liability for loss suffered in consequence of reliance on the 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 25 sellers 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 the report, 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. 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 2003 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 2003 gas and oil base prices with escalation remaining unchanged (coal prices are not changed). - The overbuild case evaluates an exuberance of merchant plant development in the regions reviewed. Specific results are contained in the report, a copy of which is attached as Annex B to this prospectus. 26 THE EXCHANGE OFFER PURPOSE AND EFFECT OF THE EXCHANGE OFFER We sold the Original Senior Notes on July 8, 2003 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 July 8, 2003, 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. 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- 27 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 Second Supplemental Indenture dated July 8, 2003 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 28 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 , 200 , 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 April 5, 2004, 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 4.875% 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, 2004. 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 29 (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 or transferred 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 or transferred to "institutional accredited investors" under Rule 501(a)(1), (2), (3) or (7) under the Securities Act were issued in certificated fully registered form 30 without coupons. Only registered holders of certificated Original Senior Notes may tender those Original Senior Notes in the Exchange Offer. 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 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 31 also reserve the right to waive any defects, irregularities or conditions of tender as to particular Original 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 32 executed Letter of Transmittal and Notice of Guaranteed Delivery, substantially in the form provided by us; and (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; 33 (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 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: Mr. Bernard Arsenec BY FACSIMILE: (212) 298-1915 FOR INFORMATION OR CONFIRMATION BY TELEPHONE: (212) 815-5098 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. 34 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 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 July 8, 2003, (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 deferred and amortized over the term of the Exchange Senior Notes. 35 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 and shall bear interest at a rate of 4.875% per annum from the date of original issuance. 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, 2015. 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. Interest shall be 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, 2004. 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. 36 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. 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) within 15 days after we are required to file the same with the SEC, copies of the annual reports and of the information, documents and other reports (or copies of such portions of any of the foregoing as the SEC may from time to time by rules and regulations prescribe) that we may be required to file with the SEC pursuant to Section 13 or Section 15(d) of the Exchange Act; or, if we are not required to file information, documents or reports pursuant to either of said Sections, then we shall file with the Trustee and the SEC, in accordance with rules and regulations prescribed from time to time by the SEC, such of the supplementary and periodic information, documents and reports which may be required pursuant to Section 13 of the Exchange Act, in respect of a security listed and registered on a national securities exchange as may be prescribed from time to time in such rules and regulations; (ii) at the time of the delivery of the report provided for in clause (i) above 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 (iii) 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 37 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 used by us or a Subsidiary to repay Indebtedness of our Company or such Subsidiary or (iii) are retained by us or a Subsidiary; provided, further, to the extent we engage in a sale-leaseback transaction with the Effingham County Industrial Development Authority (or other similar governmental entity) for ad valorem tax abatement opportunities relating to McIntosh 10 and 11, such transaction shall not be deemed to be an Asset Sale for purposes of this covenant. 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 38 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 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. 39 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, except as provided herein). "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, 2003, 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 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 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. 40 "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; (v) Stanton A; and (vi) McIntosh 10 and McIntosh 11. "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. "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). "Southern Subordinated Note" means that certain promissory note issued to Southern by us on June 20, 2003. As of September 30, 2003, approximately $0.5 million aggregate principal amount was outstanding under the Southern Subordinated Note, which amount varies from month to month and is being used to fund McIntosh 10 and McIntosh 11 until other financing is arranged. The Southern Subordinated Note bears 41 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, 2008. 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 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 or distribution of any kind 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 2008 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 equity. "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 42 (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. 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. 43 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 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. 44 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. 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 45 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 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 46 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. 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. 47 RATINGS Moody's Investors Service, Inc. and Standard and Poor's Ratings Services 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 and Standard & Poor's, a division of The McGraw-Hill Companies, Inc., 55 Water Street, 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 , , 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 holders 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 and the related financial statement schedule incorporated in this prospectus by reference from our Annual Report on Form 10-K for the year-ended December 31, 2002 have been audited by Deloitte & Touche LLP, independent auditors, as stated in their reports, which are incorporated herein by 48 reference, and have been so incorporated in reliance upon the reports of such firm given upon 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. 49 ANNEX A INDEPENDENT ENGINEER'S REPORT SOUTHERN POWER COMPANY GENERATING FACILITIES [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 Facility Sites............................................................................................A-6 The Dahlberg Facility Site.................................................................................A-6 The Franklin Facility Site.................................................................................A-6 The Harris Facility Site...................................................................................A-7 The McIntosh Facility Site.................................................................................A-7 The Stanton Facility Site..................................................................................A-7 The Wansley Facility Site..................................................................................A-8 Summary....................................................................................................A-9 Description of the Facilities.................................................................................A-9 Off-Site Requirements........................................................................................A-10 Fuel Supply...............................................................................................A-10 Water Supply and Treatment................................................................................A-11 Wastewater Disposal.......................................................................................A-13 Electrical Interconnection................................................................................A-13 Review of Technologies.......................................................................................A-14 GE 7FA CT.................................................................................................A-14 GE 7EA CT.................................................................................................A-18 Summary...................................................................................................A-18 Estimated Useful Life........................................................................................A-19 Performance Tests and Guarantees.............................................................................A-19 Operating Programs and Procedures............................................................................A-20 Operating History............................................................................................A-22 Capacity and Heat Rate.......................................................................................A-22 The Dahlberg Facility.....................................................................................A-22 The Franklin Facility.....................................................................................A-23 The Harris Facility.......................................................................................A-23 The McIntosh Facility.....................................................................................A-24 The Stanton Facility......................................................................................A-25 The Wansley Facility......................................................................................A-25 Summary...................................................................................................A-26 Availability.................................................................................................A-26 The Dahlberg Facility.....................................................................................A-26 The Franklin Facility.....................................................................................A-27 The Harris Facility.......................................................................................A-27 The McIntosh Facility.....................................................................................A-27 The Stanton Facility......................................................................................A-27 The Wansley Facility......................................................................................A-28 Summary...................................................................................................A-28 Construction Status..........................................................................................A-28
A-i ANNEX A INDEPENDENT ENGINEER'S REPORT SOUTHERN POWER GENERATING FACILITIES TABLE OF CONTENTS (CONTINUED)
PAGE ---- ENVIRONMENTAL ASSESSMENTS.......................................................................................A-29 Environmental Site Assessments...............................................................................A-29 The Dahlberg Facility.....................................................................................A-29 The Franklin Facility.....................................................................................A-29 The Harris Facility.......................................................................................A-29 The McIntosh Facility.....................................................................................A-30 The Stanton Facility......................................................................................A-30 The Wansley Facility......................................................................................A-31 Summary...................................................................................................A-32 Status of Permits and Approvals..............................................................................A-32 Regulatory Compliance........................................................................................A-34 PROJECTED OPERATING RESULTS.....................................................................................A-35 Annual Operating Revenues....................................................................................A-36 Revenue from PPAs.........................................................................................A-36 Other Revenues from Electricity Sales.....................................................................A-39 Annual Operating Expenses....................................................................................A-40 Fuel Costs................................................................................................A-40 Operating and Maintenance Costs...........................................................................A-40 Purchased Power...........................................................................................A-41 Emissions Allowances......................................................................................A-41 General and Administrative and Other Expenses.............................................................A-41 Annual Interest..............................................................................................A-41 Interest Coverage............................................................................................A-41 Sensitivity Analyses.........................................................................................A-42 Summary Comparison of Projected Operating Results............................................................A-42 PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS USED IN THE PROJECTION OF OPERATING RESULTS............................A-43 CONCLUSIONS.....................................................................................................A-45 EXHIBITS EXHIBIT A-1 Base Case Projected Operating Results.........................................................A-47 EXHIBIT A-2 Sensitivity A - Low Gas Market Price Scenario.................................................A-62 EXHIBIT A-3 Sensitivity B - High Gas Market Price Scenario................................................A-65 EXHIBIT A-4 Sensitivity C - Capacity Overbuild Market Price Scenario......................................A-68 EXHIBIT A-5 Sensitivity D - Reduced Output................................................................A-71 EXHIBIT A-6 Sensitivity E - Reduced Availability..........................................................A-74 EXHIBIT A-7 Sensitivity F - Increased Heat Rate...........................................................A-77 EXHIBIT A-8 Sensitivity G - Increased Operating Expenses..................................................A-80
Copyright (C) 2003 R. W. Beck, Inc. All Rights Reserved A-ii [LOGO] July 1, 2003 Southern Power Company 270 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 issued $575,000,000 of 6.25% Senior Notes, due July 15, 2012 in June 2002 (the "2002 Notes"). Southern Power intends on issuing $575,000,000 of 4.875% Senior Notes, due July 15, 2015 (the "Senior Notes"), as described more fully in Southern Power's offering memorandum related to the Senior Notes (the "Offering Memorandum"). Southern Power also has outstanding $100,000,000 of short-term notes related to one of the facilities under construction (the "Short-Term Notes"). Southern Power expects that it will issue additional debt in 2005 (together with the 2002 Notes, the Senior Notes and the Short-Term Notes, the "Debt"). The generating facilities reviewed, totaling 6,024 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 1,187 MW (net) Franklin (formerly known as Goat Rock) combined-cycle power plant in Lee County, Alabama consisting of two units ("Franklin 1" and "Franklin 2", and, collectively, the "Franklin Facility"); the 1,242 MW (net) Harris (formerly known as Autaugaville) combined-cycle power plant in Autauga County, Alabama consisting of two units ("Harris 1" and "Harris 2", and, collectively, the "Harris Facility"); the 1,240 MW (net) McIntosh combined-cycle power plant in Effingham, Georgia consisting of two units ("McIntosh 10" and "McIntosh 11", and, collectively, the "McIntosh 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, Franklin, 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. Franklin 1 entered into commercial operation on June 1, 2002 and Franklin 2 and the Harris Facility entered into commercial operation on June 1, 2003. The McIntosh Facility is under construction and is scheduled to enter into commercial operation in June 1, 2005. The Stanton Facility is under construction and is scheduled to enter into commercial operation on October 1, 2003. The Wansley Facility entered into commercial operation on June 1, 2002. A-1 FIGURE A-1 SOUTHERN POWER GENERATING FACILITIES SITE LOCATIONS [MAP] A-2 Southern Power was formed to own, develop, construct and acquire 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 sell power to these entities, as well as to others, under the various terms of individual power purchase agreements (collectively, the "PPAs"). Southern Power intends to continue to derive at least 80 percent of operating cash flow under long-term power purchase agreements. 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 ("NOX"), the CTs are equipped with dry low-NOX combustors. Construction of the Generating Facilities is being funded through a construction loan from a syndicate of commercial banks (the "Commercial Construction Revolver") and the issuance of short-term indebtedness, in addition to a subordinated loan and equity contribution from Southern Company. 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 PPA" and the "1999 LEM PPA" and, collectively, the "LEM PPAs"). The remainder of the output was previously being sold to Dynegy Power Marketing under a Purchased Power Agreement dated March 2, 2000; however, this power purchase agreement was terminated by Southern Power on May 21, 2003, as discussed in more detail in the Offering Memorandum. The output of the Franklin Facility will be sold to Georgia Power through May 31, 2010 for Franklin 1 and May 31, 2011 for Franklin 2 under the terms of a Power Purchase Agreement dated March 30, 2001 (the "Franklin PPA"). 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 PPA"). 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 PPA" and, together with the Harris 1 PPA, the "Harris PPAs"). The output of the McIntosh Facility will be sold to Georgia Power and Savannah Electric through May 31, 2020 under two Power Purchase Agreements dated June 3, 2002 (the "McIntosh PPAs"). The McIntosh PPAs are still subject to approval by the Federal Energy Regulatory Commission ("FERC"). 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 October 31, 2013, assuming an effective date of October 1, 2003, under the terms of three similar Power Purchase Agreements dated March 19, 2001 (the "Stanton PPAs"). 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 a Construction and Ownership Participation Agreement dated March 19, 2001 (the "Stanton Ownership Agreement"). A-3 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 PPAs"). Georgia Power operates and maintains the Dahlberg, Franklin, 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. Savannah Electric will operate and maintain the McIntosh Facility pursuant to the terms and conditions of an Operating Agreement with Southern Power effective January 1, 2003. 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, Alabama Power, and Savannah Electric provide similar services for their respective utility power 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 Franklin 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 UNIT CAPACITY DISPATCH FACILITY LOCATION FUEL TYPE TYPE (MW)(1) TYPE POWER PURCHASER - --------- ------------------ ---------------- ---- -------- ------------ ----------------- Dahlberg Athens, GA Oil/Natural Gas CT 810 Peaking LEM(2) Franklin 1 Lee County, AL Natural Gas CC 564 Intermediate Georgia Power Franklin 2 Lee County, AL Natural Gas CC 623 Intermediate Georgia Power Harris 1 Autauga County, AL Natural G CC 627 Intermediate Alabama Power Harris 2 Autauga County, AL Natural G CC 615 Intermediate Georgia Power McIntosh Effingham, GA Natural Gas CC 1,240 Intermediate Georgia Power/ Savannah Electric Stanton Orlando, FL Oil/ Natural Gas CC 411(4) Intermediate OUC/KUA/FMPA Wansley Heard County, GA Natural Gas CC 1,134 Intermediate Georgia Power/ Savannah Electric ----- Total 6,024 COMMERCIAL OPERATION TERM OF FACILITY DATE PPA - --------- ---------- ------- Dahlberg 5/00(3) 2004 Franklin 1 6/02 2010 Franklin 2 6/03 2011 Harris 1 6/03 2010 Harris 2 6/03 2019 McIntosh 6/05 2020 Stanton 10/03 2013 Wansley 6/02 2009 Total
- -------------------- (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) Under the LEM PPAs, the contract capacity of 578 MW can be met by any of the units. (3) Commercial operation of Dahlberg 9-10 occurred in 2001. (4) 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 plants 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 A-4 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. 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 Offering Memorandum, of which this Report is a part, for projections of the Generating Facilities' electricity sales, market electricity prices when the PPAs 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-NOX technology to control the formation of NOX. The Franklin Facility is a 1,187 MW (net) combined-cycle power plant consisting of two gas-fired electric generating plants. Franklin 1 is a 564 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. Franklin 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. Franklin 2 is a 623 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. Franklin 2 also includes duct firing and steam injection capabilities. The Harris Facility is a 1,242 MW (net) combined-cycle power plant consisting of two SCS Gen 3 gas-fired electric generating units, Harris 1 and 2, consisting of two GE 7FA CTs, two Deltak HRSGs, and an Alstom ST. Harris 1 is rated at 627 MW and Harris 2 is rated at 615 MW. The Harris Facility includes duct firing and steam injection capabilities. The McIntosh Facility is a 1,240 MW (net) combined-cycle power plant consisting of two SCS Gen 3 gas-fired electric generating units, McIntosh 10 and 11, each rated at 620 MW and consisting of two dual-fuel (natural gas and No. 2 fuel oil) GE 7FA CTs, two Deltak HRSGs, and an Alstom ST. The McIntosh 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 A-5 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. 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) Franklin 1 Gen 2 GE 7FA Vogt GE 564 6,711 Franklin 2 Gen 3 GE 7FA Deltak Alstom 623 6,728 Harris Gen 3 GE 7FA Deltak Alstom 1,242 6,730 McIntosh Gen 3 GE 7FA Deltak Alstom 1,240 6,827 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 an individual plant rather than separate units. THE FACILITY SITES THE DAHLBERG FACILITY 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 Facility Site"). Highway access to the Dahlberg Facility Site is convenient over national highways, state routes and city and county roads. THE FRANKLIN FACILITY SITE The Franklin 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 "Franklin Facility Site"). Highway access to the Franklin Facility Site is convenient over national highways, state routes and city and county roads. A-6 THE HARRIS FACILITY 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 Facility Site"). The Harris Facility Site is located in an unincorporated area of Autauga County, in central Alabama directly north of the Alabama River. Highway access to the Harris Facility Site is convenient over national highways, state routes and county roads. THE MCINTOSH FACILITY SITE The McIntosh Facility is to be constructed on property totaling approximately 58 acres in size located approximately 27 miles north of Savannah, Georgia, near Rincon, Georgia on Old Augusta Highway three miles south of Georgia Highway 275 (the "McIntosh Facility Site"). The McIntosh Facility Site is located in Effingham County, Georgia. The McIntosh Facility Site is located in an area zoned Industrial. Highway access to the McIntosh Facility is convenient over national highways, state routes and county roads. Heavy hauls to the McIntosh Facility will be made via a rail spur currently servicing the existing Savannah Electric facility located approximately one mile to the east of the McIntosh Facility. Southern Power also noted that the Savannah Electric facility also has capabilities to receive and offload equipment from an existing barge slip on the Savannah River. Southern Power noted that agreements are in place with Savannah Electric to utilize the rail spur and barge slip for receipt of the heavier equipment. Southern Geotech performed a subsurface investigation and prepared a report titled "Reports of Geotechnical Investigation, Proposed Plant McIntosh, Combined Cycle Units 10 & 11, Effingham County, Georgia" dated October 1, 2002 (the "McIntosh Geotechnical Report"). The McIntosh Geotechnical Report included summaries of the investigation; compilation of select laboratory results used for determination of engineering parameters, provided recommendations for foundations and foundation systems, and provided guidance on estimated settlement of foundations due to static and dynamic loading. Southern Geotech performed subsurface investigations in February 2002 and January 2003 and conducted a pile test program in August 2002. The soil boring investigations included dilatometer tests and test borings ranging in depth from approximately 51 feet to 92 feet below ground surface. Based on their geotechnical analysis, Southern Geotech recommended that pile foundations support the McIntosh Facility's more heavily loaded equipment, including the STs, CTs, ST support steel, pipe racks, and HRSGs. Southern Geotech further indicated that shallow foundations might be considered for the storage tanks, cooling towers, transformers, electrical buildings, the warehouse and administration building, and other miscellaneous foundations. The McIntosh Geotechnical Report does not include criteria for site development, compaction, or surface water control nor did it provide information relating to corrosion potential and resistivity of the soils. However, Southern Power indicated that the specifications prepared for construction include the necessary considerations for adequate site development. At the time of our site visit, we noted that surface water control measures were installed and finished subgrade had been achieved. The McIntosh Geotechnical Report provides settlement estimates for the equipment to be installed on shallow and deep foundations and a summary of pile testing conducted at the McIntosh Facility Site in August 2002. Southern Power noted that the settlement estimations reported in the McIntosh Geotechnical Report were deemed acceptable. We note that the settlement estimations presented in the McIntosh Geotechnical Report appear to be within the range we would expect for the given structures. The McIntosh Geotechnical Report did not make foundation recommendations for the structures located within the switchyard. THE STANTON FACILITY 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 Facility A-7 Site"). The Stanton Facility 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 Facility 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 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 FACILITY SITE The Wansley Facility was constructed on land totaling approximately 25 acres, located in Heard County, Georgia near Carrolton, Georgia and approximately 30 miles southwest of Atlanta (the "Wansley Facility Site"). The Wansley Facility Site is located in an incorporated area of Heard County, in western Georgia directly north of the Chattahoochee River. Highway access to the Wansley Facility Site is convenient over national highways, state routes, and county roads. A-8 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 Franklin, Harris, McIntosh, 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-NOX combustors to control the formation of NOX 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, and the McIntosh Facility, which can burn liquefied natural gas ("LNG") and 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, with the exception of the McIntosh Facility where the reference condition is 51 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. NOX 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 50 percent to 100 percent of base load by the use of dry low-NOX combustors without power augmentation. With power augmentation, NOX emissions are guaranteed by GE to 12 ppmvd at base load. Carbon monoxide ("CO") emissions are guaranteed by GE to 9 ppmvd between base load and 50 percent of base load without power augmentation for the Harris, McIntosh, and Stanton Facilities when firing natural gas and, in the case of the McIntosh Facility, LNG. With power augmentation, CO emissions are guaranteed by GE to 15 ppmvd for the Franklin, Harris, McIntosh, 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 Franklin 2, Harris, McIntosh, 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 Franklin 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-NOX 2.6 ("DLN-2.6") combustors for control of NOX emissions. Dry low-NOX 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-NOX combustor has a shorter, lower residence time flame. Both lower temperature and shorter time contribute to NOX emissions equal to or lower than that achieved by conventional steam and water injection. A-9 Each HRSG is to be equipped with selective catalytic reduction ("SCR") to further reduce the NOX 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 NOX-I ("DLN-I") combustors for dry control of NOX emissions when burning natural gas and incorporate water injection for control of NOX 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 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. NOX emissions are guaranteed to 9 ppmvd (at 95(degree)F, 14.32 psia, and 45 percent relative humidity) by the use of dry low-NOX combustors while burning natural gas. NOX 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 NOX emissions while burning natural gas. Traditional control for CTs was comprised of water injection into the combustors to cool the flame and inhibit NOX formation, whereas dry low-NOX 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-NOX combustor has a shorter, lower residence time flame. Both lower temperature and shorter time contribute to NOX emissions equal to or lower than that achieved by conventional steam and water injection. Control of NOX 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 Franklin Facility is delivered to the Franklin Facility Site through a 20-inch pipeline lateral extending from the SNG main line located approximately 5.5 miles south of the Franklin Facility Site. A-10 Southern Power owns and operates the meter station which is located adjacent to the pipeline tap location. SCS purchases natural gas from Gulf Coast for delivery to the Franklin Facility. The natural gas pipeline to the Harris Facility Site is 24 inches in diameter and approximately 12 miles in length. The pipeline was constructed by Southern and runs parallel to the existing 500 kV power transmission line. The pipeline ties into an existing pipeline owned and operated by Southern Natural Gas ("SNG"), a wholly-owned subsidiary of El Paso Corporation. SNG is not affiliated with Southern. SCS purchases natural gas from Gulf Coast Natural Gas for delivery by SNG to the plant. A metering station adjacent to the pipeline tap location and a gas conditioning station has been constructed on site. The natural gas pipeline to the McIntosh Facility is to be 16 inches in diameter and approximately 600 feet in length. The pipeline will tie into an existing 16-inch pipeline that provides gas to the existing peaking units located adjacent to the McIntosh Facility Site. The existing 16-inch pipeline is a 5.2-mile lateral pipeline that is connected to a 24-inch pipeline owned and operated by SNG. Savannah Electric will purchase natural gas from El Paso Merchant Energy, L.P. for delivery by SNG to the plant. All the gas delivered to the McIntosh 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. The natural gas pipeline to the Stanton Facility is 16 inches in diameter and approximately 5.2 miles in length. The pipeline ties 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 is 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 and Transco will retain ownership and operation responsibilities for the newly installed system in accordance with the Interconnect, Reimbursement and Operating Agreement. SCS purchases 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 McIntosh and Stanton Facilities. 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 Franklin Facility is for the cooling water system and steam cycle makeup. 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 A-11 water system has the greatest water need of all the systems. Raw water is taken from the Chattahoochee River via an existing unused penstock located within the Goat Rock Dam located approximately one mile east of the plant. Wastewater is discharged in the tailrace of the same dam. Demineralized water for the Franklin Facility is provided by Water & Power Technologies. The raw water needs of the Franklin Facility are supplied through the existing Goat Rock Dam. 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 McIntosh Facility will be supplied with raw water from the existing Savannah Electric facility which is located approximately one mile northeast from the McIntosh Facility. The raw water supply for McIntosh Facility will be the Savannah River near the City of Savannah. Potable water is to be supplied via an on-site well. Southern Power indicated that raw water is to be delivered to the McIntosh Facility via a 30-inch supply line and will be stored in an on-site storage tank. This water will subsequently be used for fire protection, cooling water, and treated for process water. Although Southern Power represents that Savannah Electric is to provide raw water to the McIntosh Facility, we are not aware of any contractual requirement to do so. However, Southern Power reported that the draft Memorandum of Operator Interface Procedures dated January 1, 2003, is to be amended to obligate Savannah Electric to provide specific water and wastewater services for the McIntosh Facility. 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 Facility 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. The water supply for the Wansley Facility is obtained from the Plant Wansley reservoir located northeast of the Wansley Facility 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 A-12 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 Franklin Facility 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 Franklin 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. Process wastewater from the McIntosh Facility is to be returned to the existing Savannah Electric facility for discharge to the Savannah River through the outfall structure at the existing Savannah Electric facility. 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 Facility 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 Franklin Facility is interconnected through the Goat Rock 230 kV Switchyard, which consists of a single bus, single breaker arrangement with three transformer positions each for Franklin 1 and 2, and one transmission line position. The Goat Rock 230 kV Switchyard is 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 Franklin Facility 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 routed from the plant switchyards to new Alabama Power 230 kV and 500 kV switchyards. The 230 kV switchyard at the McIntosh Facility consists of two 230 kV collector buses connected to the West McIntosh substation, located approximately 1,000 feet from the Facility Site. The West McIntosh 230 kV A-13 Substation is connected to the West McIntosh 500 kV Substation, configured as four-breaker ring bus, via two 500/230 kV autotransformers. The West McIntosh 230 kV Substation is also connected to the McIntosh 230 kV Substation via two transmission lines. The West McIntosh 500 kV Substation has two transmission exits, one to Vogtle and the other to Thalmann. 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 Facility 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 Facility Site. An interconnection study for the McIntosh Facility was conducted to analyze the load flow, stability, and short-circuit analysis of the transmission system. As a result of the study, some system upgrades are required. The necessary improvements are to be provided by Georgia Power and the associated cost is to be reimbursed by Southern Power. Southern Power has also entered into a 40-year interconnection agreements with Georgia Power for each of the two McIntosh Facility power blocks. Based on the information outlined in the interconnection study and execution of the interconnection agreements, the McIntosh Facility should be able to interconnect to the transmission system and deliver a net electrical output of 1,240 MW at the interconnection point. 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 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 Franklin, Harris, McIntosh, 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 A-14 Frame 7E/EA, which has over 600 units installed and has accrued over 15 million operating hours. While the Frame 7F/FA is considered mature technology with over 416 units installed, 4.1 million fired hours, and over 106,000 fired starts fleet-wide, of the 324 7241FA units currently in operation as of February 2003, the fleet leader has only accumulated approximately 22,300 fired hours and 650 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 issues 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 ("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 Franklin, Harris, McIntosh, 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 1 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 February 2003. TABLE 3 FRAME 7 F/FA OPERATIONAL CHARACTERISTICS
7191F 7221FA 7231FA 7241FA ------- ------- ------- ------- ISO Output(MW) 150 159 167.8 171.7 ISO Heat Rate(HHV)(Btu/kWh) 10,950 10,535 10,400 10,380 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) 58,000+ 75,000+ 34,000+ 22,300+ Fleet Leader Commercial Operation Date 1991 1993 1997 1999
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(degree)F to 2,420(degree)F; (2) increase in compressor airflow and pressure A-15 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 Franklin, Harris, , McIntosh, 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 many commercial facilities. Though the 7241FA fleet leader has operated in excess of 22,300 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 Franklin, Harris, McIntosh, 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-NOX 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 NOX guarantee of 9 ppmvd 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 February 2003, GE reports over 480 units operating with its dry low-NOX technology with over 5.2 million fired hours, of which 1,200,000 hours were on Frame 7F machines. DLN-2.6 in all its applications has accumulated in excess of 1,600,000 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 22,300 fired hours as of February 2003. 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 NOX 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. STEAM INJECTION FOR POWER AUGMENTATION In addition to hardware changes that have resulted in the 7241FA CT, equipped with the DLN-2.6 combustion system, the GE 7FA Facilities will utilize steam injection for power augmentation, which has not accrued extensive usage by GE as an enhancement to the Frame 7F/FA based plants' net facility output. Currently GE reports to have several 7241FA units, equipped with the DLN-2.6 combustion system, operating with steam injection for power augmentation, as well as several other Frame 7FA units (i.e., 7221FA and 7231FAs) operating with steam injection for power augmentation, equipped with either DLN-2.0 or DLN-2.6 combustion systems (the latter of which GE reports is very similar to the DLN-2.6 utilized in the 7241FA). GE has indicated that it currently does not monitor detailed operating history such as fired hours and steam injection rates on units that utilize steam injection for power augmentation. A-16 GE offers a NOX guarantee of 12 ppm for the 7241FA, equipped with the DLN-2.6 combustion system, where firing natural gas fuel during periods when steam injection for power augmentation is utilized, rather than the 9 ppm guarantee previously discussed. In addition, GE has issued a technical paper (which is referenced in GE's Long Term Parts and Services Agreement for which the Generating Facilities which incorporate the GE 7FA will participate) that states an impact factor of 1.5 on actual maintenance operating hours at a maximum allowable steam injection rate of 5 percent of CT inlet airflow in the 7241FA. However, the elevated impact factor is only applicable to a "wet control" operating mode, which is the mode of power augmentation when the firing temperature is held constant and not depressed. The other mode of operation is referred to as the "dry control" mode where the firing temperature is reduced and the maintenance impact factor is not affected. Southern Power reports that the 7FA CTs utilized by the Generating Facilities operate or will operate in a "dry control" mode. OPERATIONAL ISSUES In the last three years, GE Frame 7F/FA machines have experienced certain operational issues or GE is in the process of correcting prior issues, in its compressor and turbine sections for that frame. Some of these issues 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 issues from reoccurring on the 7241FAs utilized by the Franklin, Harris, McIntosh, Stanton, and Wansley Facilities. A brief description of the issues 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 failure was cracking due to 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 that 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 ambient 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. Southern Power has reported that the CTs at the Franklin, Harris, McIntosh, Stanton, and Wansley Facilities currently incorporate the software changes necessary to bring the inlet bleed heat on at higher ambient temperatures, and it plans on incorporating the hardware change described above (the GE reported permanent remedy to this issue) at the first hot gas path inspection for each unit. In 2002 and 2003, GE submitted several Technical Information Letters ("TILs") that discuss the susceptibility of the 7241FA's compressor section to erosion, damage, and potentially part failure when exposed to liquid water during operation. The CTs affected by these TILs are those that utilize online water washing (to reduce the effects of compressor fouling), inlet evaporative coolers, and/or inlet fogging. The Franklin, Harris, McIntosh, Stanton, and Wansley Facilities each utilize inlet evaporative cooling and intend to utilize online water washing, as required, to maintain higher levels of thermodynamic performance during commercial operation. GE has recommended the following in its TILs, as applicable to the Franklin, Harris, McIntosh, Stanton, and Wansley Facilities: (i) increased inspection requirements and intervals for the inlet evaporative cooling system; (ii) potentially ceasing the use of evaporative cooling until modifications can be made to any affected row 0 compressor blading; and (iii) increased inspection intervals for the first few compressor blade stages and potentially more frequent compressor maintenance than originally anticipated by GE for those parts. GE reported that if the evaporative coolers for its 7241FA units are commissioned and maintained according to its recommendations, such that no water carryover into the compressor section is allowed that blade A-17 erosion should not be a concern for this reason. GE further reported that after a given unit operates for approximately 300 to 400 hours with the evaporative coolers in use that it will recommend taking a mold of the row 0 compressor blades to assess any erosion at that time and provided that GE finds little or no erosion, it will permit unrestricted evaporative cooler operation going forward. As related online water washing, GE has recommended certain modifications to its online water washing system that it reports to have verified reduced erosion to the row 0 compressor blades and has additionally increased the effectiveness of the online water washing process. GE is still recommending that molds be taken of the row 0 compressor blades after 100 hours of cumulative online water washing to assess erosion of such blades (if any) until such time as it can complete its ongoing water washing verification program and permit longer inspection intervals. Southern Power reports that it is aware of GE's recommendations for both its evaporative coolers and online water washing and is working to maintain its evaporative coolers so that water carryover is not a concern and is making all required modifications and inspections of the water washing system and the row 0 compressor blades. Turbine Section. The shroud tips of the row 2 turbine blades are reported by GE to be susceptible to creep deformation that results in a slow and progressive distortion of the blade shroud under operating loads and temperatures. GE reports that it has issued instructions to users to grind material off a tip seal or cutter tooth on the shroud and that if this action is performed in the first 4,000 hours of operation that the blades should be able to make the published life expectancy. The GE advisory further recommends a borescope inspection be performed every 8,000 hours to inspect for creep deformation of the row 2 turbine blades. GE reports that it has created an alternate design of the row 2 turbine blade which reduces the mass of the shroud, moves the tip seal to the center of the shroud, and improves the shroud cooling to improve its creep life. Southern Power reports that it will make the required modifications to the row 2 blades and that the improved blades will be incorporated into the units as part of the normal parts replacement intervals. GE 7EA CT The Dahlberg Facility utilizes a GE 7EA CT set equipped with dry low-NOX 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 600 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-NOX combustion technology. GE has reported that its GE 7EA dry low-NOX combustion system has consistently achieved 9 ppmvd NOX control while operating on natural gas at the nominal GE 7EA firing temperature of 2,035(Degree)F. SUMMARY Based on our review, we are of the opinion that, based on GE's previously demonstrated capability to address 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 PPAs and the currently applicable environmental permit requirements. Furthermore, all off-site requirements of the A-18 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 All of the Generating Facilities except the Dahlberg Facility 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 Franklin, Harris, McIntosh, Stanton, and the Wansley Facilities. A description of the performance tests and Southern completion guarantees for these units are presented below. Table 4 indicates the performance guarantees provided by Southern for Franklin 2 and the Harris, McIntosh, and Stanton Facilities, as set forth in Credit Agreement for the Commercial Construction Revolver dated April 17, 2003 (the "Construction Revolver Credit Agreement"). Franklin 2 and the Harris Facility declared commercial operation under their respective PPAs on June 1, 2003. Southern Power reports that the Franklin 2 and Harris Facilities have completed their initial net plant output tests under the Franklin and Harris PPAs. TABLE 4 SOUTHERN PERFORMANCE GUARANTEES
OUTPUT HEAT RATE (MW)(1) (BTU/KWH)(2) ------ ----------- Franklin 2(3) 615 6,728 Harris 1(3) 618 6,730 Harris 2(3) 618 6,730 McIntosh 620 6,827 Stanton 633(4) 6,756
-------------------- (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. (4) Represents full output of the Stanton Facility. Southern Power owns 65 percent of the Stanton Facility. A-19 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 under the PPAs 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 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 PPAs for the Franklin, Harris, and McIntosh 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 PPAs 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 PROGRAMS AND PROCEDURES SCS, on behalf of Southern Power, manages and provides operations and maintenance services for the Generating Facilities. Georgia Power provides operations and maintenance support staff to SCS for the Franklin, Dahlberg, and Wansley Facilities pursuant to the terms and conditions of an Operating Agreement with Southern Power, dated December 18, 2002. Savannah Electric is to provide operations and maintenance support staff to SCS for the McIntosh Facility pursuant to the terms and conditions of an Operating Agreement with Southern Power, which is to be effective January 1, 2003. Alabama Power provides operations and maintenance support staff to SCS for the Harris Facility pursuant to the terms and conditions of an Operating Agreement with Southern Power, dated A-20 June 30, 2001. Georgia Power, Alabama Power, and Savannah Electric provide similar services for their respective utility power generation facilities. SCS is to provide operation and maintenance services for the Stanton Facility on behalf of Southern Company Florida pursuant to the terms and conditions of an Operating Agreement with the Stanton Participants. Southern Company Florida acts as the OUC's, KUA's, and FMPA's agent for the operation and maintenance of the Stanton Facility during the term of the Stanton PPAs. Southern Power has entered into LTSAs with GE for the maintenance and overhaul of the CTs and STs furnished by GE. The LTSA for the Stanton Facility has been assigned to Southern Company Florida, a direct wholly-owned subsidiary of Southern Power. We have reviewed the general application of the various operations and maintenance ("O&M") programs and procedures within the Generating Facilities, including: preventive, corrective and predictive maintenance plans; operating procedures; and maintenance procedures. We did not review all aspects of these plans and procedures, but verified that all of the usual and necessary plans, procedures and documentation normally required to operate a facility of this type were in place. Following is a brief description of the key programs and procedures in place at the Generating Facilities. SCS utilizes computerized maintenance management systems at the Generating Facilities. In addition to the computerized maintenance management systems, major outages are scheduled by SCS in coordination with Southern Power generating resource requirements. The predictive maintenance program includes the capability for SCS with the support of Georgia Power and Alabama Power personnel and local contractors to perform common predictive maintenance functions such as vibration analysis and trending, infrared thermography to sense hot spots in electrical and other equipment, and lube oil sample analysis. The Generating Facilities are also using SCS's centralized maintenance program in which key pieces of equipment will be analyzed and specific maintenance plans developed for the most efficient maintenance of the equipment. SCS maintains an appropriate collection of operating, maintenance and administrative procedures which have been developed in coordination with Southern Power. These procedures include normal operating and maintenance procedures, as well as emergency response procedures for operating events or the exceedance of environmental limits. SCS is in the process of implementing reliability and performance monitoring programs at the Generating Facilities. Principle among these programs are a reliability improvement program to determine the root cause of equipment failures, a boiler tube failure reduction program, a boiler waterwall tubing survey and inspection program, a high energy piping inspection program, and a pulverizer maintenance and performance program. The plant staffing is projected to consist of approximately 9, 24, 28, 30, 23, and 28 on-site personnel at the Dahlberg, Franklin, Harris, McIntosh, Stanton, and Wansley Facilities, respectively. Staffing at the Franklin and Stanton Facilities are shared with adjacent generating units. SCS has utilized a multi-skilled craft concept for most operating and maintenance positions. With this concept, each plant technician has both a primary skill and a secondary skill, with levels of proficiency within each skill. Maintenance disciplines are divided between mechanical and electrical/instruments/controls. Major maintenance for the CTs and STs are scheduled on the basis of factored hours with the exception of the Dahlberg Facility, which is scheduled based on factored starts as recommended by the manufacturer. Major maintenance scheduled on a factored hours basis is performed at approximately a 48,000- to 50,000-hour interval. Overhaul durations are typically 2 to 4 weeks, depending upon the scope of work to be performed. In years when there is no major maintenance scheduled for a unit, a one- to two-week "mini-outage" is performed on the CTs, STs, generators, HRSGs and auxiliaries. A-21 Based on our review, we are of the opinion that, through the experience of Southern Power, Alabama Power, Georgia Power, Savannah Electric or other Southern Company subsidiaries, SCS has demonstrated the capability to operate the Generating Facilities. The operating programs and procedures which are proposed or currently in place for the Generating Facilities are consistent with generally accepted practices in the industry, and SCS has incorporated organizational structures that are comparable to other facilities using similar technologies for a similar service. OPERATING HISTORY Dahlberg 1-8 have been in operation since May 2000 and Dahlberg 9-10 have been in operation since May 2001. Franklin 1 and the Wansley Facility declared commercial operation under their respective PPAs on June 1, 2002. A summary of certain operating data for the 12 months ending May 31, 2003 for these facilities is presented in Table 5. Franklin 2 and the Harris Facility declared commercial operation under their respective PPAs on June 1, 2003. As such, no operating results are available for these facilities. TABLE 5 OPERATING HISTORY(1)
NET NET ACTUAL STARTS EAF GENERATION HEAT RATE CAPACITY /ATTEMPTED UNIT (%) (MWH) (BTU/KWH)(2) FACTOR(%)(3) STARTS ---- ------ ---------- ------------ ------------ ------------- Dahlberg 1 99.24 25,247 11,829 3.57 59/59 Dahlberg 2 100.00 21,846 11,829 3.09 54/54 Dahlberg 3 97.74 33,060 11,829 4.67 68/68 Dahlberg 4 100.00 22,938 11,829 3.24 50/50 Dahlberg 5 98.67 29,839 11,829 4.22 66/66 Dahlberg 6 95.53 21,907 11,829 3.10 48/48 Dahlberg 7 99.09 25,100 11,829 3.55 54/54 Dahlberg 8 99.16 19,866 11,829 2.81 41/41 Dahlberg 9 96.46 27,456 11,829 3.88 57/57 Dahlberg 10 99.20 29,228 11,829 4.13 64/64 Franklin 1 81.37 1,399,133 7,348 30.08 17/17 Wansley 6 95.61 1,643,644 7,192 34.72 19/19 Wansley 7 95.36 1,652,011 7,192 34.80 25/25
- -------------------- (1) From June 1, 2002 through May 31, 2003. (2) On a Higher Heating Value ("HHV") basis. Fuel consumption recorded on a total project basis. (3) Based on a peak output rating of 81 MW per unit. CAPACITY AND HEAT RATE Each of the respective PPAs 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 PPAs 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 PPAs, 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 A-22 firing natural gas during the winter months. These output and heat rate values are subject to degradation as set forth in the LEM PPAs. Based on information provided by Southern Power, we have estimated the long-term annual average capacity to be 399 MW for Dahlberg 1-5, 159 MW for Dahlberg 6-8, and 239 MW for Dahlberg 9-10. This estimate includes a levelized allowance for long-term degradation. Under the terms of the LEM PPAs, fuel is purchased by Southern power and reimbursed by LEM according to the summer and winter heat rate curves in the LEM PPAs. Heat rate degradation is provided for in the LEM PPAs. 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 have assumed that the heat rate of the Dahlberg Facility will be in accordance with the heat rate curves in the LEM PPAs and no heat rate penalties will be incurred or bonuses achieved. THE FRANKLIN FACILITY The monthly capacity payments under the Franklin PPA 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 was determined by test upon commercial operation as the amount of capacity Franklin 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. As a result of the Demonstrated Capability tests performed pursuant to the Franklin PPA, the Designated Capacity has been set at 564 MW for Franklin 1 and 623 MW for Franklin 2. In the event that the Franklin 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 Franklin 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 542 MW for Franklin 1 and 598 MW for Franklin 2. This estimate includes a levelized allowance for long-term degradation. Under the terms of the Franklin PPA, fuel is purchased by Georgia Power. Southern Power guarantees summer and winter heat rate curves in the Franklin PPA 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 Franklin PPA. As a result of the performance tests performed pursuant to the Franklin PPA, Franklin 1 demonstrated a net plant heat rate, corrected to Rated Conditions, of 6,780 Btu/kWh. 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 6,949 Btu/kWh for Franklin 1 and 6,879 Btu/kWh for Franklin 2. For the purposes of the Projected Operating Results, we have assumed that the heat rate of the Franklin Facility will be in accordance with the heat rate curves in the Franklin PPA and no heat rate penalties will be incurred or bonuses achieved. THE HARRIS FACILITY The monthly capacity payments under the Harris PPAs 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 A-23 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. As a result of the Demonstrated Capability tests performed pursuant to the Harris PPAs, the Designated Capability has been set at 627 MW for Harris 1 and 615 MW for Harris 2. 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 602 MW for Harris 1 and 590 MW for Harris 2. This estimate includes a levelized allowance for long-term degradation. Under the terms of the Harris PPAs, fuel is purchased by Alabama Power and Georgia Power. Southern Power guarantees summer and winter heat rate curves in the Harris PPAs 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 PPAs. 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 6,883 Btu/kWh for Harris 1 and 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 PPAs and no heat rate penalties will be incurred or bonuses achieved. THE MCINTOSH FACILITY The monthly capacity payments under the McIntosh PPAs are based on the "Designated Capacity" for that annual period. The Designated Capacity is adjusted by a monthly capacity payment factor of 0.175 for the months of June through September, 0.05 for the months of January and February, and 0.033 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 McIntosh 10 and 11 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 McIntosh 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 McIntosh 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 McIntosh 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 McIntosh 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 A-24 day-to-day basis. Based on information provided by Southern Power, we have estimated the long-term Demonstrated Capability to be 595 MW for McIntosh 10 and 595 MW for McIntosh 11. This estimate includes a levelized allowance for long-term degradation. Under the terms of the McIntosh PPAs, Georgia Power and Savannah Electric are responsible for reimbursing Southern Power for the cost of fuel consumed by the McIntosh Facility at the guaranteed summer and winter heat rate curves in the McIntosh PPAs. 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 McIntosh PPAs. 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 6,894 Btu/kWh for McIntosh 10 and McIntosh 11. For the purposes of the Projected Operating Results, we have assumed that the heat rate of the McIntosh Facility will be in accordance with the heat rate curves in the McIntosh PPAs and no heat rate penalties will be incurred or bonuses achieved. THE STANTON FACILITY Under the terms of the Stanton PPAs, 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 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 PPAs, 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 PPAs. 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 6,915 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 PPAs and no heat rate penalties will be incurred or bonuses achieved. THE WANSLEY FACILITY The monthly capacity and fixed O&M payments under the Wansley PPAs 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 A-25 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 1,089 MW for the Wansley Facility. This estimate includes a levelized allowance for long-term degradation. Under the terms of the Wansley PPAs, 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 PPAs. 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 PPAs 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 6,890 Btu/kWh for Wansley 6 and 6,923 Btu/kWh for Wansley 7. For the purposes of the Projected 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 PPAs 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 Senior 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 PPAs 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 PPAs, 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 A-26 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 PPAs. In the event that the Dahlberg Facility is unable to meet the requirements of the LEM PPAs, Southern Power must provide the requested energy from other resources. THE FRANKLIN FACILITY Under the terms of the Franklin PPA, 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 Franklin 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. THE HARRIS FACILITY Under the terms of the Harris PPAs, 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 PPA and the "Seasonal Availability Factor" in the Harris 2 PPA, 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 MCINTOSH FACILITY Under the terms of the McIntosh PPAs, 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 96.0 percent. The capacity payments can increase by 1.5 to 4.0 percent of the annual capacity payments for a contract availability ranging from 96.0 to 99.0 percent. Southern Power can meet this contract availability through energy from alternate resources. THE STANTON FACILITY Under the terms of the Stanton PPAs, 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 A-27 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 PPAs, 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 PPAs 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 Senior 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 PPAs. CONSTRUCTION STATUS We were provided summary schedules comprised of engineering, procurement, construction, and turnover activities to support the assumed commercial operations dates of the McIntosh and Stanton Facilities. 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 the Stanton Facility is currently scheduled for October 1, 2003. According to SCS, overall construction was approximately 98 percent complete as of June 1, 2003, and start-up and testing are underway. First fire of the both CTs and steam piping blows have been completed. The total construction cost is estimated by Southern Power to be $262 million, of which Southern Power's share is 65 percent. Commercial operation of the McIntosh Facility is currently scheduled for June 1, 2005. Construction began October 1, 2002, this included site work, grading, and the installation of a barge ramp and access road. Piling for both units is scheduled to be accomplished between April and August 2003. Major foundation construction for the units is scheduled to begin in July 2003 and complete in early March 2004. Erection of the HRSGs is scheduled to begin in October 2004 and approximately ten months has been estimated for the installation of each HRSG. Installation of the CTGs is scheduled to begin in November 2003 and completion is scheduled for September 2003. The McIntosh 10 STG installation is scheduled to begin in December 2003 and complete December 23, 2004. The McIntosh 11 STG installation is scheduled to begin March 2, 2004 and complete January 18, 2005. The GSU transformers are to be delivered to the site on February 25, 2004. The station service energization is scheduled for May 3, 2004. Steam blows for McIntosh 10 and 11 are scheduled for November and December 2004, respectively. Gas performance testing for McIntosh 10 is scheduled to begin January 12, 2003 and McIntosh 11 gas performance testing is scheduled to begin February 11, 2005. Commercial operation is scheduled for McIntosh 10 and 11 on May 1, 2005 and June 1, 2005, respectively. The total construction cost is estimated by Southern Power to be approximately $591 million. A-28 ENVIRONMENTAL ASSESSMENTS ENVIRONMENTAL SITE ASSESSMENTS THE DAHLBERG FACILITY We have reviewed the "Environmental Property Assessment" regarding the Dahlberg Facility 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. 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. 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 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 FRANKLIN FACILITY We have reviewed the "Environmental Property Assessment" regarding the Franklin Facility 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 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. 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 Facility 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 A-29 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. Neither Alabama Power's nor TTL's assessments identified any potential impacts to the Harris Facility 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 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 MCINTOSH FACILITY We have prepared the "Phase I Environmental Site Assessment, Property for the Proposed Plant McIntosh Combined Cycle Units 10 and 11", dated June 9, 2003, regarding the approximately 58-acre McIntosh Facility Site. Previous land use of the subject property has included growing timber and agriculture, and the property previously contained isolated residential structures. No previous spills or other environmental concerns have been reported at the subject property. At the time of our April 29, 2003 site visit, the property had been cleared of all trees and vegetation in preparation for construction of the McIntosh Facility. We observed no evidence of spills, soil staining, tanks, solid waste disposal, hazardous waste, or storage of chemicals or hazardous materials during our site visit. Our interviews with personnel familiar to the property, review of materials regarding the history of the property, and review of state and Federal environmental databases did not reveal any recognized environmental conditions or other environmental concerns regarding the subject property. 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 A-30 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. 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. If groundwater remediation is ever required at the Stanton Facility 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 Facility 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 Facility Site. URS did not identify the existing coal-fired Plant Wansley or any other adjacent areas as having any potential to impact the Wansley Facility 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. A-31 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 In February 2003, Southern Power stated that there have been no reportable spills or site contamination issues of concern at the Dahlberg, Franklin, Harris, Stanton and Wansley Facility Sites since issuance of the 2001 environmental site assessments. Based on our Phase I environmental site assessment for the McIntosh Facility, we did not identify any environmental concerns related to site contamination issues. Because no updated ESAs of previous or recent environmental investigations regarding the potential for site contamination issues at the sites of the other Generating Facilities have been provided for our review, we can offer no opinion with respect to potential site contamination issues at the sites of the Dahlberg, Franklin, Harris, Stanton, and Wansley Facilities, if any, or the potential for future remediation. STATUS OF PERMITS AND APPROVALS The Generating Facilities must be operated in accordance with applicable environmental laws, regulations, policies, codes and standards. Table 6 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. We note that the modification of the NPDES Permit and the Surface Water Withdrawal Permit of the adjacent steam plant to accommodate the McIntosh Facility have not yet been issued and are under review by the Georgia Environmental Protection Division. As such, we have not reviewed the conditions to be set forth in the permits. TABLE 6 STATUS OF KEY PERMITS AND APPROVALS REQUIRED FOR OPERATION
================================================================================================================================== DAHLBERG FRANKLIN HARRIS MCINTOSH STANTON WANSLEY PERMIT/APPROVAL FACILITY FACILITY FACILITY FACILITY FACILITY FACILITY ================================================================================================================================== Air Construction Issued 8/9/99 Issued 4/10/00 Issued 1/8/01 Covered under Issued 9/21/01 Issued 7/28/00 Permits by Georgia by Alabama by ADEM; Prevention of by FDEP. by GEPD; Environmental Department of reissued with Significant finalized Protection Environmental "Harris" name Deterioration 11/6/00. Division Management 7/26/02. Permit/Title V ("GEPD"). ("ADEM"), Part 70 revised 4/6/01. Operating Permit for existing plant issued 4/17/03. - ---------------------------------------------------------------------------------------------------------------------------------- Title IV Acid Rain Issued 8/31/99 Issued 5/7/01 Application Covered under Application Issued 7/28/00 Permits by GEPD. by ADEM. submitted Prevention of deemed by GEPD; 12/14/00 to Significant complete finalized ADEM. Deterioration 4/24/02. 11/6/00. Application Permit /Title re-submitted V Part 70 with "Harris" Operating name 7/19/02; Permit for permit pending existing plant issued 4/17/03. - ----------------------------------------------------------------------------------------------------------------------------------
A-32 TABLE 6 STATUS OF KEY PERMITS AND APPROVALS REQUIRED FOR OPERATION
================================================================================================================================== DAHLBERG FRANKLIN HARRIS MCINTOSH STANTON WANSLEY PERMIT/APPROVAL FACILITY FACILITY FACILITY FACILITY FACILITY FACILITY - ---------------------------------------------------------------------------------------------------------------------------------- Title V Operating Application Application Application Covered under Application Issued 7/28/00 Permits submitted submitted ADEM to be Prevention of must be by GEPD; 3/5/01 to 11/20/02. submitted to Significant submitted finalized GEPD; permit ADEM within Deterioration within 12 11/6/00; pending. 12 months of Permit /Title months of the amended 2/4/02 the start of V Part 70 start of and 6/25/02. operations. Operating operation; Permit for application to existing be submitted plant issued after third 4/17/03. quarter 2003. - ---------------------------------------------------------------------------------------------------------------------------------- National Pollutant N/A Final NPDES Issued Application Not required. Issued 7/31/00 Discharge Permit issued 12/20/01; submitted by GEPD. Elimination System 12/27/00 by effective 5/31/02; ("NPDES") Permits ADEM. 1/1/02. permit for Wastewater issuance Discharges expected 7/03. - ---------------------------------------------------------------------------------------------------------------------------------- Notice of Submitted Issued Issued Notice of Submitted to Submitted Intent/General 8/11/00 to 12/17/99 by 12/1/00 by Intent filed FDEP 6/2/02. 8/10/00 to Permits-Construction GEPD (only ADEM. ADEM. 9/30/02. GEPD. Stormwater covers Units Discharges 9 and 10). - ---------------------------------------------------------------------------------------------------------------------------------- Notice of Not required Notice of Not required Notice of Notice of Discharges to Intent/NPDES for peaking Intent to be - stormwater Intent to be Intent to be existing General plants. filed after discharges filed after filed after Wansley site Permits-Operational completion of covered under completion of completion of retention pond. Activities construction. NPDES construction. construction. Stormwater Wastewater Discharges Discharge Permit. - ---------------------------------------------------------------------------------------------------------------------------------- Clean Water Act Wetlands Issued 1/12/00 Issued According to Issued 11/6/01 Issued 4/21/00 Section 404 Delineation for the 11/4/00 for Southern for the for gas line Permits- Corps of Survey construction gas pipeline; Power's construction crossing Engineers ("COE") 2/24/99. A of natural gas issued Assessment, of the river; also, a Project pipeline. 12/20/00 for this is not substation Stream Buffer Completion intake and required. expansion, the Variance from Report was discharge electric GEPD was submitted to structures. transmission issued 10/5/00 COE on line, and the for 7/20/01. gas pipeline. construction of gas pipeline. - ----------------------------------------------------------------------------------------------------------------------------------
A-33 TABLE 6 STATUS OF KEY PERMITS AND APPROVALS REQUIRED FOR OPERATION
================================================================================================================================== DAHLBERG FRANKLIN HARRIS MCINTOSH STANTON WANSLEY PERMIT/APPROVAL FACILITY FACILITY FACILITY FACILITY FACILITY FACILITY - ---------------------------------------------------------------------------------------------------------------------------------- Water Withdrawal N/A Issued 4/30/00 Certificate Application Water to be Issued Permits by GEPD to of Beneficial submitted provided by 10/31/00 by withdraw water Use from the 5/31/02; OUC pursuant GEPD; petition from Goat Rock Alabama permit to agreement filed against Reservoir. Department of issuance OUC has with Permit; Also, the Economic and expected 7/03. Orange County, appeals Federal Energy Community Florida. hearing began Regulatory Affairs to be OUC's plan is 7/16/01; Commission obtained currently Administrative issued prior to the under review Law Judge approval on start of by St. John's issued an 10/10/00 to operations. River Water amended order withdraw Southern Management 4/24/02. additional Power District. Permit water through submitted reissued in an existing Declaration accordance penstock in of Beneficial with Goat Rock Dam. Use on Administrative 3/29/01. Order 5/22/02. - ---------------------------------------------------------------------------------------------------------------------------------- Federal Aviation Issued Issued 4/25/00. On 5/30/01, FAA review in Not required. Issued Administration 7/15/99; FAA issued a progress. 12/12/00. ("FAA") Notice of extended determination Construction or 7/19/00. that the Alteration Permits stacks are for Stacks not a hazard to navigation. - ---------------------------------------------------------------------------------------------------------------------------------- Order of N/A N/A N/A N/A Issued 9/11/01 N/A Certification by the State of Florida Siting Board. - ---------------------------------------------------------------------------------------------------------------------------------- Spill Prevention Finalized on Construction In place for To be Existing plan Prepared Control and 9/27/00. plan revised oil flush as prepared to be amended 1/7/03. Countermeasure and certified of 8/26/02; prior to the to include new ("SPCC") Plan 12/6/02; operational start of unit. operational plan is being operation. Temporary plan plan in place prepared. in place. 10/15/01. ==================================================================================================================================
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 "NOX State Implementation Plan ("SIP") Call Rule" for the purpose of controlling NOX, a precursor to ozone, and a pollutant of concern. As required by the USEPA rules, Alabama and Georgia are subject to the NOX SIP Call, which will impose NOX allowance obligations on certain emission sources. The USEPA has approved Alabama's SIP that includes the Franklin and Harris Facilities. As such, each facility will be required to obtain allowances to cover annual NOX emissions starting in 2004. Calculations performed by the Alabama Department of Environmental Management ("ADEM") propose 35 tons of NOX allocations to each Harris Facility CT train for a total of 140 tons for the four trains and 33 tons of NOX allocations to each Franklin 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. A-34 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 NOx 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 Dahlberg, McIntosh, and Wansley Facilities will be included within the area that will be subject to the NOX SIP Call Rule. Since the manner in which the NOX 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, McIntosh, and Wansley Facilities, all located in Georgia. The future cost of NOX 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 Generating Facilities are subject to Title IV of the Clean Air Act (Acid Rain Provisions) whereby each unit must possess sulfur dioxide ("SO2") allowances to cover its emissions beginning in 2000. The future cost of SO2 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 NOX requirements under the Acid Rain Program. - For the purpose of estimating NOX and SO2 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 NOX 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 SO2 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. - The modification of the NPDES Permit and the Surface Water Withdrawal Permit of the adjacent steam plant to accommodate the McIntosh Project have not yet been issued and are under review by the Georgia Environmental Protection Division. As such, we have not reviewed the conditions to be set forth in the permits. - 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 ("PM2.5"), regional haze, regional visibility, water intake structure regulations, and potential ratcheting of SO2 and NOX 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 primarily under the terms of the PPAs, which vary in term. For the purposes of the Projected Operating Results, we have assumed that all of the PPAs will A-35 expire at the end of their respective initial terms and will not be renewed. After expiration of the PPAs, 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 PPAs, the cost of fuel is reimbursed by, or purchased directly by, the power purchasers. Emissions allowances are also the responsibility of the power purchasers. The interest on the Senior Notes has been estimated by Lehman Brothers Inc. and Citigroup Global Markets Inc. (together, the "Representatives of the Initial Purchasers"). The Senior Notes have been assumed to mature on July 15, 2015. Southern Power has assumed that the Debt will be refinanced upon maturity. The Projected Operating Results are presented for each calendar year beginning July 1, 2003 through December 31, 2023, a period approximately eight years beyond the term of the Senior 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 PPAS All of the Generating Facilities have PPAs that have various terms and conditions. Several facilities have more than one PPA, as they apply to specific units. Most of the PPAs provide payment for capacity, start-up charges and variable O&M charges. The power purchasers and terms for each individual PPA are presented in Table 7. TABLE 7 POWER PURCHASE AGREEMENTS
TOTAL CONTRACT POWER CAPACITY CAPACITY POTENTIAL UNIT(S) PURCHASER(S) (MW)(1) (MW)(2) START DATE END DATE EXTENSION ------- ----------------- -------- -------- --------------- ----------------- ---------------- Dahlberg LEM 797(3) 578(3) June 1, 2000 December 31, 2004 December 31, 2009 Franklin 1 Georgia Power 542 542(4) June 1, 2002 May 31, 2010 N/A Franklin 2 Georgia Power 598 598(4) June 1, 2003 May 31, 2011 N/A Harris 1 Alabama Power 602 602 June 1, 2003 May 31, 2010 N/A Harris 2 Georgia Power 590 590 June 1, 2004 May 31, 2019 N/A McIntosh Georgia Power 998 998 June 1, 2005 May 31, 2020(5) N/A McIntosh Savannah Electric 192 192 June 1, 2005 May 31, 2020(5) N/A Stanton OUC, KUA, FMPA 394(6) 404 October 1, 2003 October 31, 2013 October 31, 2033 Wansley Georgia Power 897 897 June 1, 2002 December 31, 2009 N/A Wansley Savannah Electric 192 192 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) Assumes the extension of the fuel transportation agreement, as expected by Southern Power. (6) 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. A-36 THE DAHLBERG FACILITY Dahlberg 1 through 5 are currently in operation and are realizing revenue under the terms of the 1998 LEM PPA. LEM has the right to extend the term of this 1998 LEM PPA to December 31, 2009; however, we have assumed for the purposes of the Projected Operating Results that this 1998 LEM PPA will expire December 31, 2004. Southern Power will receive revenues from Dahlberg 1 through 5 for capacity, start-up and variable operations from LEM. Start-up charges are paid under the 1998 LEM PPA for starts in excess of 750 over the initial term of the 1998 LEM PPA. 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 PPA. 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 PPA. As with the 1998 LEM PPA, LEM has the right to extend this contract; however, we have assumed for the purposes of the Projected Operating Results that the 1999 LEM PPA will expire on December 31, 2004. Revenues from operations of these units include capacity payments, start-up charges and variable operations payments. 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 PPA. 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. THE FRANKLIN FACILITY The Franklin PPA includes provisions for selling capacity and associated energy from Franklin 1 and Franklin 2 to Georgia Power. The agreement expires May 31, 2010 for Franklin 1 and May 31, 2011 for Franklin 2. For Franklin 1 and Franklin 2, the annual average projected capacities are 542 MW and 598 MW, respectively. Average contract capacity values are 542 MW for Franklin 1 and 400 MW through June 1, 2004 and 598 MW thereafter for Franklin 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 fixed for the term of the Franklin PPA. 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 Franklin PPA. 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 indexed to the 1999 Gross Domestic Product - Implicit Price Deflator ("GDP-IPD"). We have assumed the GDP-IPD will increase at 2.6 percent from 2003. Start-up charges are per unit per start and are based upon the total number of starts. Under the terms of the Franklin PPA, the start-up charges are indexed to both the January 1, 1999 U.S. City Average Consumer Price Index for All Urban 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 the CPI will escalate at 2.6 percent after January 1, 2003 and the midpoint in the "Daily Price Survey" will be as projected by PA Consulting in their delivered fuel forecast. In addition, before initiation of the Franklin PPA as it relates to Franklin 2, a portion of the output from Franklin 2 is to be sold to third parties pursuant to contracts entered into by Southern Power. During the remainder of 2003, net revenues associated with these third-party contract sales will be approximately $1,823,000 based on the executed contracts as reported by Southern Power. A-37 THE HARRIS FACILITY Harris 1 and 2 are to sell power under separate PPAs 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 PPA, 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, 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 PPAs. 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 indexed to the 1999 GDP-IPD. We have assumed that the GDP-IPD and all inflation-related indices will increase at 2.6 percent from 2003. Start-up charges are per unit per start and are based upon the total number of starts. Under the terms of the Harris 1 and 2 PPAs, 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 the CPI will escalate at 2.6 percent after January 1, 2003 and the midpoint in the "Daily Price Survey" will be as projected by PA Consulting in their delivered fuel forecast. THE MCINTOSH FACILITY The McIntosh PPAs include provisions for selling capacity and associated energy generated by the McIntosh Facility to Georgia Power and Savannah Electric. Under the terms of the McIntosh PPAs, energy sales start on June 1, 2005 and expire May 31, 2020. If certain fuel agreements are not in place for the final year of each of the McIntosh PPAs, that agreement may be terminated in 2019. Southern Power anticipates an extension of the fuel transportation agreement at the appropriate time and expects the term of each McIntosh PPAs to be effective through May 31, 2020. Contract capacity and associated energy from McIntosh are sold as blocks, each rated at from 550 to 685 MW. The contract capacity equals the projected annual average capacity. Capacity pricing varies by month with 70 percent of the annual capacity payment occurring during June-September and 30 percent occurring in the months remaining. Additional capacity payments are available for contract availability above 96.0 percent. Southern Power has indicated that it would provide energy from alternate resources in order to receive the maximum capacity payment under the McIntosh PPAs. We have assumed the contract availability is equal to 99.0 percent based upon the purchase of replacement energy from the market, resulting in an increase in capacity payments of 4.0 percent. Start-up charges are paid for starts in excess of 150 starts per year and are indexed to the 2001 CPI. We have assumed that the CPI will increase at 2.6 percent from January 1, 2003. Variable O&M payments are also indexed to the 2001 CPI. THE STANTON FACILITY Under the terms of the Stanton PPAs, 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 PPAs commences upon commercial operation of the Stanton Facility. For the purposes of the Projected Operating Results, we have assumed that the Stanton PPAs 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. A-38 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. 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. 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; (2) an hourly variable O&M charge while firing natural gas 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 in the CPI will be 2.6 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. The start charges are 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 in the CPI will be 2.6 percent per year. THE WANSLEY FACILITY The Wansley PPAs include provisions for selling capacity and associated energy generated by the Wansley Facility to Georgia Power and Savannah Electric. Under the terms of the Wansley PPAs, energy sales terminate 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 through 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 PPAs. 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. Start-up charges are paid for starts in excess of 50 starts per year indexed to the 1999 GDP-IPD. We have assumed that the GDP-IPD will increase at 2.6 percent from 2003. Variable O&M payments are also indexed to the 1999 GDP-IPD. OTHER REVENUES FROM ELECTRICITY SALES Southern Power has assumed that a portion of the capacity and associated energy from Franklin 1, Franklin 2, and Harris 2 will be sold into the market before initiation of their respective PPAs. In addition, capacity of the Dahlberg Facility above the requirements of the LEM PPAs is assumed to be sold into the market. Market prices have been estimated by PA Consulting in 2001 dollars and have been adjusted for inflation. For the purposes of the A-39 Projected Operating Results, the general inflation rate has been assumed to be 2.6 percent per year. PA Consulting also provided monthly dispatch hours for each of these facilities during this period. After the expiration of the PPAs, 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 PPAs 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 PPAs 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 2.6 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 PPAs. These costs are incurred by Southern Power after the expiration of the PPAs. These charges have been estimated by Southern Power, as derived from their fuel plans for the Franklin, Harris, McIntosh, 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 2003 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-40 PURCHASED POWER In order to maximize the capacity payments under the PPAs, 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 SO2 and NOX 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 SO2 and NOX allowances. In the event of a shortfall during the term of any of the various PPAs, the emissions allowance expense would be the contractual obligation of the buyer of the electricity, but excess allowances could be sold by Southern Power. For the purpose of the Projected Operating Results, we have assumed market NOX emissions allowance prices of $2,000 per ton in 2004, $1,700 per ton in 2005, and escalating thereafter at the assumed rate of inflation. We have assumed market SO2 emissions allowance prices of $150 per ton in 2003, escalating thereafter at 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 and insurance costs have been estimated by Southern Power for 2003 and have been assumed to escalate at the rate of inflation. ANNUAL INTEREST We have included actual interest due on the 2002 Notes and interest payments on the $575,000,000 principal amount of the Senior Notes at an interest rate of 4.875 percent per year, as reported by the Representatives of the Initial Purchasers, as well as interest on Debt assumed to be issued in 2005. The Short-Term Notes were issued at a floating interest rate assumed to be 4.875 percent per year, as estimated by the Representatives of the Initial Purchasers. The scheduled amortization of the 2002 Notes consists of a single payment due on July 15, 2012. The scheduled amortization of the Senior Notes consists of a single payment due on July 15, 2015. Interest payments on the Senior Notes are due each July 15 and January 15 beginning January 15, 2004. We have assumed that an additional $384,000,000 of Debt will be issued July 1, 2005 at an interest rate of 7.50 percent per year, as estimated by the Representatives of the Initial Purchasers. Southern Power has assumed that the Debt will be refinanced upon maturity at the same principal amounts and respective interest rates, as estimated by the Representatives of the Initial Purchasers. 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 the 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 3.97 times the annual interest requirement in each year during the term of the Senior Notes and a weighted average coverage of 4.41 times the annual interest requirement on the Debt over the term of the Senior 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 A-41 the Debt will be refinanced upon maturity. The weighted average interest coverage has been calculated as the total net operating revenues, as shown in Exhibit A-1, over the term of the Senior Notes divided by the total interest payments on the Debt over the term of the Senior 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 increased 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 sensitivity cases (a), (b) and (c), 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 sensitivity cases (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 8. A-42 TABLE 8 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 ------- ------------ ------------ ------------ ------- ------------ --------- --------- 2003(2) 3.99 3.97 4.00 3.99 3.77 3.85 3.67 3.86 2004 4.55 4.47 4.59 4.55 4.32 4.44 4.26 4.42 2005 4.46 4.34 4.56 4.52 4.22 4.33 4.16 4.34 2006 4.17 3.92 4.32 4.19 3.95 4.03 3.87 4.04 2007 3.97 3.61 4.16 3.99 3.75 3.80 3.66 3.83 2013 4.90 4.80 4.83 4.79 4.59 4.76 4.58 4.75 2018 4.86 5.00 4.66 4.91 4.55 4.76 4.59 4.71 2023 4.86 5.16 4.98 4.90 4.49 4.77 4.62 4.69 Minimum(3) 3.97 3.61 4.00 3.98 3.75 3.80 3.66 3.83 Average(4) 4.41 4.23 4.47 4.37 4.15 4.26 4.10 4.27
-------------------- (1) Interest coverages assume the refinancing of the Debt upon maturity at the same principal amounts and respective interest rates, as estimated by the Representatives of the Initial Purchasers. (2) Represents partial year beginning July 1. (3) Represents minimum interest coverage on the Debt during any year over the term of the Senior Notes assuming no principal repayment. (4) Represents the weighted average interest coverage on the Debt over the term of the Senior 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 their 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, Georgia Power, Alabama Power, and Savannah Electric and the operators 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-43 4. Southern Power, SCS, Georgia Power, Alabama Power, and Savannah Electric 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 McIntosh PPAs will be approved by the FERC in a timely manner. 8. The CPI, GDP-IPD, general inflation and all inflation-related indices will increase at a rate of 2.6 percent per year based on a March 10, 2003 projection prepared by Blue Chip Economic Indicators. 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 PPAs as projected by PA Consulting, at prices determined in accordance with the relevant PPAs. After the term of the PPAs, Southern Power will enter into long-term power purchase agreements at prices equivalent to the market electricity prices projected by PA Consulting in 2001 dollars and adjusted for assumed inflation and will sell the quantities of electricity as projected by PA Consulting. 11. The Franklin Facility will earn the revenue from contract sales to third parties in 2003 as reported by Southern Power. 12. Certain of the Generating Facilities will achieve contract availabilities under their respective PPAs 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 PPAs 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 PPAs. 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 2003 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 Debt. The price of NOX emissions allowances will be $2,000 per ton in 2004, $1,700 per ton in 2005, and will escalate thereafter at the assumed rate of inflation. The price of SO2 emissions allowances will be $150 per ton in 2003 and will escalate thereafter at 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. The principal amount of the Senior Notes will be $575,000,000. The interest rate on the Senior Notes will be 4.875 percent per year, as reported by the Representatives of the Initial Purchasers. The interest rate on the principal amount of Short-Term Notes of $100,000,000 will be 4.875 percent per year, as A-44 estimated by the Representatives of the Initial Purchasers. An additional $384,000,000 will be issued July 1, 2005 at an interest rate of 7.50 percent per year, as estimated by the Representatives of the Initial Purchasers. The Debt will be refinanced upon maturity at the same principal amounts and respective 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 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 PPAs 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. Through the experience of Southern Power, Alabama Power, Georgia Power, Savannah Electric or other Southern Company subsidiaries, SCS has demonstrated the capability to operate the Generating Facilities. The operating programs and procedures which are proposed or currently in place for the Generating Facilities are consistent with generally accepted practices in the industry, and SCS has incorporated organizational structures that are comparable to other facilities using similar technologies for a similar service. 7. 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. 8. The Generating Facilities should be capable of achieving the required average annual contract availabilities under the PPAs 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 A-45 capable of achieving an average annual availability of 92 percent, which includes provision for forced and scheduled maintenance. 9. Based on our Phase I environmental site assessment for the McIntosh Facility, we did not identify any environmental concerns related to site contamination issues. Because no updated ESAs of previous or recent environmental investigations regarding the potential for site contamination issues at the sites of the other Generating Facilities have been provided for our review, we can offer no opinion with respect to potential site contamination issues at the sites of the Dahlberg, Franklin, Harris, Stanton, and Wansley Facilities, if any, or the potential for future remediation. 10. 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. We note that the modification of the NPDES Permit and the Surface Water Withdrawal Permit of the adjacent steam plant to accommodate the McIntosh Facility have not yet been issued and are under review by the Georgia Environmental Protection Division. As such, we have not reviewed the conditions to be set forth in the permits. 11. 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. 12. 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 3.97 times the annual interest requirement in each year during the term of the Senior Notes and a weighted average coverage of 4.41 times the annual interest requirement on the Debt over the term of the Senior 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-46 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 2009 - ------------------------ --------- --------- --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 31.3% 29.5% 31.7% 39.1% 43.8% 44.9% 43.6% Contract Energy Sales (GWh)(4) 5,943 11,442 16,544 20,333 22,763 23,315 22,607 Other Energy Sales (GWh)(4) 1,116 765 0 9 38 73 86 --------- --------- --------- --------- --------- --------- --------- Total Energy Sales (GWh) 7,059 12,207 16,544 20,342 22,800 23,388 22,692 Fuel Consumption (BBtu) 48,697 92,948 124,247 152,609 168,579 172,934 167,909 Average Net Heat Rate (Btu/kWh)(5) 7,710 7,788 7,715 7,685 7,572 7,572 7,575 SO(2) Allowances Purchased (Tons)(6) 24 47 62 77 83 86 85 NO(X) Allowances Purchased (Tons)(7) 0 (70) 165 229 292 314 290 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 34.44 34.72 29.42 26.55 23.42 23.20 23.70 Other Capacity Price ($/MWh)(10) $ 16.91 18.52 16.99 17.18 16.83 19.29 36.69 Other Energy Price ($/MWh)(10) $ 52.82 48.71 0.00 67.31 68.32 65.64 67.93 Fuel Price ($/MMBtu)(11) $ 5.38 4.96 0.00 3.76 3.58 3.69 3.80 SO(2) Allowances ($/Ton)(12) $ 150 154 158 162 166 171 175 NO(X) Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836 1,884 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 16,645 34,138 0 0 0 0 0 Franklin (14) $ 85,818 109,905 116,396 120,196 122,832 124,145 124,376 Harris (14) $ 36,237 115,862 142,441 146,622 144,089 144,558 144,040 McIntosh $ 0 0 87,301 130,323 123,410 127,323 121,774 Stanton $ 10,374 45,040 44,420 45,276 45,484 45,836 46,076 Wansley $ 55,624 92,339 96,116 97,366 97,269 99,010 99,498 Other Electricity Revenues Dahlberg $ 2,223 4,429 13,540 14,271 15,987 20,192 35,052 Franklin (14) $ 3,222 12,310 0 0 0 0 0 Harris $ 62,689 29,934 0 0 0 0 0 McIntosh $ 0 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 0 --------- --------- --------- --------- --------- --------- --------- Total Operating Revenues $ 272,832 443,957 500,214 554,054 549,071 561,064 570,816 OPERATING EXPENSES ($000) Fuel Dahlberg $ 38 0 0 429 1,753 3,520 4,242 Franklin $ 1,221 8,423 0 0 0 0 0 Harris $ 45,315 21,309 0 0 0 0 0 McIntosh $ 0 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 0 Purchased Power (15) $ 43,081 13,258 20,974 22,153 24,224 25,754 25,204 Operations & Maintenance (16) $ 33,111 60,848 77,843 92,168 102,824 108,667 110,018 Administration and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873 33,364 --------- --------- --------- --------- --------- --------- --------- Total Operating Expenses $ 135,495 130,804 128,551 146,671 161,192 170,814 172,828 NET OPERATING REVENUES ($000) $ 137,337 313,154 371,663 407,383 387,879 390,250 397,987 ANNUAL INTEREST($000)(18) $ 34,422 68,844 83,244 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 3.99 4.55 4.46 4.17 3.97 4.00 4.08 2003-15 AVG INTEREST COVERAGE (20) 4.41 Year Ending December 31, 2010 2011 2012 2013 --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 41.2% 42.3% 40.0% 36.5% Contract Energy Sales (GWh)(4) 12,712 10,007 8,847 7,832 Other Energy Sales (GWh)(4) 8,491 11,721 11,674 10,804 -------- ------- ------- ------- Total Energy Sales (GWh) 21,203 21,728 20,521 18,636 Fuel Consumption (BBtu) 159,487 162,653 154,397 141,954 Average Net Heat Rate (Btu/kWh)(5) 7,615 7,557 7,596 7,660 SO(2) Allowances Purchased (Tons)(6) 80 83 76 70 NO(X) Allowances Purchased (Tons)(7) 257 274 253 213 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 27.06 27.44 28.12 32.21 Other Capacity Price ($/MWh)(10) 46.49 58.16 62.97 67.71 Other Energy Price ($/MWh)(10) 45.84 47.51 49.19 50.06 Fuel Price ($/MMBtu)(11) 4.49 4.63 4.80 5.00 SO(2) Allowances ($/Ton)(12) 180 184 189 194 NO(X) Allowances ($/Ton)(13) 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Franklin (14) 82,134 25,853 0 0 Harris (14) 89,115 74,485 74,217 74,430 McIntosh 126,117 127,802 127,964 138,295 Stanton 46,560 46,476 46,609 39,515 Wansley 0 0 0 0 Other Electricity Revenues Dahlberg 40,321 53,484 55,407 56,286 Franklin (14) 81,488 225,938 271,958 260,111 Harris 104,379 167,795 164,181 167,052 McIntosh 0 0 0 0 Stanton 0 0 0 9,790 Wansley 287,063 309,602 311,136 295,566 --------- --------- --------- --------- Total Operating Revenues 857,177 1,031,435 1,051,472 1,041,045 OPERATING EXPENSES ($000) Fuel Dahlberg 2,569 5,267 3,711 1,718 Franklin 46,993 123,819 146,873 138,743 Harris 62,530 97,649 94,037 96,545 McIntosh 0 0 0 0 Stanton 0 0 0 5,867 Wansley 176,261 182,099 180,998 169,780 Purchased Power (15) 13,054 10,511 10,282 5,270 Operations & Maintenance (16) 108,282 114,767 114,695 109,371 Administration and General (17) 33,872 34,386 34,924 35,465 --------- --------- --------- --------- Total Operating Expenses 443,562 568,499 585,520 562,759 NET OPERATING REVENUES ($000) 413,615 462,936 465,952 478,286 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.24 4.74 4.77 4.90 2003-15 AVG INTEREST COVERAGE (20)
A-47 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ------------------------ ---------- ---------- ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 33.1% 31.3% 28.5% 26.3% 24.5% 22.8% Contract Energy Sales (GWh)(4) 6,352 6,051 5,629 5,115 4,738 3,576 Other Energy Sales (GWh)(4) 10,550 9,968 8,937 8,339 7,786 8,061 ---------- ---------- ---------- ---------- ---------- ---------- Total Energy Sales (GWh) 16,901 16,020 14,567 13,453 12,524 11,638 Fuel Consumption (BBtu) 130,059 123,431 113,265 105,067 98,368 92,010 Average Net Heat Rate (Btu/kWh)(5) 7,740 7,750 7,822 7,855 7,901 7,928 SO(2) Allowances Purchased (Tons)(6) 66 62 57 52 49 46 NO(X) Allowances Purchased (Tons)(7) 174 143 102 81 68 54 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 34.12 35.99 39.32 43.28 46.20 46.07 Other Capacity Price ($/MWh)(10) $ 67.83 71.68 74.42 76.04 79.21 83.11 Other Energy Price ($/MWh)(10) $ 52.74 53.05 55.13 57.70 59.65 62.83 Fuel Price ($/MMBtu)(11) $ 5.34 5.53 5.79 6.03 6.21 6.44 SO(2) Allowances ($/Ton)(12) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 0 Franklin (14) $ 0 0 0 0 0 0 Harris (14) $ 75,619 76,488 75,534 74,859 75,898 16,327 McIntosh $ 141,097 141,329 145,813 146,477 143,008 148,445 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 55,353 56,856 58,471 59,764 62,426 65,796 Franklin (14) $ 250,895 236,471 229,122 221,854 222,225 219,581 Harris $ 154,761 155,722 149,400 149,374 150,355 243,589 McIntosh $ 0 0 0 0 0 0 Stanton $ 85,586 86,686 88,008 88,055 87,464 85,084 Wansley $ 282,582 281,329 266,973 267,947 260,555 260,275 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Revenues $1,045,893 1,034,881 1,013,321 1,008,330 1,001,931 1,039,097 OPERATING EXPENSES ($000) Fuel Dahlberg $ 1,229 291 0 0 0 0 Franklin $ 133,670 122,726 118,812 111,665 107,328 98,985 Harris $ 87,889 90,309 85,446 85,355 83,464 129,387 McIntosh $ 0 0 0 0 0 0 Stanton $ 51,374 51,636 52,163 51,430 51,765 49,421 Wansley $ 162,611 162,635 149,621 146,902 140,054 134,564 Purchased Power (15) $ 5,040 4,895 4,646 4,447 4,285 1,949 Operations & Maintenance (16) $ 105,991 109,381 103,618 102,295 102,455 100,654 Administration and General (17) $ 36,022 36,601 37,186 37,792 38,416 39,052 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Expenses $ 583,827 578,475 551,492 539,886 527,767 554,013 NET OPERATING REVENUES ($000) $ 462,066 456,406 461,829 468,444 474,164 485,084 ANNUAL INTEREST($000)(18) $ 97,644 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.73 4.67 4.73 4.80 4.86 4.97 2003-15 AVG INTEREST COVERAGE (20) 4.41 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 21.0% 20.2% 18.4% 18.4% Contract Energy Sales (GWh)(4) 551 0 0 0 Other Energy Sales (GWh)(4) 10,107 10,274 9,375 9,375 ---------- ---------- ---------- ---------- Total Energy Sales (GWh) 10,657 10,274 9,375 9,375 Fuel Consumption (BBtu) 84,797 82,221 75,165 75,165 Average Net Heat Rate (Btu/kWh)(5) 7,957 8,003 8,018 8,018 SO(2) Allowances Purchased (Tons)(6) 43 42 38 38 NO(X) Allowances Purchased (Tons)(7) 31 28 11 11 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 50.29 0.00 0.00 0.00 Other Capacity Price ($/MWh)(10) 84.87 87.74 89.36 91.68 Other Energy Price ($/MWh)(10) 64.45 66.02 67.65 69.40 Fuel Price ($/MMBtu)(11) 6.69 6.85 7.10 7.26 SO(2) Allowances ($/Ton)(12) 232 238 244 251 NO(X) Allowances ($/Ton)(13) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Franklin (14) 0 0 0 0 Harris (14) 0 0 0 0 McIntosh 27,698 0 0 0 Stanton 0 0 0 0 Wansley 0 0 0 0 Other Electricity Revenues Dahlberg 67,299 69,661 70,940 72,784 Franklin (14) 208,898 213,547 197,972 203,119 Harris 285,657 282,765 283,337 290,702 McIntosh 217,143 279,817 259,961 266,720 Stanton 86,687 84,437 85,808 88,039 Wansley 257,924 257,133 254,567 261,186 ---------- ---------- ---------- ---------- Total Operating Revenues 1,151,306 1,187,360 1,152,585 1,182,550 OPERATING EXPENSES ($000) Fuel Dahlberg 0 0 0 0 Franklin 92,020 92,989 80,882 82,525 Harris 149,382 146,630 145,457 148,754 McIntosh 112,453 142,923 128,857 131,721 Stanton 51,114 49,309 50,143 51,047 Wansley 133,575 131,388 128,651 131,615 Purchased Power (15) 0 0 0 0 Operations & Maintenance (16) 100,077 105,674 100,368 120,978 Administration and General (17) 39,705 40,375 41,060 41,768 ---------- ---------- ---------- ---------- Total Operating Expenses 678,326 709,288 675,417 708,407 NET OPERATING REVENUES ($000) 472,980 478,072 477,168 474,143 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.84 4.90 4.89 4.86 2003-15 AVG INTEREST COVERAGE (20)
A-48 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 - ------------------------ -------- ------- ------- ------- ------- ------- DAHLBERG FACILITY - ----------------- PERFORMANCE Average Annual Capacity (MW)(2) 797 797 797 797 797 797 Average Annual Contract Capacity (MW)(19) 578 578 0 0 0 0 Average Annual Other Capacity (MW)(19) 239 239 797 797 797 797 Capacity Factor(%)(3) 0.2% 0.0% 0.0% 0.1% 0.5% 1.1% Energy Generation (GWh) 7 0 0 9 38 73 Contract Energy Sales (GWh) 6 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 1 0 0 9 38 73 Net Heat Rate (Btu/kWh)(5) 12,733 0 0 13,253 13,020 13,016 Contract Fuel Consumption (BBtu) 77 0 0 0 0 0 Other Fuel Consumption (BBtu) 9 0 0 114 490 955 SO(2) Allowances Purchased (Tons)(6) 0 0 0 0 0 0 NO(X) Allowances Purchased (Tons)(7) 0 0 0 1 6 11 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) $2,620.87 0.00 0.00 0.00 0.00 0.00 Other Electricity Capacity ($/kW-yr) $ 9.09 18.52 16.99 17.18 16.83 19.29 Energy ($/MWh) $ 70.32 0.00 0.00 67.31 68.32 65.64 Fuel ($/MMBtu)(12) $ 4.19 0.00 0.00 3.76 3.58 3.69 SO(2) Allowances ($/Ton)(13) $ 150 154 158 162 166 171 NO(X) Allowances ($/Ton)(14) $ 0 2,000 1,700 1,744 1,790 1,836 OPERATING REVENUES ($000) Contract Electricity Revenues $ 16,645 34,138 0 0 0 0 Other Electricity Revenues Capacity Revenues $ 2,173 4,429 13,540 13,692 13,416 15,376 Energy Revenues $ 50 0 0 579 2,571 4,816 --------- ------- ------- ------- ------- ------- Total Operating Revenues $ 18,868 38,567 13,540 14,271 15,987 20,192 OPERATING EXPENSES ($000)(16) Fuel Costs $ 38 0 0 429 1,753 3,520 Purchased Power $ 22 0 0 0 0 0 Operating and Maintenance $ 5,141 2,715 2,786 3,215 4,531 6,207 Administrative and General $ 2,605 5,268 5,323 5,378 5,435 5,496 --------- ------- ------- ------- ------- ------- Total Operating Expenses $ 7,806 7,983 8,109 9,022 11,719 15,223 NET OPERATING REVENUES ($000) $ 11,062 30,584 5,431 5,249 4,268 4,969 Year Ending December 31, 2009 2010 2011 2012 2013 - ------------------------ ------- ------- ------- ------- ------- DAHLBERG FACILITY - ----------------- PERFORMANCE Average Annual Capacity (MW)(2) 797 797 797 797 797 Average Annual Contract Capacity (MW)(19) 0 0 0 0 0 Average Annual Other Capacity (MW)(19) 797 797 797 797 797 Capacity Factor(%)(3) 1.2% 0.7% 1.4% 1.0% 0.4% Energy Generation (GWh) 86 50 100 69 31 Contract Energy Sales (GWh) 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 86 50 100 69 31 Net Heat Rate (Btu/kWh)(5) 13,063 13,115 13,070 12,991 13,042 Contract Fuel Consumption (BBtu) 0 0 0 0 0 Other Fuel Consumption (BBtu) 1,117 657 1,307 894 402 SO(2) Allowances Purchased (Tons)(6) 1 0 1 0 0 NO(X) Allowances Purchased (Tons)(7) 13 8 15 11 5 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) 0.00 0.00 0.00 0.00 0.00 Other Electricity Capacity ($/kW-yr) 36.69 46.49 58.16 62.97 67.51 Energy ($/MWh) 67.93 65.25 71.34 75.87 80.59 Fuel ($/MMBtu)(12) 3.80 3.91 4.03 4.15 4.28 SO(2) Allowances ($/Ton)(13) 175 180 184 189 194 NO(X) Allowances ($/Ton)(14) 1,884 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues 0 0 0 0 0 Other Electricity Revenues Capacity Revenues 29,243 37,052 46,350 50,186 53,802 Energy Revenues 5,809 3,269 7,134 5,221 2,484 ------- ------- ------- ------- ------- Total Operating Revenues 35,052 40,321 53,484 55,407 56,286 OPERATING EXPENSES ($000)(16) Fuel Costs 4,242 2,569 5,267 3,711 1,718 Purchased Power 0 0 0 0 0 Operating and Maintenance 6,917 5,468 7,957 8,451 4,948 Administrative and General 5,556 5,617 5,682 5,749 5,815 ------- ------- ------- ------- ------- Total Operating Expenses 16,715 13,654 18,906 17,911 12,481 NET OPERATING REVENUES ($000) 18,337 26,667 34,578 37,496 43,805
A-49 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ------------------------ ------- ------- ------- ------- ------- ------- DAHLBERG FACILITY - ----------------- PERFORMANCE Average Annual Capacity (MW)(2) 797 797 797 797 797 797 Average Annual Contract Capacity (MW)(19) 0 0 0 0 0 0 Average Annual Other Capacity (MW)(19) 797 797 797 797 797 797 Capacity Factor(%)(3) 0.3% 0.1% 0.0% 0.0% 0.0% 0.0% Energy Generation (GWh) 22 5 0 0 0 0 Contract Energy Sales (GWh) 0 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 22 5 0 0 0 0 Net Heat Rate (Btu/kWh)(5) 12,761 12,754 0 0 0 0 Contract Fuel Consumption (BBtu) 0 0 0 0 0 0 Other Fuel Consumption (BBtu) 279 64 0 0 0 0 SO(2) Allowances Purchased (Tons)(6) 0 0 0 0 0 0 NO(X) Allowances Purchased (Tons)(7) 3 1 0 0 0 0 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 0.00 Other Electricity Capacity ($/kW-yr) $ 67.11 70.80 73.36 74.99 78.33 82.55 Energy ($/MWh) $ 85.39 84.90 0.00 0.00 0.00 0.00 Fuel ($/MMBtu)(12) $ 4.40 4.53 0.00 0.00 0.00 0.00 SO(2) Allowances ($/Ton)(13) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(14) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues $ 0 0 0 0 0 0 Other Electricity Revenues Capacity Revenues $53,486 56,430 58,471 59,764 62,426 65,796 Energy Revenues $ 1,867 426 0 0 0 0 ------- ------- ------- ------- ------- ------- Total Operating Revenues $55,353 56,856 58,471 59,764 62,426 65,796 OPERATING EXPENSES ($000)(16) Fuel Costs $ 1,229 291 0 0 0 0 Purchased Power $ 0 0 0 0 0 0 Operating and Maintenance $ 4,620 3,864 3,694 3,790 3,888 3,990 Administrative and General $ 5,883 5,954 6,027 6,102 6,180 6,257 ------- ------- ------- ------- ------- ------- Total Operating Expenses $11,732 10,109 9,721 9,892 10,068 10,247 NET OPERATING REVENUES ($000) $43,621 46,747 48,750 49,872 52,358 55,549 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ ------- ------- ------- ------- DAHLBERG FACILITY - ----------------- PERFORMANCE Average Annual Capacity (MW)(2) 797 797 797 797 Average Annual Contract Capacity (MW)(19) 0 0 0 0 Average Annual Other Capacity (MW)(19) 797 797 797 797 Capacity Factor(%)(3) 0.0% 0.0% 0.0% 0.0% Energy Generation (GWh) 0 0 0 0 Contract Energy Sales (GWh) 0 0 0 0 Other Energy Sales (Purchases)(GWh) 0 0 0 0 Net Heat Rate (Btu/kWh)(5) 0 0 0 0 Contract Fuel Consumption (BBtu) 0 0 0 0 Other Fuel Consumption (BBtu) 0 0 0 0 SO(2) Allowances Purchased (Tons)(6) 0 0 0 0 NO(X) Allowances Purchased (Tons)(7) 0 0 0 0 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) 0.00 0.00 0.00 0.00 Other Electricity Capacity ($/kW-yr) 84.44 87.40 89.01 91.32 Energy ($/MWh) 0.00 0.00 0.00 0.00 Fuel ($/MMBtu)(12) 0.00 0.00 0.00 0.00 SO(2) Allowances ($/Ton)(13) 232 238 244 251 NO(X) Allowances ($/Ton)(14) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues 0 0 0 0 Other Electricity Revenues Capacity Revenues 67,299 69,661 70,940 72,784 Energy Revenues 0 0 0 0 ------- ------- ------- ------- Total Operating Revenues 67,299 69,661 70,940 72,784 OPERATING EXPENSES ($000)(16) Fuel Costs 0 0 0 0 Purchased Power 0 0 0 0 Operating and Maintenance 4,093 4,201 4,310 4,422 Administrative and General 6,338 6,420 6,503 6,592 ------- ------- ------- ------- Total Operating Expenses 10,431 10,621 10,813 11,014 NET OPERATING REVENUES ($000) 56,868 59,040 60,127 61,770
A-50 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 - ------------------------ -------- -------- -------- -------- -------- -------- FRANKLIN FACILITY - ----------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,139 1,139 1,139 1,139 1,139 1,139 Average Annual Contract Capacity (MW) 942 1,090 1,139 1,139 1,139 1,139 Average Annual Other Capacity (MW) 99 82 0 0 0 0 Capacity Factor(%)(3) 35.3% 29.7% 32.2% 37.9% 45.6% 46.5% Energy Generation (GWh) 1,761 2,965 3,217 3,781 4,552 4,644 Contract Energy Sales (GWh) 2,385 2,784 3,300 3,878 4,670 4,764 Other Energy Sales (Purchases)(GWh) 29 216 0 0 0 0 Net Heat Rate (Btu/kWh)(5) 7,567 7,913 7,854 7,818 7,687 7,658 Contract Fuel Consumption (BBtu) 13,102 21,767 25,270 29,556 34,993 35,565 Other Fuel Consumption (BBtu) 223 1,693 0 0 0 0 SO(2) Allowances Purchased (Tons)(6) 7 12 13 15 17 18 NO(X) Allowances Purchased (Tons)(7) 0 (42) (34) (26) (9) (3) COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) $ 35.99 39.48 35.27 30.99 26.30 26.06 Other Electricity Capacity ($/kW-yr) $ 16.90 18.52 0.00 0.00 0.00 0.00 Energy ($/MWh) $ 54.10 50.00 0.00 0.00 0.00 0.00 Fuel ($/MMBtu)(12) $ 4.48 4.19 0.00 0.00 0.00 0.00 SO(2) Allowances ($/Ton)(13) $ 150 154 158 162 166 171 NO(X) Allowances ($/Ton)(14) $ 0 2,000 1,700 1,744 1,790 1,836 OPERATING REVENUES ($000) Contract Electricity Revenues $ 85,818 109,905 116,396 120,196 122,832 124,145 Other Electricity Revenues Capacity Revenues $ 1,670 1,525 0 0 0 0 Energy Revenues $ 1,552 10,785 0 0 0 0 -------- -------- -------- -------- -------- -------- Total Operating Revenues $ 89,040 122,215 116,396 120,196 122,832 124,145 OPERATING EXPENSES ($000)(16) Fuel Costs $ 1,221 8,423 0 0 0 0 Purchased Power $ 38,355 1,730 4,012 4,604 5,370 5,702 Operating and Maintenance $ 8,504 16,067 17,370 19,327 21,986 22,872 Administrative and General $ 4,317 8,715 8,800 8,888 8,978 9,069 -------- -------- -------- -------- -------- -------- Total Operating Expenses $ 52,396 34,935 30,182 32,819 36,334 37,643 NET OPERATING REVENUES ($000) $ 36,644 87,280 86,214 87,377 86,498 86,502 Year Ending December 31, 2009 2010 2011 2012 2013 - ------------------------ -------- -------- -------- -------- -------- FRANKLIN FACILITY PERFORMANCE Average Annual Capacity (MW)(2) 1,139 1,139 1,139 1,139 1,139 Average Annual Contract Capacity (MW) 1,139 1,139 598 0 0 Average Annual Other Capacity (MW) 0 542 1,139 1,139 1,139 Capacity Factor(%)(3) 44.1% 41.6% 41.1% 38.6% 34.6% Energy Generation (GWh) 4,398 4,147 4,101 3,850 3,453 Contract Energy Sales (GWh) 4,511 2,910 715 0 0 Other Energy Sales (Purchases)(GWh) 0 1,294 3,385 3,850 3,453 Net Heat Rate (Btu/kWh)(5) 7,690 7,791 7,694 7,748 7,821 Contract Fuel Consumption (BBtu) 33,820 22,131 5,485 0 0 Other Fuel Consumption (BBtu) 0 10,177 26,068 29,831 27,007 SO(2) Allowances Purchased (Tons)(6) 17 16 16 15 14 NO(X) Allowances Purchased (Tons)(7) (12) (20) (20) (24) (34) COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) 27.57 28.23 36.14 0.00 0.00 Other Electricity Capacity ($/kW-yr) 0.00 31.77 48.49 62.97 67.51 Energy ($/MWh) 0.00 49.66 50.42 52.00 53.05 Fuel ($/MMBtu)(12) 0.00 3.99 4.10 4.23 4.36 SO(2) Allowances ($/Ton)(13) 175 180 184 189 194 NO(X) Allowances ($/Ton)(14) 1,884 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues 124,376 82,134 25,853 0 0 Other Electricity Revenues Capacity Revenues 0 17,205 55,245 71,735 76,902 Energy Revenues 0 64,283 170,693 200,223 183,209 -------- -------- -------- -------- -------- Total Operating Revenues 124,376 163,622 251,791 271,958 260,111 OPERATING EXPENSES ($000)(16) Fuel Costs 0 46,993 123,819 146,873 138,743 Purchased Power 5,524 2,822 0 0 0 Operating and Maintenance 22,725 22,479 22,919 22,751 22,052 Administrative and General 9,164 9,260 9,358 9,461 9,565 -------- -------- -------- -------- -------- Total Operating Expenses 37,413 81,554 156,097 179,086 170,361 NET OPERATING REVENUES ($000) 86,963 82,068 95,694 92,872 89,750
A-51 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ------------------------ --------- --------- --------- --------- --------- --------- FRANKLIN FACILITY - ----------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,139 1,139 1,139 1,139 1,139 1,139 Average Annual Contract Capacity (MW) 0 0 0 0 0 0 Average Annual Other Capacity (MW) 1,139 1,139 1,139 1,139 1,139 1,139 Capacity Factor(%)(3) 31.9% 27.7% 25.3% 22.8% 21.4% 19.0% Energy Generation (GWh) 3,181 2,760 2,520 2,270 2,134 1,899 Contract Energy Sales (GWh) 0 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 3,181 2,760 2,520 2,270 2,134 1,899 Net Heat Rate (Btu/kWh)(5) 7,876 7,910 7,968 7,958 7,992 7,967 Contract Fuel Consumption (BBtu) 0 0 0 0 0 0 Other Fuel Consumption (BBtu) 25,054 21,832 20,082 18,068 17,052 15,130 SO(2) Allowances Purchased (Tons)(6) 13 11 10 9 9 8 NO(X) Allowances Purchased (Tons)(7) (36) (45) (51) (59) (58) (62) COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 0.00 Other Electricity Capacity ($/kW-yr) $ 67.11 70.80 73.36 74.99 78.33 82.55 Energy ($/MWh) $ 54.84 56.46 57.75 60.09 62.33 66.10 Fuel ($/MMBtu)(12) $ 4.48 4.62 4.80 5.01 5.20 5.38 SO(2) Allowances ($/Ton)(13) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(14) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues $ 0 0 0 0 0 0 Other Electricity Revenues Capacity Revenues $ 76,452 80,659 83,577 85,423 89,230 94,045 Energy Revenues $ 174,443 155,812 145,545 136,431 132,995 125,536 --------- --------- --------- --------- --------- --------- Total Operating Revenues $ 250,895 236,471 229,122 221,854 222,225 219,581 OPERATING EXPENSES ($000)(16) Fuel Costs $ 133,670 122,726 118,812 111,665 107,328 98,985 Purchased Power $ 0 0 0 0 0 0 Operating and Maintenance $ 21,769 21,204 21,366 20,868 20,886 20,329 Administrative and General $ 9,672 9,782 9,894 10,008 10,128 10,249 --------- --------- --------- --------- --------- --------- Total Operating Expenses $ 165,111 153,712 150,071 142,540 138,342 129,564 NET OPERATING REVENUES ($000) $ 85,784 82,759 79,051 79,314 83,883 90,017 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ --------- --------- --------- --------- FRANKLIN FACILITY - ----------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,139 1,139 1,139 1,139 Average Annual Contract Capacity (MW) 0 0 0 0 Average Annual Other Capacity (MW) 1,139 1,139 1,139 1,139 Capacity Factor(%)(3) 16.5% 16.3% 13.3% 13.3% Energy Generation (GWh) 1,651 1,631 1,330 1,330 Contract Energy Sales (GWh) 0 0 0 0 Other Energy Sales (Purchases)(GWh) 1,651 1,631 1,330 1,330 Net Heat Rate (Btu/kWh)(5) 8,004 8,033 8,065 8,065 Contract Fuel Consumption (BBtu) 0 0 0 0 Other Fuel Consumption (BBtu) 13,212 13,099 10,725 10,725 SO(2) Allowances Purchased (Tons)(6) 7 7 5 5 NO(X) Allowances Purchased (Tons)(7) (71) (69) (77) (77) COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) 0.00 0.00 0.00 0.00 Other Electricity Capacity ($/kW-yr) 84.44 87.40 89.01 91.32 Energy ($/MWh) 68.28 69.90 72.62 74.51 Fuel ($/MMBtu)(12) 5.63 5.75 5.89 6.05 SO(2) Allowances ($/Ton)(13) 232 238 244 251 NO(X) Allowances ($/Ton)(14) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues 0 0 0 0 Other Electricity Revenues Capacity Revenues 96,194 99,571 101,398 104,034 Energy Revenues 112,704 113,976 96,574 99,085 --------- --------- --------- --------- Total Operating Revenues 208,898 213,547 197,972 203,119 OPERATING EXPENSES ($000)(16) Fuel Costs 92,020 92,989 80,882 82,525 Purchased Power 0 0 0 0 Operating and Maintenance 19,770 20,183 19,360 19,862 Administrative and General 10,374 10,502 10,634 10,769 --------- --------- --------- --------- Total Operating Expenses 122,164 123,674 110,876 113,156 NET OPERATING REVENUES ($000) 86,734 89,873 87,096 89,963
A-52 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 - ------------------------ -------- -------- -------- -------- -------- -------- HARRIS FACILITY - --------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,192 1,192 1,192 1,192 1,192 1,192 Average Annual Contract Capacity (MW) 602 1,192 1,192 1,192 1,192 1,192 Average Annual Other Capacity (MW) 590 590 0 0 0 0 Capacity Factor(%)(3) 41.6% 37.7% 42.9% 49.0% 53.6% 55.1% Energy Generation (GWh) 2,171 3,934 4,486 5,119 5,600 5,754 Contract Energy Sales (GWh) 1,107 3,428 4,589 5,238 5,729 5,887 Other Energy Sales (Purchases)(GWh) 1,086 549 0 0 0 0 Net Heat Rate (Btu/kWh)(5) 7,766 7,810 7,712 7,669 7,556 7,531 Contract Fuel Consumption (BBtu) 8,442 26,421 34,594 39,261 42,311 43,337 Other Fuel Consumption (BBtu) 8,418 4,301 0 0 0 0 SO(2) Allowances Purchased (Tons)(6) 8 15 17 20 21 22 NO(X) Allowances Purchased (Tons)(7) 0 (28) (17) (6) 5 14 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) $ 32.73 33.80 31.04 27.99 25.15 24.55 Other Electricity Capacity ($/kW-yr) $ 9.09 5.87 0.00 0.00 0.00 0.00 Energy ($/MWh) $ 52.78 48.20 0.00 0.00 0.00 0.00 Fuel ($/MMBtu)(12) $ 4.48 4.18 0.00 0.00 0.00 0.00 SO(2) Allowances ($/Ton)(13) $ 150 154 158 162 166 171 NO(X) Allowances ($/Ton)(14) $ 0 2,000 1,700 1,744 1,790 1,836 OPERATING REVENUES ($000) Contract Electricity Revenues $ 36,237 115,862 142,441 146,622 144,089 144,558 Other Electricity Revenues Capacity Revenues $ 5,362 3,461 0 0 0 0 Energy Revenues $ 57,327 26,473 0 0 0 0 -------- -------- -------- -------- -------- -------- Total Operating Revenues $ 98,926 145,796 142,441 146,622 144,089 144,558 OPERATING EXPENSES ($000)(16) Fuel Costs $ 45,315 21,309 0 0 0 0 Purchased Power $ 1,175 2,058 4,779 5,248 5,638 6,029 Operating and Maintenance $ 8,960 17,603 19,545 21,750 23,491 24,525 Administrative and General $ 3,514 7,114 7,203 7,296 7,390 7,488 -------- -------- -------- -------- -------- -------- Total Operating Expenses $ 58,964 48,084 31,527 34,294 36,519 38,042 NET OPERATING REVENUES ($000) $ 39,962 97,712 110,914 112,328 107,570 106,516 Year Ending December 31, 2009 2010 2011 2012 2013 - ------------------------ -------- -------- -------- -------- -------- HARRIS FACILITY - --------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,192 1,192 1,192 1,192 1,192 Average Annual Contract Capacity (MW) 1,192 1,192 590 590 590 Average Annual Other Capacity (MW) 0 602 602 602 602 Capacity Factor(%)(3) 53.5% 49.8% 52.7% 49.5% 46.4% Energy Generation (GWh) 5,589 5,199 5,509 5,171 4,842 Contract Energy Sales (GWh) 5,718 3,416 2,739 2,621 2,302 Other Energy Sales (Purchases)(GWh) 0 1,846 2,839 2,616 2,598 Net Heat Rate (Btu/kWh)(5) 7,532 7,566 7,507 7,540 7,596 Contract Fuel Consumption (BBtu) 42,094 25,381 20,116 19,270 17,133 Other Fuel Consumption (BBtu) 0 13,951 21,242 19,722 19,649 SO(2) Allowances Purchased (Tons)(6) 21 20 21 19 18 NO(X) Allowances Purchased (Tons)(7) 4 (3) 2 (3) (10) COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) 25.19 26.09 27.19 28.31 32.33 Other Electricity Capacity ($/kW-yr) 0.00 31.77 58.16 62.97 67.51 Energy ($/MWh) 0.00 46.17 46.77 48.27 48.66 Fuel ($/MMBtu)(12) 0.00 3.98 4.10 4.22 4.35 SO(2) Allowances ($/Ton)(13) 175 180 184 189 194 NO(X) Allowances ($/Ton)(14) 1,884 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues 144,040 89,115 74,485 74,217 74,430 Other Electricity Revenues Capacity Revenues 0 19,130 35,021 37,920 40,652 Energy Revenues 0 85,249 132,774 126,261 126,400 -------- -------- -------- -------- -------- Total Operating Revenues 144,040 193,494 242,280 238,398 241,482 OPERATING EXPENSES ($000)(16) Fuel Costs 0 62,530 97,649 94,037 96,545 Purchased Power 6,011 2,989 3,259 3,216 2,887 Operating and Maintenance 24,672 24,223 25,804 26,012 26,410 Administrative and General 7,587 7,690 7,795 7,904 8,013 -------- -------- -------- -------- -------- Total Operating Expenses 38,270 97,433 134,506 131,169 133,854 NET OPERATING REVENUES ($000) 105,770 96,061 107,774 107,229 107,628
A-53 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ------------------------ --------- --------- --------- --------- --------- --------- HARRIS FACILITY - --------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,192 1,192 1,192 1,192 1,192 1,192 Average Annual Contract Capacity (MW) 590 590 590 590 590 590 Average Annual Other Capacity (MW) 602 602 602 602 602 1,192 Capacity Factor(%)(3) 41.2% 40.9% 36.9% 34.0% 32.5% 30.0% Energy Generation (GWh) 4,307 4,275 3,851 3,548 3,400 3,132 Contract Energy Sales (GWh) 2,145 2,119 1,928 1,720 1,656 495 Other Energy Sales (Purchases)(GWh) 2,216 2,209 1,972 1,871 1,785 2,637 Net Heat Rate (Btu/kWh)(5) 7,701 7,717 7,769 7,830 7,863 7,926 Contract Fuel Consumption (BBtu) 16,112 15,932 14,587 13,145 12,738 3,919 Other Fuel Consumption (BBtu) 17,061 17,057 15,334 14,632 13,993 20,902 SO(2) Allowances Purchased (Tons)(6) 17 16 15 14 13 12 NO(X) Allowances Purchased (Tons)(7) (24) (29) (39) (45) (45) (53) COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) $ 35.25 36.09 39.18 43.51 45.82 32.99 Other Electricity Capacity ($/kW-yr) $ 67.11 70.80 73.36 74.99 78.33 69.62 Energy ($/MWh) $ 51.60 51.19 53.36 55.71 57.81 60.90 Fuel ($/MMBtu)(12) $ 4.49 4.62 4.81 5.02 5.22 5.45 SO(2) Allowances ($/Ton)(13) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(14) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues $ 75,619 76,488 75,534 74,859 75,898 16,327 Other Electricity Revenues Capacity Revenues $ 40,414 42,638 44,180 45,156 47,169 83,003 Energy Revenues $ 114,347 113,084 105,220 104,218 103,186 160,586 --------- --------- --------- --------- --------- --------- Total Operating Revenues $ 230,380 232,210 224,934 224,233 226,253 259,916 OPERATING EXPENSES ($000)(16) Fuel Costs $ 87,889 90,309 85,446 85,355 83,464 129,387 Purchased Power $ 2,773 2,759 2,589 2,460 2,431 0 Operating and Maintenance $ 25,239 25,720 24,956 24,604 24,915 24,366 Administrative and General $ 8,126 8,242 8,361 8,486 8,611 8,740 --------- --------- --------- --------- --------- --------- Total Operating Expenses $ 124,026 127,030 121,352 120,905 119,421 162,494 NET OPERATING REVENUES ($000) $ 106,354 105,180 103,582 103,328 106,832 97,422 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ --------- --------- --------- --------- HARRIS FACILITY - --------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,192 1,192 1,192 1,192 Average Annual Contract Capacity (MW) 0 0 0 0 Average Annual Other Capacity (MW) 1,192 1,192 1,192 1,192 Capacity Factor(%)(3) 27.9% 26.6% 25.5% 25.5% Energy Generation (GWh) 2,919 2,775 2,662 2,662 Contract Energy Sales (GWh) 0 0 0 0 Other Energy Sales (Purchases)(GWh) 2,919 2,775 2,662 2,662 Net Heat Rate (Btu/kWh)(5) 7,912 7,955 7,996 7,996 Contract Fuel Consumption (BBtu) 0 0 0 0 Other Fuel Consumption (BBtu) 23,096 22,077 21,285 21,285 SO(2) Allowances Purchased (Tons)(6) 12 11 11 11 NO(X) Allowances Purchased (Tons)(7) (54) (57) (58) (58) COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) 0.00 0.00 0.00 0.00 Other Electricity Capacity ($/kW-yr) 84.44 87.40 89.01 91.32 Energy ($/MWh) 63.37 64.34 66.57 68.30 Fuel ($/MMBtu)(12) 5.66 5.80 5.96 6.11 SO(2) Allowances ($/Ton)(13) 232 238 244 251 NO(X) Allowances ($/Ton)(14) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues 0 0 0 0 Other Electricity Revenues Capacity Revenues 100,678 104,212 106,125 108,883 Energy Revenues 184,979 178,553 177,212 181,819 --------- --------- --------- --------- Total Operating Revenues 285,657 282,765 283,337 290,702 OPERATING EXPENSES ($000)(16) Fuel Costs 149,382 146,630 145,457 148,754 Purchased Power 0 0 0 0 Operating and Maintenance 24,303 24,454 24,580 25,219 Administrative and General 8,873 9,008 9,148 9,290 --------- --------- --------- --------- Total Operating Expenses 182,557 180,092 179,184 183,262 NET OPERATING REVENUES ($000) 103,100 102,673 104,153 107,440
A-54 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 - ------------------------ ------- ------- ------- ------- ------- ------- McINTOSH FACILITY - ----------------- PERFORMANCE Average Annual Capacity (MW)(2) 0 0 1,190 1,190 1,190 1,190 Average Annual Contract Capacity (MW) 0 0 1,190 1,190 1,190 1,190 Average Annual Other Capacity (MW) 0 0 0 0 0 0 Capacity Factor(%)(3) 0.0% 0.0% 49.4% 46.8% 51.5% 52.6% Energy Generation (GWh) 0 0 3,005 4,877 5,371 5,484 Contract Energy Sales (GWh) 0 0 3,067 4,928 5,427 5,541 Other Energy Sales (Purchases)(GWh) 0 0 0 0 0 0 Net Heat Rate (Btu/kWh)(5) 0 0 7,604 7,666 7,545 7,552 Contract Fuel Consumption (BBtu) 0 0 22,848 37,387 40,521 41,419 Other Fuel Consumption (BBtu) 0 0 0 0 0 0 SO(2) Allowances Purchased (Tons)(6) 0 0 11 19 20 21 NO(X) Allowances Purchased (Tons)(7) 0 0 97 128 146 146 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) $ 0.00 0.00 28.47 26.45 22.74 22.98 Other Electricity Capacity ($/kW-yr) $ 0.00 0.00 0.00 0.00 0.00 0.00 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) $ 150 154 158 162 166 171 NO(X) Allowances ($/Ton)(14) $ 0 2,000 1,700 1,744 1,790 1,836 OPERATING REVENUES ($000) Contract Electricity Revenues $ 0 0 87,301 130,323 123,410 127,323 Other Electricity Revenues Capacity Revenues $ 0 0 0 0 0 0 Energy Revenues $ 0 0 0 0 0 0 ------- ------- ------- ------- ------- ------- Total Operating Revenues $ 0 0 87,301 130,323 123,410 127,323 OPERATING EXPENSES ($000)(16) Fuel Costs $ 0 0 0 0 0 0 Purchased Power $ 0 0 2,956 2,243 2,446 2,612 Operating and Maintenance $ 0 0 12,210 19,263 20,481 21,310 Administrative and General $ 0 0 2,428 4,266 4,378 4,490 ------- ------- ------- ------- ------- ------- Total Operating Expenses $ 0 0 17,594 25,772 27,305 28,412 NET OPERATING REVENUES ($000) $ 0 0 69,707 104,551 96,105 98,911 Year Ending December 31, 2009 2010 2011 2012 2013 - ------------------------ ------- ------- ------- ------- ------- McINTOSH FACILITY - ----------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,190 1,190 1,190 1,190 1,190 Average Annual Contract Capacity (MW) 1,190 1,190 1,190 1,190 1,190 Average Annual Other Capacity (MW) 0 0 0 0 0 Capacity Factor(%)(3) 52.8% 48.1% 50.4% 48.2% 43.7% Energy Generation (GWh) 5,500 5,011 5,257 5,023 4,558 Contract Energy Sales (GWh) 5,558 5,063 5,311 5,075 4,605 Other Energy Sales (Purchases)(GWh) 0 0 0 0 0 Net Heat Rate (Btu/kWh)(5) 7,495 7,559 7,520 7,526 7,647 Contract Fuel Consumption (BBtu) 41,226 37,876 39,531 37,803 34,853 Other Fuel Consumption (BBtu) 0 0 0 0 0 SO(2) Allowances Purchased (Tons)(6) 21 19 20 19 17 NO(X) Allowances Purchased (Tons)(7) 143 133 137 135 125 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) 21.91 24.91 24.06 25.21 30.03 Other Electricity Capacity ($/kW-yr) 0.00 0.00 0.00 0.00 0.00 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 ($/Ton)(13) 175 180 184 189 194 NO(X) Allowances ($/Ton)(14) 1,884 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues 121,774 126,117 127,802 127,964 138,295 Other Electricity Revenues Capacity Revenues 0 0 0 0 0 Energy Revenues 0 0 0 0 0 ------- ------- ------- ------- ------- Total Operating Revenues 121,774 126,117 127,802 127,964 138,295 OPERATING EXPENSES ($000)(16) Fuel Costs 0 0 0 0 0 Purchased Power 2,620 2,444 2,607 2,550 2,383 Operating and Maintenance 21,604 20,973 21,586 21,465 20,990 Administrative and General 4,604 4,726 4,844 4,970 5,096 ------- ------- ------- ------- ------- Total Operating Expenses 28,828 28,143 29,037 28,985 28,469 NET OPERATING REVENUES ($000) 92,946 97,974 98,765 98,979 109,826
A-55 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ------------------------ -------- -------- -------- -------- -------- -------- McINTOSH FACILITY - ----------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,190 1,190 1,190 1,190 1,190 1,190 Average Annual Contract Capacity (MW) 1,190 1,190 1,190 1,190 1,190 1,190 Average Annual Other Capacity (MW) 0 0 0 0 0 0 Capacity Factor(%)(3) 39.9% 37.3% 35.1% 32.2% 29.3% 29.3% Energy Generation (GWh) 4,163 3,892 3,663 3,359 3,050 3,050 Contract Energy Sales (GWh) 4,206 3,932 3,702 3,394 3,082 3,082 Other Energy Sales (Purchases)(GWh) 0 0 0 0 0 0 Net Heat Rate (Btu/kWh)(5) 7,718 7,746 7,800 7,841 7,880 7,900 Contract Fuel Consumption (BBtu) 32,127 30,144 28,573 26,340 24,031 24,092 Other Fuel Consumption (BBtu) 0 0 0 0 0 0 SO(2) Allowances Purchased (Tons)(6) 16 15 14 13 12 12 NO(X) Allowances Purchased (Tons)(7) 114 105 98 95 87 89 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) $ 33.54 35.94 39.39 43.15 46.41 48.17 Other Electricity Capacity ($/kW-yr) $ 0.00 0.00 0.00 0.00 0.00 0.00 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) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(14) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues $141,097 141,329 145,813 146,477 143,008 148,445 Other Electricity Revenues Capacity Revenues $ 0 0 0 0 0 0 Energy Revenues $ 0 0 0 0 0 0 -------- -------- -------- -------- -------- -------- Total Operating Revenues $141,097 141,329 145,813 146,477 143,008 148,445 OPERATING EXPENSES ($000)(16) Fuel Costs $ 0 0 0 0 0 0 Purchased Power $ 2,267 2,136 2,057 1,987 1,854 1,949 Operating and Maintenance $ 20,484 24,214 20,566 20,126 20,071 20,081 Administrative and General $ 5,226 5,364 5,498 5,640 5,786 5,936 -------- -------- -------- -------- -------- -------- Total Operating Expenses $ 27,977 31,714 28,121 27,753 27,711 27,966 NET OPERATING REVENUES ($000) $113,120 109,615 117,692 118,724 115,297 120,479 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ -------- -------- -------- -------- McINTOSH FACILITY - ----------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,190 1,190 1,190 1,190 Average Annual Contract Capacity (MW) 1,190 0 0 0 Average Annual Other Capacity (MW) 1,190 1,190 1,190 1,190 Capacity Factor(%)(3) 26.1% 25.8% 22.2% 22.2% Energy Generation (GWh) 2,725 2,691 2,317 2,317 Contract Energy Sales (GWh) 551 0 0 0 Other Energy Sales (Purchases)(GWh) 2,175 2,691 2,317 2,317 Net Heat Rate (Btu/kWh)(5) 7,909 7,970 7,969 7,969 Contract Fuel Consumption (BBtu) 4,356 0 0 0 Other Fuel Consumption (BBtu) 17,199 21,450 18,464 18,464 SO(2) Allowances Purchased (Tons)(6) 11 11 9 9 NO(X) Allowances Purchased (Tons)(7) 79 82 72 72 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) 50.29 0.00 0.00 0.00 Other Electricity Capacity ($/kW-yr) 67.55 87.40 89.01 91.32 Energy ($/MWh) 62.89 65.32 66.48 68.21 Fuel ($/MMBtu)(12) 5.67 5.79 5.97 6.12 SO(2) Allowances ($/Ton)(13) 232 238 244 251 NO(X) Allowances ($/Ton)(14) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues 27,698 0 0 0 Other Electricity Revenues Capacity Revenues 80,386 104,010 105,920 108,674 Energy Revenues 136,757 175,807 154,041 158,046 -------- -------- -------- -------- Total Operating Revenues 244,841 279,817 259,961 266,720 OPERATING EXPENSES ($000)(16) Fuel Costs 112,453 142,923 128,857 131,721 Purchased Power 0 0 0 0 Operating and Maintenance 19,870 24,739 19,685 38,198 Administrative and General 6,088 6,246 6,404 6,570 -------- -------- -------- -------- Total Operating Expenses 138,411 173,908 154,946 176,489 NET OPERATING REVENUES ($000) 106,429 105,909 105,015 90,231
A-56 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 - ------------------------ ------- ------- ------- ------- ------- ------- STANTON FACILITY - ---------------- PERFORMANCE Average Annual Capacity (MW)(2) 394 394 394 394 394 394 Average Annual Contract Capacity (MW) 404 404 404 404 404 404 Average Annual Other Capacity (MW) 0 0 0 0 0 0 Capacity Factor(%)(3) 36.6% 41.5% 33.7% 38.9% 40.5% 40.5% Energy Generation (GWh) 315 1,433 1,162 1,343 1,399 1,398 Contract Energy Sales (GWh) 330 1,534 1,244 1,438 1,497 1,497 Other Energy Sales (Purchases)(GWh) 0 0 0 0 0 0 Net Heat Rate (Btu/kWh)(5) 7,866 7,750 7,914 7,853 7,827 7,832 Contract Fuel Consumption (BBtu) 2,481 11,108 9,197 10,550 10,947 10,950 Other Fuel Consumption (BBtu) 0 0 0 0 0 0 SO(2) Allowances Purchased (Tons)(6) 1 6 5 5 5 5 NO(X) Allowances Purchased (Tons)(7) 0 0 0 0 0 0 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) $ 31.45 29.35 35.70 31.48 30.38 30.62 Other Electricity Capacity ($/kW-yr) $ 0.00 0.00 0.00 0.00 0.00 0.00 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) $ 150 154 158 162 166 171 NO(X) Allowances ($/Ton)(14) $ 0 2,000 1,700 1,744 1,790 1,836 OPERATING REVENUES ($000) Contract Electricity Revenues $10,374 45,040 44,420 45,276 45,484 45,836 Other Electricity Revenues Capacity Revenues $ 0 0 0 0 0 0 Energy Revenues $ 0 0 0 0 0 0 ------- ------- ------- ------- ------- ------- Total Operating Revenues $10,374 45,040 44,420 45,276 45,484 45,836 OPERATING EXPENSES ($000)(16) Fuel Costs $ 0 0 0 0 0 0 Purchased Power $ 769 5,142 4,309 4,772 4,992 5,205 Operating and Maintenance $ 1,627 7,128 6,515 7,216 7,573 7,765 Administrative and General $ 588 2,379 2,409 2,439 2,470 2,502 ------- ------- ------- ------- ------- ------- Total Operating Expenses $ 2,984 14,649 13,233 14,427 15,035 15,472 NET OPERATING REVENUES ($000) $ 7,390 30,392 31,187 30,848 30,450 30,364 Year Ending December 31, 2009 2010 2011 2012 2013 - ------------------------ ------- ------- ------- ------- ------- STANTON FACILITY - ---------------- PERFORMANCE Average Annual Capacity (MW)(2) 394 394 394 394 394 Average Annual Contract Capacity (MW) 404 404 404 404 404 Average Annual Other Capacity (MW) 0 0 0 0 394 Capacity Factor(%)(3) 37.2% 35.8% 33.6% 31.1% 30.0% Energy Generation (GWh) 1,283 1,236 1,159 1,074 1,036 Contract Energy Sales (GWh) 1,373 1,323 1,241 1,150 925 Other Energy Sales (Purchases)(GWh) 0 0 0 0 112 Net Heat Rate (Btu/kWh)(5) 7,934 8,020 8,011 8,070 8,086 Contract Fuel Consumption (BBtu) 10,177 9,911 9,287 8,669 7,476 Other Fuel Consumption (BBtu) 0 0 0 0 904 SO(2) Allowances Purchased (Tons)(6) 5 5 5 4 4 NO(X) Allowances Purchased (Tons)(7) 0 0 0 0 0 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) 33.55 35.19 37.45 40.53 42.74 Other Electricity Capacity ($/kW-yr) 0.00 0.00 0.00 0.00 7.83 Energy ($/MWh) 0.00 0.00 0.00 0.00 59.97 Fuel ($/MMBtu)(12) 0.00 0.00 0.00 0.00 4.65 SO(2) Allowances ($/Ton)(13) 175 180 184 189 194 NO(X) Allowances ($/Ton)(14) 1,884 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues 46,076 46,560 46,476 46,609 39,515 Other Electricity Revenues Capacity Revenues 0 0 0 0 3,086 Energy Revenues 0 0 0 0 6,704 ------- ------- ------- ------- ------- Total Operating Revenues 46,076 46,560 46,476 46,609 49,305 OPERATING EXPENSES ($000)(16) Fuel Costs 0 0 0 0 5,867 Purchased Power 4,894 4,799 4,645 4,516 0 Operating and Maintenance 7,631 7,640 7,598 7,462 7,520 Administrative and General 2,535 2,568 2,602 2,637 2,674 ------- ------- ------- ------- ------- Total Operating Expenses 15,060 15,007 14,845 14,615 16,061 NET OPERATING REVENUES ($000) 31,015 31,553 31,631 31,994 33,244
A-57 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ------------------------ ------- ------- ------- ------- ------- ------- STANTON FACILITY - ---------------- PERFORMANCE Average Annual Capacity (MW)(2) 394 394 394 394 394 394 Average Annual Contract Capacity (MW) 404 0 0 0 0 0 Average Annual Other Capacity (MW) 394 394 394 394 394 394 Capacity Factor(%)(3) 26.6% 26.1% 25.1% 23.7% 23.0% 20.4% Energy Generation (GWh) 919 900 867 819 792 704 Contract Energy Sales (GWh) 0 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 919 900 867 819 792 704 Net Heat Rate (Btu/kWh)(5) 8,183 8,164 8,244 8,232 8,282 8,387 Contract Fuel Consumption (BBtu) 0 0 0 0 0 0 Other Fuel Consumption (BBtu) 7,522 7,352 7,147 6,745 6,563 5,905 SO(2) Allowances Purchased (Tons)(6) 4 4 4 3 3 3 NO(X) Allowances Purchased (Tons)(7) 0 0 0 0 0 0 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 0.00 Other Electricity Capacity ($/kW-yr) $ 74.49 79.77 84.18 85.77 87.38 89.03 Energy ($/MWh) $ 61.18 61.36 63.26 66.22 66.93 71.03 Fuel ($/MMBtu)(12) $ 4.78 4.93 5.14 5.34 5.54 5.76 SO(2) Allowances ($/Ton)(13) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(14) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues $ 0 0 0 0 0 0 Other Electricity Revenues Capacity Revenues $29,351 31,429 33,167 33,792 34,427 35,078 Energy Revenues $56,235 55,257 54,841 54,263 53,037 50,006 ------- ------- ------- ------- ------- ------- Total Operating Revenues $85,586 86,686 88,008 88,055 87,464 85,084 OPERATING EXPENSES ($000)(16) Fuel Costs $51,374 51,636 52,163 51,430 51,765 49,421 Purchased Power $ 0 0 0 0 0 0 Operating and Maintenance $ 7,322 7,456 7,516 7,518 7,840 7,628 Administrative and General $ 2,711 2,749 2,788 2,828 2,869 2,912 ------- ------- ------- ------- ------- ------- Total Operating Expenses $61,407 61,841 62,468 61,776 62,474 59,961 NET OPERATING REVENUES ($000) $24,179 24,845 25,540 26,279 24,990 25,123 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ ------- ------- ------- ------- STANTON FACILITY - ---------------- PERFORMANCE Average Annual Capacity (MW)(2) 394 394 394 394 Average Annual Contract Capacity (MW) 0 0 0 0 Average Annual Other Capacity (MW) 394 394 394 394 Capacity Factor(%)(3) 20.5% 18.8% 18.7% 18.7% Energy Generation (GWh) 706 650 647 647 Contract Energy Sales (GWh) 0 0 0 0 Other Energy Sales (Purchases)(GWh) 706 650 647 647 Net Heat Rate (Btu/kWh)(5) 8,422 8,485 8,501 8,501 Contract Fuel Consumption (BBtu) 0 0 0 0 Other Fuel Consumption (BBtu) 5,944 5,514 5,500 5,500 SO(2) Allowances Purchased (Tons)(6) 3 3 3 3 NO(X) Allowances Purchased (Tons)(7) 0 0 0 0 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) 0.00 0.00 0.00 0.00 Other Electricity Capacity ($/kW-yr) 90.71 92.42 94.15 96.60 Energy ($/MWh) 72.18 73.90 75.29 77.25 Fuel ($/MMBtu)(12) 6.01 6.15 6.32 6.48 SO(2) Allowances ($/Ton)(13) 232 238 244 251 NO(X) Allowances ($/Ton)(14) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues 0 0 0 0 Other Electricity Revenues Capacity Revenues 35,740 36,412 37,096 38,060 Energy Revenues 50,947 48,025 48,712 49,979 ------- ------- ------- ------- Total Operating Revenues 86,687 84,437 85,808 88,039 OPERATING EXPENSES ($000)(16) Fuel Costs 51,114 49,309 50,143 51,047 Purchased Power 0 0 0 0 Operating and Maintenance 7,810 7,814 7,977 8,185 Administrative and General 2,955 2,999 3,045 3,092 ------- ------- ------- ------- Total Operating Expenses 61,879 60,123 61,166 62,324 NET OPERATING REVENUES ($000) 24,808 24,314 24,642 25,715
A-58 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 - ------------------------ ------- ------- ------- ------- ------- ------- WANSLEY FACILITY - ---------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,089 1,089 1,089 1,089 1,089 1,089 Average Annual Contract Capacity (MW) 1,089 1,089 1,089 1,089 1,089 1,089 Average Annual Other Capacity (MW) 0 0 0 0 0 0 Capacity Factor(%)(3) 43.2% 37.8% 44.4% 49.6% 55.6% 57.5% Energy Generation (GWh) 2,062 3,603 4,234 4,729 5,303 5,484 Contract Energy Sales (GWh) 2,115 3,696 4,343 4,851 5,440 5,625 Other Energy Sales (Purchases)(GWh) 0 0 0 0 0 0 Net Heat Rate (Btu/kWh)(5) 7,734 7,676 7,637 7,557 7,414 7,423 Contract Fuel Consumption (BBtu) 15,945 27,658 32,338 35,741 39,317 40,708 Other Fuel Consumption (BBtu) 0 0 0 0 0 0 SO(2) Allowances Purchased (Tons)(6) 8 14 16 18 20 20 NO(X) Allowances Purchased (Tons)(7) 0 0 119 132 144 146 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) $ 26.30 24.98 22.13 20.07 17.88 17.60 Other Electricity Capacity ($/kW-yr) $ 0.00 0.00 0.00 0.00 0.00 0.00 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) $ 150 154 158 162 166 171 NO(X) Allowances ($/Ton)(14) $ 0 2,000 1,700 1,744 1,790 1,836 OPERATING REVENUES ($000) Contract Electricity Revenues $55,624 92,339 96,116 97,366 97,269 99,010 Other Electricity Revenues Capacity Revenues $ 0 0 0 0 0 0 Energy Revenues $ 0 0 0 0 0 0 ------- ------- ------- ------- ------- ------- Total Operating Revenues $55,624 92,339 96,116 97,366 97,269 99,010 OPERATING EXPENSES ($000)(16) Fuel Costs $ 0 0 0 0 0 0 Purchased Power $ 2,760 4,328 4,918 5,286 5,778 6,206 Operating and Maintenance $ 8,880 17,335 19,416 21,396 24,762 25,988 Administrative and General $ 1,705 3,490 3,571 3,654 3,740 3,828 ------- ------- ------- ------- ------- ------- Total Operating Expenses $13,345 25,153 27,905 30,336 34,280 36,022 NET OPERATING REVENUES ($000) $42,279 67,186 68,211 67,030 62,989 62,988 Year Ending December 31, 2009 2010 2011 2012 2013 - ------------------------ ------- ------- ------- ------- ------- WANSLEY FACILITY - ---------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,089 1,089 1,089 1,089 1,089 Average Annual Contract Capacity (MW) 1,089 0 0 0 0 Average Annual Other Capacity (MW) 0 1,089 1,089 1,089 1,089 Capacity Factor(%)(3) 55.7% 55.6% 56.6% 53.9% 48.3% Energy Generation (GWh) 5,310 5,301 5,397 5,140 4,610 Contract Energy Sales (GWh) 5,446 0 0 0 0 Other Energy Sales (Purchases)(GWh) 0 5,301 5,397 5,140 4,610 Net Heat Rate (Btu/kWh)(5) 7,435 7,434 7,341 7,434 7,490 Contract Fuel Consumption (BBtu) 39,475 0 0 0 0 Other Fuel Consumption (BBtu) 0 39,403 39,617 38,208 34,530 SO(2) Allowances Purchased (Tons)(6) 20 20 20 19 17 NO(X) Allowances Purchased (Tons)(7) 142 139 140 134 127 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) 18.27 0.00 0.00 0.00 0.00 Other Electricity Capacity ($/kW-yr) 0.00 46.49 58.16 62.97 67.51 Energy ($/MWh) 0.00 44.60 45.63 47.19 48.16 Fuel ($/MMBtu)(12) 0.00 3.98 4.10 4.23 4.35 SO(2) Allowances ($/Ton)(13) 175 180 184 189 194 NO(X) Allowances ($/Ton)(14) 1,884 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues 99,498 0 0 0 0 Other Electricity Revenues Capacity Revenues 0 50,631 63,337 68,580 73,520 Energy Revenues 0 236,432 246,265 242,556 222,046 ------- ------- ------- ------- ------- Total Operating Revenues 99,498 287,063 309,602 311,136 295,566 OPERATING EXPENSES ($000)(16) Fuel Costs 0 176,261 182,099 180,998 169,780 Purchased Power 6,155 0 0 0 0 Operating and Maintenance 26,471 27,499 28,904 28,554 27,450 Administrative and General 3,918 4,011 4,105 4,203 4,302 ------- ------- ------- ------- ------- Total Operating Expenses 36,544 207,771 215,108 213,756 201,533 NET OPERATING REVENUES ($000) 62,954 79,292 94,494 97,380 94,033
A-59 EXHIBIT A-1 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ------------------------ -------- -------- -------- -------- -------- -------- WANSLEY FACILITY - ---------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,089 1,089 1,089 1,089 1,089 1,089 Average Annual Contract Capacity (MW) 0 0 0 0 0 0 Average Annual Other Capacity (MW) 1,089 1,089 1,089 1,089 1,089 1,089 Capacity Factor(%)(3) 44.1% 42.9% 37.5% 35.4% 32.2% 29.6% Energy Generation (GWh) 4,212 4,094 3,578 3,379 3,075 2,821 Contract Energy Sales (GWh) 0 0 0 0 0 0 Other Energy Sales (Purchases)(GWh) 4,212 4,094 3,578 3,379 3,075 2,821 Net Heat Rate (Btu/kWh)(5) 7,575 7,584 7,698 7,736 7,801 7,819 Contract Fuel Consumption (BBtu) 0 0 0 0 0 0 Other Fuel Consumption (BBtu) 31,904 31,050 27,542 26,137 23,991 22,062 SO(2) Allowances Purchased (Tons)(6) 16 16 14 13 12 11 NO(X) Allowances Purchased (Tons)(7) 117 111 94 90 84 80 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 0.00 Other Electricity Capacity ($/kW-yr) $ 67.11 70.80 73.36 74.99 78.33 82.55 Energy ($/MWh) $ 49.74 49.88 52.28 55.14 56.99 60.38 Fuel ($/MMBtu)(12) $ 4.48 4.62 4.81 5.01 5.23 5.44 SO(2) Allowances ($/Ton)(13) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(14) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues $ 0 0 0 0 0 0 Other Electricity Revenues Capacity Revenues $ 73,090 77,112 79,901 81,667 85,306 89,910 Energy Revenues $209,492 204,217 187,072 186,280 175,249 170,365 -------- -------- -------- -------- -------- -------- Total Operating Revenues $282,582 281,329 266,973 267,947 260,555 260,275 OPERATING EXPENSES ($000)(16) Fuel Costs $162,611 162,635 149,621 146,902 140,054 134,564 Purchased Power $ 0 0 0 0 0 0 Operating and Maintenance $ 26,558 26,924 25,520 25,389 24,855 24,260 Administrative and General $ 4,404 4,510 4,618 4,728 4,842 4,958 -------- -------- -------- -------- -------- -------- Total Operating Expenses $193,574 194,069 179,758 177,019 169,750 163,782 NET OPERATING REVENUES ($000) $ 89,008 87,260 87,215 90,928 90,805 96,493 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ -------- -------- -------- -------- WANSLEY FACILITY - ---------------- PERFORMANCE Average Annual Capacity (MW)(2) 1,089 1,089 1,089 1,089 Average Annual Contract Capacity (MW) 0 0 0 0 Average Annual Other Capacity (MW) 1,089 1,089 1,089 1,089 Capacity Factor(%)(3) 27.8% 26.5% 25.4% 25.4% Energy Generation (GWh) 2,656 2,527 2,419 2,419 Contract Energy Sales (GWh) 0 0 0 0 Other Energy Sales (Purchases)(GWh) 2,656 2,527 2,419 2,419 Net Heat Rate (Btu/kWh)(5) 7,902 7,948 7,933 7,933 Contract Fuel Consumption (BBtu) 0 0 0 0 Other Fuel Consumption (BBtu) 20,990 20,081 19,191 19,191 SO(2) Allowances Purchased (Tons)(6) 10 10 10 10 NO(X) Allowances Purchased (Tons)(7) 77 72 74 74 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity ($/MWh) 0.00 0.00 0.00 0.00 Other Electricity Capacity ($/kW-yr) 84.44 87.40 89.01 91.32 Energy ($/MWh) 62.47 64.09 65.16 66.86 Fuel ($/MMBtu)(12) 5.67 5.81 5.94 6.09 SO(2) Allowances ($/Ton)(13) 232 238 244 251 NO(X) Allowances ($/Ton)(14) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues 0 0 0 0 Other Electricity Revenues Capacity Revenues 91,964 95,192 96,939 99,459 Energy Revenues 165,960 161,941 157,628 161,727 -------- -------- -------- -------- Total Operating Revenues 257,924 257,133 254,567 261,186 OPERATING EXPENSES ($000)(16) Fuel Costs 133,575 131,388 128,651 131,615 Purchased Power 0 0 0 0 Operating and Maintenance 24,231 24,283 24,456 25,092 Administrative and General 5,077 5,200 5,326 5,455 -------- -------- -------- -------- Total Operating Expenses 162,882 160,871 158,433 162,162 NET OPERATING REVENUES ($000) 95,042 96,262 96,134 99,024
A-60 FOOTNOTES TO EXHIBIT A-1 1. Represents six months for the year 2003. 2. Represents annual average capacity for the Generating Facilities, including allowance for degradation. Reflects three months of operation of the Stanton Facility in 2003 and seven months of operation of the McIntosh Facility in 2005. 3. Represents annual weighted average capacity factors of the Generating Facilities as projected by PA Consulting. 4. Energy sales both contractual and other are as projected by PA Consulting. Other sales assumed to be representative of long-term contracts Southern Power expects to enter into upon expiration of the PPAs. 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 can sell based on emission rates as provided by Southern Power and dispatch as projected by PA Consulting. During the term of the PPAs, we have assumed that any shortfall in emissions would be provided by the buyer of the generation. Upon expiration of the PPAs, 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 terms of the PPAs, we have assumed that any shortfall in emissions would be provided by the buyer of the generation. Upon expiration of the PPAs, 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 2.6 percent per year for the term of the Debt, based on the March 10, 2003 projection prepared by Blue Chip Economic Indicators. 9. Average contract electricity price calculated as the sum of the electricity revenues under the PPAs divided by the total annual contractual energy from the various PPAs. 10. 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 in 2001 dollars and adjusted for inflation. Assumed to be equivalent to the price of long-term contracts to be entered into by Southern Power upon expiration of the PPAs. Shown as zero in years during which there are no other capacity or energy sales. 11. 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 in 2001 dollars and adjusted for inflation. Shown as zero in years during which there are no fuel purchases. 12. Assumed to be $150 per ton in 2003 escalating thereafter at the assumed rate of inflation. 13. Assumed to be $2,000 per ton in 2004, $1,700 per ton in 2005, and escalating thereafter at the assumed rate of inflation. 14. Assumes contract sales to third parties in 2003 as reported by Southern Power for the Franklin Facility prior to commencement of the Franklin PPA and market energy sales as estimated by PA Consulting for Harris 2 prior to the commencement of the Harris 2 PPA. 15. In order to maximize the capacity payments under the PPAs, Southern Power has indicated that it will provide replacement energy from alternate sources. Purchases power has been assumed to be available at the market prices projected by PA Consulting. 16. Operating and maintenance includes fixed and variable operations and maintenance expense, the cost of emissions allowances, balance of plant major maintenance costs, and LTSA expenses. These expenses have been estimated by Southern Power and have been assumed to escalate at the rate of inflation. 17. Administrative and general expenses include administrative expense, insurance costs, property taxes and other costs. These expenses have been estimated by Southern Power and have been assumed to escalate at the rate of inflation. 18. Interest payments on the Debt are based on semi-annual payments due each July 15 and January 15. Interest has been included on the principal amount of the Senior Notes of $575,000,000 at an interest rate of 4.875 percent per year beginning January 15, 2004, as reported by the Representatives of the Initial Purchasers. Interest has been included on the principal amount of Short-Term Notes of $100,000,000 at an interest rate of 4.875 percent per year, 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. The scheduled amortization of the 2002 Notes consists of a single payment due on July 15, 2012. The scheduled amortization of the Senior Notes consists of a single payment due on July 15, 2015. Includes an additional $384,000,000 of Debt assumed to be issued July 1, 2005 at an interest rate of 7.50 percent per year, as estimated by the Representatives of the Initial Purchasers. Southern Power has assumed that the Debt will be refinanced upon maturity at the same principal amounts and respective interest rates, as estimated by the Representatives of the Initial Purchasers. No additional costs of issuance have been included. No principal amortization of the Debt has been assumed. 19. Interest coverage is equal to the net operating revenue divided by the interest on the Debt. 20. Average interest coverage is equal to the total net operating revenues over the term of the Senior Notes ending July 15, 2015 divided by the total interest on the Debt over the same period. A-61 EXHIBIT A-2 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY A - LOW FUEL MARKET PRICE SCENARIO
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 - ------------------------ --------- --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 31.8% 32.9% 34.7% 43.0% 50.0% 51.0% Contract Energy Sales (GWh)(4) 6,054 12,753 18,124 22,369 25,987 26,437 Other Energy Sales (GWh)(4) 1,130 836 0 27 40 90 Total Energy Sales (GWh) 7,184 13,589 18,124 22,396 26,027 26,527 Fuel Consumption (BBtu) 49,603 101,938 134,077 165,254 187,783 191,932 Average Net Heat Rate (Btu/kWh)(5) 7,711 7,672 7,600 7,557 7,389 7,408 SO(2) Allowances Purchased (Tons)(6) 25 52 67 82 94 96 NO(X) Allowances Purchased (Tons)(7) 0 (42) 225 292 369 381 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 33.32 30.94 26.46 23.26 19.50 19.47 Other Capacity Price ($/MWh)(10) $ 16.91 19.42 16.99 17.40 17.17 19.58 Other Energy Price ($/MWh)(10) $ 47.49 43.43 0.00 59.55 54.10 59.11 Fuel Price ($/MMBtu)(11) $ 4.83 4.40 0.00 3.33 3.17 3.27 SO(2) Allowances ($/Ton)(12) $ 150 154 158 162 166 171 NO(X) Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 16,642 34,138 0 0 0 0 Franklin (14) $ 82,732 109,109 115,884 120,185 120,739 123,521 Harris (14) $ 36,279 114,049 139,098 141,041 133,219 135,058 McIntosh $ 0 0 85,224 118,096 111,889 113,347 Stanton $ 10,373 44,575 44,330 45,062 45,012 45,414 Wansley $ 55,671 92,742 95,085 95,959 95,871 97,265 Other Electricity Revenues Dahlberg $ 2,220 4,643 13,540 15,463 15,835 20,952 Franklin (14) $ 3,126 12,173 0 0 0 0 Harris $ 57,542 29,372 0 0 0 0 McIntosh $ 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 --------- --------- --------- --------- --------- --------- Total Operating Revenues $ 264,585 440,801 493,161 535,806 522,565 535,557 OPERATING EXPENSES ($000) Fuel Dahlberg $ 33 0 0 1,169 1,641 3,852 Franklin $ 1,137 8,103 0 0 0 0 Harris $ 41,244 20,381 0 0 0 0 McIntosh $ 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Purchased Power (15) $ 39,344 13,039 20,417 21,329 23,977 25,653 Operations & Maintenance (16) $ 33,305 64,562 82,086 98,189 111,764 118,231 Administration and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873 --------- --------- --------- --------- --------- --------- Total Operating Expenses $ 127,792 133,050 132,237 152,608 169,773 180,609 NET OPERATING REVENUES ($000) $ 136,793 307,750 360,923 383,198 352,792 354,948 ANNUAL INTEREST($000)(18) $ 34,422 68,844 83,244 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 3.97 4.47 4.34 3.92 3.61 3.64 2003-15 AVG INTEREST COVERAGE (20) 4.23 Year Ending December 31, 2009 2010 2011 2012 2013 - ------------------------ --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 49.5% 48.4% 49.6% 46.2% 41.8% Contract Energy Sales (GWh)(4) 25,644 14,872 11,781 10,016 8,860 Other Energy Sales (GWh)(4) 109 10,047 13,672 13,669 12,512 Total Energy Sales (GWh) 25,753 24,919 25,453 23,685 21,371 Fuel Consumption (BBtu) 186,593 182,980 186,449 174,575 160,355 Average Net Heat Rate (Btu/kWh)(5) 7,418 7,433 7,395 7,440 7,545 SO(2) Allowances Purchased (Tons)(6) 95 93 93 88 81 NO(X) Allowances Purchased (Tons)(7) 355 344 353 320 279 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 20.05 21.91 21.36 23.08 26.66 Other Capacity Price ($/MWh)(10) 39.76 46.38 58.63 64.47 66.77 Other Energy Price ($/MWh)(10) 61.14 40.75 41.96 43.50 45.36 Fuel Price ($/MMBtu)(11) 3.37 3.95 4.08 4.22 4.40 SO(2) Allowances ($/Ton)(12) 175 180 184 189 194 NO(X) Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Franklin (14) 122,092 80,069 22,896 0 0 Harris (14) 134,504 86,468 69,543 69,333 72,923 McIntosh 113,135 112,887 112,308 115,168 123,656 Stanton 46,213 46,471 46,868 46,634 39,616 Wansley 98,288 0 0 0 0 Other Electricity Revenues Dahlberg 38,374 44,743 57,071 59,057 59,317 Franklin (14) 0 84,793 232,181 280,814 274,594 Harris 0 107,005 171,364 167,391 166,149 McIntosh 0 0 0 0 0 Stanton 0 0 0 0 9,915 Wansley 0 296,542 314,689 321,254 302,982 --------- --------- --------- --------- --------- Total Operating Revenues 552,606 858,978 1,026,920 1,059,651 1,049,152 OPERATING EXPENSES ($000) Fuel Dahlberg 4,787 5,832 7,605 5,568 4,224 Franklin 0 47,471 124,826 148,146 143,651 Harris 0 62,360 97,978 92,810 92,031 McIntosh 0 0 0 0 0 Stanton 0 0 0 0 5,853 Wansley 0 177,437 181,835 182,555 169,083 Purchased Power (15) 25,217 13,499 10,958 10,453 5,389 Operations & Maintenance (16) 120,453 125,129 129,666 126,028 124,883 Administration and General (17) 33,364 33,872 34,386 34,924 35,465 --------- --------- --------- --------- --------- Total Operating Expenses 183,821 465,601 587,255 600,484 580,579 NET OPERATING REVENUES ($000) 368,785 393,378 439,665 459,167 468,574 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 3.78 4.03 4.50 4.70 4.80 2003-15 AVG INTEREST COVERAGE (20)
A-62 EXHIBIT A-2 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY A - LOW FUEL MARKET PRICE SCENARIO
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ------------------------ ---------- ---------- ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 38.9% 36.2% 32.1% 30.0% 28.5% 26.4% Contract Energy Sales (GWh)(4) 7,522 6,962 6,157 5,773 5,552 4,049 Other Energy Sales (GWh)(4) 12,372 11,527 10,266 9,555 9,022 9,379 ---------- --------- --------- --------- --------- --------- Total Energy Sales (GWh) 19,893 18,489 16,423 15,328 14,574 13,428 Fuel Consumption (BBtu) 149,925 140,040 126,140 118,353 113,040 104,994 Average Net Heat Rate (Btu/kWh)(5) 7,580 7,618 7,726 7,766 7,802 7,840 SO(2) Allowances Purchased (Tons)(6) 73 69 63 59 57 53 NO(X) Allowances Purchased (Tons)(7) 245 212 164 130 114 103 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 26.78 28.92 34.69 36.93 39.66 40.25 Other Capacity Price ($/MWh)(10) $ 68.74 72.86 74.82 77.65 82.06 84.68 Other Energy Price ($/MWh)(10) $ 47.20 47.65 50.43 51.73 53.21 55.74 Fuel Price ($/MMBtu)(11) $ 4.69 4.86 5.10 5.31 5.46 5.67 SO(2) Allowances ($/Ton)(12) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 0 Franklin (14) $ 0 0 0 0 0 0 Harris (14) $ 72,345 73,483 75,455 74,414 76,660 16,401 McIntosh $ 129,106 127,834 138,116 138,806 143,554 146,579 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 57,896 59,465 60,736 61,843 64,942 67,709 Franklin (14) $ 262,420 250,941 239,089 230,686 231,792 230,042 Harris $ 159,844 158,443 153,603 150,128 153,100 245,144 McIntosh $ 0 0 0 0 0 0 Stanton $ 88,411 86,524 89,755 91,538 88,806 88,640 Wansley $ 291,865 286,945 275,388 272,348 271,391 266,018 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Revenues $1,061,887 1,043,635 1,032,142 1,019,763 1,030,245 1,060,533 OPERATING EXPENSES ($000) Fuel Dahlberg $ 2,215 1,341 1,297 458 0 401 Franklin $ 135,391 128,282 119,272 113,497 108,708 104,220 Harris $ 88,410 88,622 84,287 83,324 82,547 126,063 McIntosh $ 0 0 0 0 0 0 Stanton $ 52,874 50,261 51,676 52,439 51,357 50,984 Wansley $ 162,937 160,016 148,545 145,328 142,477 135,835 Purchased Power (15) $ 5,303 5,003 4,705 4,439 4,423 1,976 Operations & Maintenance (16) $ 118,504 115,360 111,908 110,260 114,456 124,837 Administration and General (17) $ 36,022 36,601 37,186 37,792 38,416 39,052 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Expenses $ 601,656 585,487 558,876 547,537 542,385 583,369 NET OPERATING REVENUES ($000) $ 460,231 458,148 473,266 472,226 487,860 477,164 ANNUAL INTEREST($000)(18) $ 97,644 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.71 4.69 4.85 4.84 5.00 4.89 2003-15 AVG INTEREST COVERAGE (20) 4.23 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 24.1% 22.6% 21.5% 21.5% Contract Energy Sales (GWh)(4) 629 0 0 0 Other Energy Sales (GWh)(4) 11,641 11,487 10,919 10,919 ---------- ---------- ---------- ---------- Total Energy Sales (GWh) 12,270 11,487 10,919 10,919 Fuel Consumption (BBtu) 96,881 91,272 86,883 86,883 Average Net Heat Rate (Btu/kWh)(5) 7,896 7,945 7,957 7,957 SO(2) Allowances Purchased (Tons)(6) 48 46 43 43 NO(X) Allowances Purchased (Tons)(7) 64 57 47 47 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 44.69 0.00 0.00 0.00 Other Capacity Price ($/MWh)(10) 86.16 87.74 89.36 91.68 Other Energy Price ($/MWh)(10) 57.69 59.33 60.43 62.00 Fuel Price ($/MMBtu)(11) 5.89 6.07 6.24 6.37 SO(2) Allowances ($/Ton)(12) 232 238 244 251 NO(X) Allowances ($/Ton)(13) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Franklin (14) 0 0 0 0 Harris (14) 0 0 0 0 McIntosh 28,102 0 0 0 Stanton 0 0 0 0 Wansley 0 0 0 0 Other Electricity Revenues Dahlberg 69,103 69,683 70,940 72,784 Franklin (14) 215,531 220,156 202,691 207,961 Harris 292,093 285,628 287,713 295,192 McIntosh 221,487 276,155 267,296 274,246 Stanton 88,566 86,042 88,643 90,947 Wansley 264,221 252,991 260,978 267,763 ---------- ---------- ---------- ---------- Total Operating Revenues 1,179,103 1,190,655 1,178,261 1,208,893 OPERATING EXPENSES ($000) Fuel Dahlberg 471 20 0 0 Franklin 93,729 96,113 82,574 84,261 Harris 150,243 145,923 146,140 149,455 McIntosh 112,354 137,421 132,151 135,100 Stanton 50,537 48,789 50,359 51,268 Wansley 134,330 125,305 130,498 133,510 Purchased Power (15) 0 0 0 0 Operations & Maintenance (16) 106,269 105,320 106,268 109,258 Administration and General (17) 39,705 40,375 41,060 41,768 ---------- ---------- ---------- ---------- Total Operating Expenses 687,637 699,265 689,049 704,619 NET OPERATING REVENUES ($000) 491,466 491,390 489,212 504,274 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 5.03 5.03 5.01 5.16 2003-15 AVG INTEREST COVERAGE (20)
A-63 FOOTNOTES TO EXHIBIT A-2 The footnotes to Exhibit A-2 are the same as the footnotes for Exhibit A-1, except: 3. Capacity factor as estimated by PA Consulting under its "Low Gas Price" scenario. 10. As estimated by PA Consulting in its "Low Gas Price" scenario. 11. As estimated by PA Consulting in its "Low Gas Price" scenario. A-64 EXHIBIT A-3 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY B - HIGH FUEL MARKET PRICE SCENARIO
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 - ------------------------ --------- --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE - ----------- Annual Average Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 31.0% 27.7% 29.2% 35.8% 40.7% 41.9% Contract Energy Sales (GWh)(4) 5,894 10,729 15,261 18,639 21,180 21,761 Other Energy Sales (GWh)(4) 1,103 721 0 1 25 54 --------- --------- --------- --------- --------- --------- Total Energy Sales (GWh) 6,997 11,450 15,261 18,640 21,205 21,815 Fuel Consumption (BBtu) 48,291 87,948 115,730 141,456 158,669 163,034 Average Net Heat Rate (Btu/kWh)(5) 7,709 7,858 7,792 7,774 7,664 7,654 SO(2) Allowances Purchased (Tons)(6) 24 44 57 70 78 81 NO(X) Allowances Purchased (Tons)(7) 0 (87) 114 168 253 272 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 35.23 37.11 32.25 29.42 25.85 25.45 Other Capacity Price ($/MWh)(10) $ 16.91 18.77 16.99 19.28 16.95 18.85 Other Energy Price ($/MWh)(10) $ 58.07 54.29 0.00 77.43 74.45 74.66 Fuel Price ($/MMBtu)(11) $ 5.93 5.52 0.00 4.17 3.98 4.10 SO(2) Allowances ($/Ton)(12) $ 150 154 158 162 166 171 NO(X) Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 16,638 34,138 0 0 0 0 Franklin (14) $ 88,652 108,851 115,376 120,985 124,041 123,701 Harris (14) $ 36,150 116,316 145,693 149,122 147,086 148,231 McIntosh $ 0 0 90,332 135,335 132,400 135,677 Stanton $ 10,466 45,636 44,902 45,339 45,838 46,278 Wansley $ 55,734 93,179 95,904 97,532 98,104 99,920 Other Electricity Revenues Dahlberg $ 2,235 4,488 13,540 15,479 15,377 19,089 Franklin (14) $ 3,546 13,062 0 0 0 0 Harris $ 67,478 31,120 0 0 0 0 McIntosh $ 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 --------- --------- --------- --------- --------- --------- Total Operating Revenues $ 280,899 446,790 505,747 563,792 562,846 572,896 OPERATING EXPENSES ($000) Fuel Dahlberg $ 42 0 0 75 1,295 2,910 Franklin $ 1,465 9,041 0 0 0 0 Harris $ 49,304 22,259 0 0 0 0 McIntosh $ 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Purchased Power (15) $ 46,792 14,027 21,668 22,810 25,324 27,175 Operations & Maintenance (16) $ 33,001 58,717 74,736 87,203 97,949 103,330 Administration and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873 --------- --------- --------- --------- --------- --------- Total Operating Expenses $ 143,333 131,010 126,138 142,009 156,959 166,288 NET OPERATING REVENUES ($000) $ 137,566 315,780 379,609 421,784 405,887 406,609 ANNUAL INTEREST($000)(18) $ 34,422 68,844 83,244 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.00 4.59 4.56 4.32 4.16 4.16 2003-15 AVG INTEREST COVERAGE (20) 4.47 Year Ending December 31, 2009 2010 2011 2012 2013 - ------------------------ --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE - ----------- Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 41.0% 37.5% 38.4% 36.4% 33.5% Contract Energy Sales (GWh)(4) 21,255 11,821 9,189 8,141 7,330 Other Energy Sales (GWh)(4) 74 7,460 10,531 10,533 9,785 --------- --------- --------- --------- --------- Total Energy Sales (GWh) 21,329 19,281 19,719 18,674 17,115 Fuel Consumption (BBtu) 159,541 146,825 149,868 142,032 131,940 Average Net Heat Rate (Btu/kWh)(5) 7,658 7,712 7,674 7,681 7,753 SO(2) Allowances Purchased (Tons)(6) 80 74 74 69 65 NO(X) Allowances Purchased (Tons)(7) 252 198 219 201 167 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 25.94 30.01 31.36 31.32 35.39 Other Capacity Price ($/MWh)(10) 29.83 45.82 54.61 60.52 64.84 Other Energy Price ($/MWh)(10) 85.76 51.60 53.06 54.50 55.68 Fuel Price ($/MMBtu)(11) 4.23 5.04 5.18 5.37 5.59 SO(2) Allowances ($/Ton)(12) 175 180 184 189 194 NO(X) Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Franklin (14) 125,333 81,771 26,446 0 0 Harris (14) 148,570 91,202 76,143 75,343 75,602 McIntosh 131,497 135,112 139,245 132,778 144,149 Stanton 46,137 46,647 46,310 46,840 39,657 Wansley 99,767 0 0 0 0 Other Electricity Revenues Dahlberg 30,104 37,549 49,907 51,355 53,722 Franklin (14) 0 81,608 223,846 267,121 255,957 Harris 0 107,545 166,117 166,614 165,580 McIntosh 0 0 0 0 0 Stanton 0 0 0 0 10,080 Wansley 0 280,465 306,660 308,552 296,429 --------- --------- --------- --------- --------- Total Operating Revenues 581,408 861,899 1,034,674 1,048,603 1,041,176 OPERATING EXPENSES ($000) Fuel Dahlberg 4,080 775 4,877 2,218 1,485 Franklin 0 47,895 127,085 148,523 140,527 Harris 0 65,428 99,828 98,965 98,558 McIntosh 0 0 0 0 0 Stanton 0 0 0 0 6,220 Wansley 0 173,932 186,007 184,902 176,282 Purchased Power (15) 26,832 13,433 10,735 10,604 5,431 Operations & Maintenance (16) 105,517 100,656 107,448 105,392 105,518 Administration and General (17) 33,364 33,872 34,386 34,924 35,465 --------- --------- --------- --------- --------- Total Operating Expenses 169,793 435,991 570,366 585,529 569,487 NET OPERATING REVENUES ($000) 411,615 425,908 464,308 463,073 471,689 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.22 4.36 4.76 4.74 4.83 2003-15 AVG INTEREST COVERAGE (20)
A-65 EXHIBIT A-3 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY B - HIGH FUEL MARKET PRICE SCENARIO
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ------------------------ ---------- ---------- ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 29.9% 27.6% 25.7% 23.9% 21.6% 20.5% ---------- ---------- ---------- ---------- ---------- ---------- Contract Energy Sales (GWh)(4) 5,805 5,399 5,051 4,658 4,059 3,260 Other Energy Sales (GWh)(4) 9,503 8,687 8,093 7,580 6,978 7,191 ---------- ---------- ---------- ---------- ---------- ---------- Total Energy Sales (GWh) 15,308 14,086 13,144 12,238 11,037 10,451 Fuel Consumption (BBtu) 118,813 109,707 102,992 96,274 87,163 83,229 Average Net Heat Rate (Btu/kWh)(5) 7,806 7,835 7,883 7,913 7,943 7,986 SO(2) Allowances Purchased (Tons)(6) 60 56 51 48 43 42 NO(X) Allowances Purchased (Tons)(7) 135 96 74 53 43 34 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 37.70 40.75 43.70 46.76 51.17 49.85 Other Capacity Price ($/MWh)(10) $ 67.86 68.95 71.80 74.57 77.90 78.67 Other Energy Price ($/MWh)(10) $ 57.81 59.38 61.10 63.25 65.69 69.89 Fuel Price ($/MMBtu)(11) $ 5.97 6.20 6.47 6.73 6.94 7.20 SO(2) Allowances ($/Ton)(12) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 0 Franklin (14) $ 0 0 0 0 0 0 Harris (14) $ 76,189 75,949 75,626 74,376 73,063 16,026 McIntosh $ 142,671 144,038 145,113 143,433 134,634 146,494 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 54,445 54,216 56,270 58,466 61,268 61,924 Franklin (14) $ 246,117 230,727 227,466 217,254 214,230 212,743 Harris $ 152,410 151,244 148,916 146,806 145,134 238,972 McIntosh $ 0 0 0 0 0 0 Stanton $ 86,925 84,675 88,791 90,137 88,963 87,973 Wansley $ 282,383 272,278 261,721 266,698 262,088 249,231 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Revenues $1,041,140 1,013,127 1,003,903 997,170 979,380 1,013,363 OPERATING EXPENSES ($000) Fuel Dahlberg $ 746 0 0 0 0 0 Franklin $ 133,598 122,154 121,291 112,592 104,903 99,715 Harris $ 88,494 89,336 87,480 86,349 81,038 131,056 McIntosh $ 0 0 0 0 0 0 Stanton $ 53,255 51,458 54,236 54,288 54,338 52,517 Wansley $ 167,421 160,026 150,449 151,467 145,107 131,777 Purchased Power (15) $ 5,023 4,871 4,659 4,450 4,102 1,976 Operations & Maintenance (16) $ 100,460 98,045 102,019 97,914 96,443 95,782 Administration and General (17) $ 36,022 36,601 37,186 37,792 38,416 39,052 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Expenses $ 585,019 562,492 557,319 544,852 524,348 551,875 NET OPERATING REVENUES ($000) $ 456,121 450,635 446,584 452,318 455,032 461,488 ANNUAL INTEREST($000)(18) $ 97,644 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.67 4.62 4.57 4.63 4.66 4.73 2003-15 AVG INTEREST COVERAGE (20) 4.47 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ --------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 18.6% 17.4% 16.0% 16.0% Contract Energy Sales (GWh)(4) 472 0 0 0 Other Energy Sales (GWh)(4) 8,986 8,819 8,145 8,145 --------- ---------- ---------- ---------- Total Energy Sales (GWh) 9,458 8,819 8,145 8,145 Fuel Consumption (BBtu) 75,749 70,859 65,626 65,626 Average Net Heat Rate (Btu/kWh)(5) 8,009 8,035 8,058 8,058 SO(2) Allowances Purchased (Tons)(6) 38 36 33 33 NO(X) Allowances Purchased (Tons)(7) 11 2 (10) (10) COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 56.53 0.00 0.00 0.00 Other Capacity Price ($/MWh)(10) 80.18 86.61 89.36 91.68 Other Energy Price ($/MWh)(10) 72.01 73.29 75.12 77.07 Fuel Price ($/MMBtu)(11) 7.49 7.72 7.96 8.13 SO(2) Allowances ($/Ton)(12) 232 238 244 251 NO(X) Allowances ($/Ton)(13) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Franklin (14) 0 0 0 0 Harris (14) 0 0 0 0 McIntosh 26,677 0 0 0 Stanton 0 0 0 0 Wansley 0 0 0 0 Other Electricity Revenues Dahlberg 63,288 68,689 70,940 72,784 Franklin (14) 196,652 204,281 186,701 191,555 Harris 288,563 276,406 282,400 289,741 McIntosh 207,099 271,060 257,909 264,615 Stanton 89,150 85,329 88,197 90,489 Wansley 248,571 243,037 244,102 250,448 ---------- ---------- ---------- ---------- Total Operating Revenues 1,120,000 1,148,802 1,130,249 1,159,632 OPERATING EXPENSES ($000) Fuel Dahlberg 0 0 0 0 Franklin 88,464 88,534 74,531 76,009 Harris 157,176 145,028 146,093 149,407 McIntosh 108,944 139,304 128,723 131,583 Stanton 53,241 50,540 52,658 53,626 Wansley 131,272 123,315 120,472 123,224 Purchased Power (15) 0 0 0 0 Operations & Maintenance (16) 95,380 94,632 99,557 97,427 Administration and General (17) 39,705 40,375 41,060 41,768 ---------- ---------- ---------- ---------- Total Operating Expenses 674,182 681,728 663,093 673,044 NET OPERATING REVENUES ($000) 445,818 467,074 467,156 486,588 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.57 4.78 4.78 4.98 2003-15 AVG INTEREST COVERAGE (20)
A-66 FOOTNOTES TO EXHIBIT A-3 The footnotes to Exhibit A-3 are the same as the footnotes for Exhibit A-1, except: 3. Capacity factor as estimated by PA Consulting under its "High Gas Price" scenario. 10. As estimated by PA Consulting in its "High Gas Price" scenario. 11. As estimated by PA Consulting in its "High Gas Price" scenario. A-67 EXHIBIT A-4 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY C - OVERBUILD PRICE SCENARIO
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 - ------------------------ --------- --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 31.3% 29.5% 31.1% 38.8% 43.9% 38.4% Contract Energy Sales (GWh)(4) 5,943 11,442 16,215 20,208 22,807 19,959 Other Energy Sales (GWh)(4) 1,116 765 0 0 37 7 --------- --------- --------- --------- --------- --------- Total Energy Sales (GWh) 7,059 12,207 16,215 20,208 22,844 19,966 Fuel Consumption (BBtu) 48,697 92,948 122,228 151,604 168,896 148,972 Average Net Heat Rate (Btu/kWh)(5) 7,710 7,788 7,741 7,683 7,572 7,642 SO(2) Allowances Purchased (Tons)(6) 24 47 61 76 83 74 NO(X) Allowances Purchased (Tons)(7) 0 (70) 163 225 291 244 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 34.44 34.72 30.16 26.72 23.45 26.70 Other Capacity Price ($/MWh)(10) $ 16.91 18.52 16.99 17.63 16.96 17.35 Other Energy Price ($/MWh)(10) $ 52.82 48.71 0.00 0.00 66.66 65.93 Fuel Price ($/MMBtu)(11) $ 5.38 4.96 0.00 0.00 3.58 3.68 SO(2) Allowances ($/Ton)(12) $ 150 154 158 162 166 171 NO(X) Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 16,645 34,138 0 0 0 0 Franklin (14) $ 85,818 109,905 116,864 121,833 123,023 120,315 Harris (14) $ 36,237 115,862 145,327 147,411 144,218 145,291 McIntosh $ 0 0 86,915 129,170 125,233 123,445 Stanton $ 10,374 45,040 43,968 44,901 45,538 45,653 Wansley $ 55,624 92,339 95,909 96,611 96,728 98,123 Other Electricity Revenues Dahlberg $ 2,223 4,429 13,540 14,054 15,955 14,280 Franklin (14) $ 3,222 12,310 0 0 0 0 Harris $ 62,689 29,934 0 0 0 0 McIntosh $ 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 --------- --------- --------- --------- --------- --------- Total Operating Revenues $ 272,832 443,957 502,523 553,980 550,695 547,107 OPERATING EXPENSES ($000) Fuel Dahlberg $ 38 0 0 0 1,703 320 Franklin $ 1,221 8,423 0 0 0 0 Harris $ 45,315 21,309 0 0 0 0 McIntosh $ 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Purchased Power (15) $ 43,081 13,258 19,993 21,630 24,257 21,294 Operations & Maintenance (16) $ 33,111 60,848 76,502 91,134 102,869 96,902 Administration and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873 --------- --------- --------- --------- --------- --------- Total Operating Expenses $ 135,495 130,804 126,229 144,685 161,220 151,389 NET OPERATING REVENUES ($000) $ 137,337 313,154 376,294 409,295 389,474 395,718 ANNUAL INTEREST($000)(18) $ 34,422 68,844 83,244 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 3.99 4.55 4.52 4.19 3.99 4.05 2003-15 AVG INTEREST COVERAGE (20) 4.37 Year Ending December 31, 2009 2010 2011 2012 2013 - ------------------------ --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 40.5% 40.7% 42.0% 40.5% 36.6% Contract Energy Sales (GWh)(4) 21,060 12,696 10,076 8,979 7,888 Other Energy Sales (GWh)(4) 43 8,226 11,463 11,822 10,837 --------- --------- --------- --------- --------- Total Energy Sales (GWh) 21,102 20,921 21,538 20,801 18,725 Fuel Consumption (BBtu) 156,836 157,496 161,511 156,240 142,566 Average Net Heat Rate (Btu/kWh)(5) 7,611 7,623 7,573 7,584 7,657 SO(2) Allowances Purchased (Tons)(6) 78 79 81 78 70 NO(X) Allowances Purchased (Tons)(7) 253 249 265 254 210 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 25.41 27.18 27.25 27.68 31.60 Other Capacity Price ($/MWh)(10) 17.85 38.56 52.83 59.99 64.27 Other Energy Price ($/MWh)(10) 69.99 46.54 47.88 49.26 50.52 Fuel Price ($/MMBtu)(11) 3.80 4.51 4.64 4.80 5.00 SO(2) Allowances ($/Ton)(12) 175 180 184 189 194 NO(X) Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Franklin (14) 122,914 81,468 25,834 0 0 Harris (14) 141,730 89,903 74,058 74,605 74,384 McIntosh 125,711 127,005 127,834 126,963 135,346 Stanton 46,141 46,647 46,856 46,966 39,522 Wansley 98,651 0 0 0 0 Other Electricity Revenues Dahlberg 17,215 32,898 47,667 53,336 53,927 Franklin (14) 0 79,572 219,335 270,606 259,187 Harris 0 101,590 163,069 164,372 165,570 McIntosh 0 0 0 0 0 Stanton 0 0 0 0 10,071 Wansley 0 271,683 300,457 311,604 294,117 --------- --------- --------- --------- --------- Total Operating Revenues 552,362 830,766 1,005,110 1,048,452 1,032,124 OPERATING EXPENSES ($000) Fuel Dahlberg 2,104 1,728 4,033 3,958 1,881 Franklin 0 47,048 122,685 147,580 139,669 Harris 0 62,157 96,060 95,109 96,152 McIntosh 0 0 0 0 0 Stanton 0 0 0 0 6,105 Wansley 0 169,700 179,467 182,875 170,179 Purchased Power (15) 23,555 13,267 10,842 10,639 5,323 Operations & Maintenance (16) 104,512 106,752 113,175 113,724 109,905 Administration and General (17) 33,364 33,872 34,386 34,924 35,465 --------- --------- --------- --------- --------- Total Operating Expenses 163,535 434,525 560,648 588,810 564,680 NET OPERATING REVENUES ($000) 388,827 396,241 444,462 459,642 467,444 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 3.98 4.06 4.55 4.71 4.79 2003-15 AVG INTEREST COVERAGE (20)
A-68 EXHIBIT A-4 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY C - OVERBUILD PRICE SCENARIO
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ----------------------- ---------- ---------- ---------- ---------- ---------- ---------- CONSOLIDATED - ----------- PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 33.9% 32.4% 29.4% 27.1% 25.3% 23.9% Contract Energy Sales (GWh)(4) 6,481 6,304 5,723 5,334 4,892 3,737 Other Energy Sales (GWh)(4) 10,835 10,245 9,282 8,539 8,056 8,425 ---------- ---------- ---------- ---------- ---------- ---------- Total Energy Sales (GWh) 17,316 16,549 15,005 13,873 12,948 12,162 Fuel Consumption (BBtu) 132,821 127,318 116,328 108,217 101,615 96,084 Average Net Heat Rate (Btu/kWh)(5) 7,714 7,739 7,799 7,846 7,894 7,922 SO(2) Allowances Purchased (Tons)(6) 66 64 57 54 51 48 NO(X) Allowances Purchased (Tons)(7) 178 152 109 89 74 61 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 33.19 34.67 38.57 41.41 45.39 45.44 Other Capacity Price ($/MWh)(10) $ 66.28 71.25 72.77 75.32 76.21 81.95 Other Energy Price ($/MWh)(10) $ 52.46 53.76 55.75 58.06 60.97 63.15 Fuel Price ($/MMBtu)(11) $ 5.32 5.51 5.76 6.01 6.18 6.41 SO(2) Allowances ($/Ton)(12) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 0 Franklin (14) $ 0 0 0 0 0 0 Harris (14) $ 75,450 77,027 75,351 75,843 76,119 16,480 McIntosh $ 139,658 141,559 145,378 145,058 145,936 153,321 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 54,403 56,996 57,404 59,126 59,776 65,654 Franklin (14) $ 251,434 244,668 235,064 223,922 227,582 226,082 Harris $ 155,698 159,658 150,527 151,764 154,296 249,581 McIntosh $ 0 0 0 0 0 0 Stanton $ 88,510 89,234 91,933 93,374 93,818 87,046 Wansley $ 284,959 286,766 275,169 270,485 262,170 266,344 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Revenues $1,050,112 1,055,908 1,030,826 1,019,572 1,019,697 1,064,508 OPERATING EXPENSES ($000) Fuel Dahlberg $ 1,388 494 127 0 0 420 Franklin $ 134,847 126,826 122,294 113,262 111,597 103,933 Harris $ 89,279 92,367 85,688 87,180 86,524 133,091 McIntosh $ 0 0 0 0 0 0 Stanton $ 54,357 53,416 54,924 54,679 55,105 51,633 Wansley $ 165,653 164,332 155,064 148,392 140,356 139,340 Purchased Power (15) $ 5,117 5,114 4,783 4,629 4,482 2,044 Operations & Maintenance (16) $ 107,871 110,658 105,305 103,746 103,888 103,122 Administration and General (17) $ 36,022 36,601 37,186 37,792 38,416 39,052 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Expenses $ 594,534 589,809 565,370 549,680 540,369 572,636 NET OPERATING REVENUES ($000) $ 455,578 466,099 465,456 469,892 479,328 491,872 ANNUAL INTEREST($000)(18) $ 97,644 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.67 4.77 4.77 4.81 4.91 5.04 2003-15 AVG INTEREST COVERAGE (20) 4.37 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 21.9% 20.3% 18.9% 18.9% Contract Energy Sales (GWh)(4) 578 0 0 0 Other Energy Sales (GWh)(4) 10,560 10,331 9,608 9,608 ---------- ---------- ---------- ---------- Total Energy Sales (GWh) 11,139 10,331 9,608 9,608 Fuel Consumption (BBtu) 88,597 82,571 76,999 76,999 Average Net Heat Rate (Btu/kWh)(5) 7,954 7,993 8,014 8,014 SO(2) Allowances Purchased (Tons)(6) 44 41 40 40 NO(X) Allowances Purchased (Tons)(7) 36 29 14 14 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 49.73 0.00 0.00 0.00 Other Capacity Price ($/MWh)(10) 83.70 87.74 89.36 91.68 Other Energy Price ($/MWh)(10) 65.07 66.58 67.56 69.32 Fuel Price ($/MMBtu)(11) 6.65 6.85 7.08 7.23 SO(2) Allowances ($/Ton)(12) 232 238 244 251 NO(X) Allowances ($/Ton)(13) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Franklin (14) 0 0 0 0 Harris (14) 0 0 0 0 McIntosh 28,769 0 0 0 Stanton 0 0 0 0 Wansley 0 0 0 0 Other Electricity Revenues Dahlberg 66,598 69,810 70,940 72,784 Franklin (14) 217,435 214,425 201,267 206,499 Harris 294,043 287,085 282,661 290,009 McIntosh 224,041 278,217 266,722 273,657 Stanton 89,129 85,030 88,273 90,568 Wansley 261,609 262,273 257,694 264,394 ---------- ---------- ---------- ---------- Total Operating Revenues 1,181,624 1,196,840 1,167,557 1,197,911 OPERATING EXPENSES ($000) Fuel Dahlberg 0 130 0 0 Franklin 97,875 92,882 83,218 84,922 Harris 154,417 148,753 144,910 148,193 McIntosh 117,489 140,173 134,904 137,925 Stanton 53,484 49,271 51,676 52,619 Wansley 135,525 134,385 130,400 133,409 Purchased Power (15) 0 0 0 0 Operations & Maintenance (16) 106,651 101,397 101,242 121,073 Administration and General (17) 39,705 40,375 41,060 41,768 ---------- ---------- ---------- ---------- Total Operating Expenses 705,145 707,366 687,409 719,908 NET OPERATING REVENUES ($000) 476,478 489,474 480,148 478,003 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.88 5.01 4.92 4.90 2003-15 AVG INTEREST COVERAGE (20)
A-69 FOOTNOTES TO EXHIBIT A-4 The footnotes to Exhibit A-4 are the same as the footnotes for Exhibit A-1, except: 3. Capacity factor as estimated by PA Consulting under its "Capacity Overbuild" scenario. 10. As estimated by PA Consulting in its "Capacity Overbuild" scenario. 11. As estimated by PA Consulting in its "Capacity Overbuild" scenario. A-70 EXHIBIT A-5 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY D - REDUCED OUTPUT
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 - ------------------------ --------- --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 4,381 4,381 5,512 5,512 5,512 5,512 Average Capacity Factor (%)(3) 31.3% 29.5% 31.7% 39.1% 43.8% 44.9% Contract Energy Sales (GWh)(4) 5,646 10,870 15,717 19,316 21,625 22,149 Other Energy Sales (GWh)(4) 1,057 727 0 8 36 70 --------- ---------- ---------- --------- --------- --------- Total Energy Sales (GWh) 6,703 11,597 15,717 19,325 21,660 22,219 Fuel Consumption (BBtu) 46,239 88,302 118,036 144,978 160,151 164,289 Average Net Heat Rate (Btu/kWh)(5) 7,706 7,788 7,715 7,685 7,572 7,572 SO(2) Allowances Purchased (Tons)(6) 23 44 58 73 80 82 NO(X) Allowances Purchased (Tons)(7) 0 (80) 144 203 264 285 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 34.75 35.09 29.62 26.77 23.58 23.37 Other Capacity Price ($/MWh)(10) $ 16.91 18.52 16.99 17.18 16.83 19.29 Other Energy Price ($/MWh)(10) $ 52.82 48.71 0.00 67.30 68.30 65.65 Fuel Price ($/MMBtu)(11) $ 5.43 5.00 0.00 3.77 3.58 3.69 SO(2) Allowances ($/Ton)(12) $ 150 154 158 162 166 171 NO(X) Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 16,661 34,138 0 0 0 0 Franklin (14) $ 82,006 105,175 111,310 114,990 117,454 118,725 Harris (14) $ 34,535 110,822 136,468 140,516 137,881 138,291 McIntosh $ 0 0 83,379 125,292 118,280 122,148 Stanton $ 9,934 43,202 42,628 43,454 43,663 44,009 Wansley $ 53,066 88,102 91,761 92,911 92,704 94,380 Other Electricity Revenues Dahlberg $ 2,111 4,207 12,862 13,557 15,186 19,184 Franklin (14) $ 2,899 11,695 0 0 0 0 Harris $ 59,555 28,437 0 0 0 0 McIntosh $ 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 --------- --------- --------- --------- --------- --------- Total Operating Revenues $ 260,767 425,778 478,408 530,720 525,168 536,737 OPERATING EXPENSES ($000) Fuel Dahlberg $ 38 0 0 407 1,663 3,346 Franklin $ 1,040 8,070 0 0 0 0 Harris $ 43,428 20,410 0 0 0 0 McIntosh $ 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Purchased Power (15) $ 40,949 12,596 19,926 21,044 23,012 24,466 Operations & Maintenance (16) $ 32,920 60,457 77,328 91,518 102,071 107,865 Administration and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873 --------- --------- --------- --------- --------- --------- Total Operating Expenses $ 131,105 128,499 126,988 144,890 159,137 168,550 NET OPERATING REVENUES ($000) $ 129,662 297,280 351,419 385,830 366,031 368,187 ANNUAL INTEREST($000)(18) $ 34,422 68,844 83,244 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 3.77 4.32 4.22 3.95 3.75 3.77 2003-15 AVG INTEREST COVERAGE (20) 4.15 Year Ending December 31, 2009 2010 2011 2012 2013 - ------------------------ --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,512 5,512 5,512 5,512 5,512 Average Capacity Factor (%)(3) 43.6% 41.2% 42.3% 40.0% 36.5% Contract Energy Sales (GWh)(4) 21,476 12,076 9,507 8,404 7,441 Other Energy Sales (GWh)(4) 81 8,067 11,135 11,091 10,264 --------- --------- --------- --------- --------- Total Energy Sales (GWh) 21,557 20,143 20,642 19,495 17,704 Fuel Consumption (BBtu) 159,513 151,511 154,520 146,678 134,857 Average Net Heat Rate (Btu/kWh)(5) 7,575 7,615 7,557 7,596 7,661 SO(2) Allowances Purchased (Tons)(6) 81 76 78 73 67 NO(X) Allowances Purchased (Tons)(7) 263 231 248 227 188 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 23.86 27.29 27.74 28.39 32.60 Other Capacity Price ($/MWh)(10) 36.69 46.49 58.16 62.97 67.71 Other Energy Price ($/MWh)(10) 67.93 45.84 47.51 49.19 50.06 Fuel Price ($/MMBtu)(11) 3.80 4.52 4.66 4.83 5.04 SO(2) Allowances ($/Ton)(12) 175 180 184 189 194 NO(X) Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Franklin (14) 118,989 78,662 25,138 0 0 Harris (14) 137,776 85,194 71,287 71,025 71,295 McIntosh 116,572 120,978 122,596 122,774 133,166 Stanton 44,261 44,744 44,673 44,808 38,131 Wansley 94,871 0 0 0 0 Other Electricity Revenues Dahlberg 33,298 38,305 50,809 52,639 53,471 Franklin (14) 0 77,414 214,642 258,359 247,106 Harris 0 99,160 159,405 155,972 158,699 McIntosh 0 0 0 0 0 Stanton 0 0 0 0 9,301 Wansley 0 272,710 294,122 295,579 280,788 --------- --------- --------- --------- --------- Total Operating Revenues 545,767 817,167 982,672 1,001,156 991,957 OPERATING EXPENSES ($000) Fuel Dahlberg 4,029 2,440 4,997 3,525 1,634 Franklin 0 44,964 118,472 140,566 132,862 Harris 0 59,753 93,296 89,875 92,270 McIntosh 0 0 0 0 0 Stanton 0 0 0 0 5,658 Wansley 0 168,425 173,971 172,927 162,266 Purchased Power (15) 23,942 12,401 9,986 9,767 5,007 Operations & Maintenance (16) 109,208 107,491 113,908 113,879 108,623 Administration and General (17) 33,364 33,872 34,386 34,924 35,465 --------- --------- --------- --------- --------- Total Operating Expenses 170,543 429,347 549,017 565,464 543,785 NET OPERATING REVENUES ($000) 375,224 387,820 433,655 435,693 448,171 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 3.84 3.97 4.44 4.46 4.59 2003-15 AVG INTEREST COVERAGE (20)
A-71 EXHIBIT A-5 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY D - REDUCED OUTPUT
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ------------------------ ---------- ---------- ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,512 5,512 5,512 5,512 5,512 5,512 Average Capacity Factor (%)(3) 33.1% 31.3% 28.5% 26.3% 24.5% 22.8% Contract Energy Sales (GWh)(4) 6,034 5,749 5,348 4,859 4,501 3,398 Other Energy Sales (GWh)(4) 10,022 9,470 8,490 7,922 7,397 7,658 ---------- ---------- ---------- ---------- ---------- ---------- Total Energy Sales (GWh) 16,056 15,219 13,838 12,781 11,898 11,056 Fuel Consumption (BBtu) 123,558 117,262 107,601 99,814 93,450 87,410 Average Net Heat Rate (Btu/kWh)(5) 7,740 7,750 7,822 7,855 7,901 7,928 SO(2) Allowances Purchased (Tons)(6) 62 58 54 50 46 43 NO(X) Allowances Purchased (Tons)(7) 152 121 83 64 51 38 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 34.56 36.47 39.87 43.90 46.87 46.82 Other Capacity Price ($/MWh)(10) $ 67.83 71.68 74.42 76.04 79.21 83.11 Other Energy Price ($/MWh)(10) $ 52.74 53.05 55.13 57.70 59.65 62.83 Fuel Price ($/MMBtu)(11) $ 5.38 5.57 5.84 6.08 6.26 6.50 SO(2) Allowances ($/Ton)(12) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 0 Franklin (14) $ 0 0 0 0 0 0 Harris (14) $ 72,508 73,365 72,444 71,808 72,853 15,567 McIntosh $ 136,033 136,292 140,800 141,513 138,096 143,517 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 52,586 54,014 55,548 56,776 59,306 62,506 Franklin (14) $ 238,351 224,647 217,665 210,762 211,114 208,604 Harris $ 147,022 147,936 141,930 141,905 142,837 231,408 McIntosh $ 0 0 0 0 0 0 Stanton $ 81,307 82,352 83,608 83,651 83,090 80,830 Wansley $ 268,452 267,262 253,624 254,549 247,527 247,260 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Revenues $ 996,259 985,868 965,619 960,964 954,823 989,692 OPERATING EXPENSES ($000) Fuel Dahlberg $ 1,167 282 0 0 0 0 Franklin $ 128,064 117,685 113,992 107,140 102,900 94,921 Harris $ 84,056 86,370 81,756 81,686 79,808 123,696 McIntosh $ 0 0 0 0 0 0 Stanton $ 49,576 49,822 50,321 49,625 49,948 47,721 Wansley $ 155,459 155,462 142,996 140,350 133,782 128,569 Purchased Power (15) $ 4,788 4,651 4,413 4,225 4,070 1,852 Operations & Maintenance (16) $ 105,302 108,721 103,005 101,715 101,896 100,125 Administration and General (17) $ 36,022 36,601 37,186 37,792 38,416 39,052 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Expenses $ 564,434 559,595 533,669 522,533 510,821 535,936 NET OPERATING REVENUES ($000) $ 431,825 426,273 431,950 438,431 444,002 453,756 ANNUAL INTEREST($000)(18) $ 97,644 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.42 4.37 4.42 4.49 4.55 4.65 2003-15 AVG INTEREST COVERAGE (20) 4.15 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,512 5,512 5,512 5,512 Average Capacity Factor (%)(3) 21.0% 20.2% 18.4% 18.4% Contract Energy Sales (GWh)(4) 523 0 0 0 Other Energy Sales (GWh)(4) 9,601 9,760 8,906 8,906 ---------- ---------- ---------- ---------- Total Energy Sales (GWh) 10,124 9,760 8,906 8,906 Fuel Consumption (BBtu) 80,558 78,109 71,405 71,405 Average Net Heat Rate (Btu/kWh)(5) 7,957 8,003 8,018 8,018 SO(2) Allowances Purchased (Tons)(6) 40 39 36 36 NO(X) Allowances Purchased (Tons)(7) 16 12 (2) (2) COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 51.14 0.00 0.00 0.00 Other Capacity Price ($/MWh)(10) 84.87 87.74 89.36 91.68 Other Energy Price ($/MWh)(10) 64.45 66.02 67.65 69.40 Fuel Price ($/MMBtu)(11) 6.75 6.90 7.16 7.32 SO(2) Allowances ($/Ton)(12) 232 238 244 251 NO(X) Allowances ($/Ton)(13) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Franklin (14) 0 0 0 0 Harris (14) 0 0 0 0 McIntosh 26,758 0 0 0 Stanton 0 0 0 0 Wansley 0 0 0 0 Other Electricity Revenues Dahlberg 63,934 66,178 67,392 69,144 Franklin (14) 198,453 202,869 188,074 192,962 Harris 271,374 268,626 269,169 276,168 McIntosh 206,287 265,826 246,963 253,384 Stanton 82,352 80,216 81,518 83,637 Wansley 245,028 244,276 241,839 248,126 ---------- ---------- ---------- ---------- Total Operating Revenues 1,094,186 1,127,991 1,094,955 1,123,421 OPERATING EXPENSES ($000) Fuel Dahlberg 0 0 0 0 Franklin 88,306 89,218 77,718 79,279 Harris 142,849 140,234 139,116 142,248 McIntosh 107,577 136,710 123,346 126,066 Stanton 49,330 47,612 48,406 49,264 Wansley 127,626 125,551 122,948 125,764 Purchased Power (15) 0 0 0 0 Operations & Maintenance (16) 99,569 105,169 99,893 120,492 Administration and General (17) 39,705 40,375 41,060 41,768 ---------- ---------- ---------- ---------- Total Operating Expenses 654,962 684,868 652,486 684,881 NET OPERATING REVENUES ($000) 439,224 443,123 442,469 438,540 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.50 4.54 4.53 4.49 2003-15 AVG INTEREST COVERAGE (20)
A-72 FOOTNOTES TO EXHIBIT A-5 The footnotes to Exhibit A-5 are the same as the footnotes for Exhibit A-1, except: 2. The output of the Generating Facilities is assumed to be 5 percent less than that assumed in the Base Case. A-73 EXHIBIT A-6 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY E - REDUCED AVAILABILITY
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 - ------------------------ --------- --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 29.7% 28.0% 30.1% 37.1% 41.5% 42.6% Contract Energy Sales (GWh)(4) 5,943 11,442 16,544 20,333 22,763 23,315 Other Energy Sales (GWh)(4) 1,011 587 0 8 36 70 --------- --------- --------- --------- --------- --------- Total Energy Sales (GWh) 6,954 12,029 16,544 20,341 22,799 23,384 Fuel Consumption (BBtu) 46,163 88,156 117,843 144,742 159,891 164,023 Average Net Heat Rate (Btu/kWh)(5) 7,706 7,788 7,715 7,685 7,572 7,572 SO(2) Allowances Purchased (Tons)(6) 23 44 58 73 80 82 NO(X) Allowances Purchased (Tons)(7) 0 (81) 142 203 263 284 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 35.75 35.98 30.99 28.04 24.81 24.63 Other Capacity Price ($/MWh)(10) $ 16.91 18.52 16.99 17.18 16.83 19.29 Other Energy Price ($/MWh)(10) $ 52.76 48.61 0.00 67.24 68.33 65.65 Fuel Price ($/MMBtu)(11) $ 5.43 5.00 0.00 3.77 3.58 3.69 SO(2) Allowances ($/Ton)(12) $ 150 154 158 162 166 171 NO(X) Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 16,661 34,138 0 0 0 0 Franklin (14) $ 87,294 112,236 121,654 126,059 129,387 131,009 Harris (14) $ 38,190 119,384 149,633 154,398 152,007 152,927 McIntosh $ 0 0 92,105 137,730 130,987 135,325 Stanton $ 10,995 47,607 46,499 47,484 47,687 48,107 Wansley $ 59,305 98,298 102,845 104,437 104,629 106,880 Other Electricity Revenues Dahlberg $ 2,220 4,429 13,540 14,241 15,857 19,948 Franklin (14) $ 578 8,148 0 0 0 0 Harris $ 59,734 25,371 0 0 0 0 McIntosh $ 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 --------- --------- --------- --------- --------- --------- Total Operating Revenues $ 274,977 449,611 526,276 584,349 580,554 594,196 OPERATING EXPENSES ($000) Fuel Dahlberg $ 38 0 0 407 1,663 3,346 Franklin $ (869) 5,218 0 0 0 0 Harris $ 43,370 17,782 0 0 0 0 McIntosh $ 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Purchased Power (15) $ 54,681 34,276 60,040 68,226 74,847 79,728 Operations & Maintenance (16) $ 32,510 59,608 76,203 90,190 100,473 106,130 Administration and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873 --------- --------- --------- --------- --------- --------- Total Operating Expenses $ 142,460 143,850 165,977 190,744 209,374 222,077 NET OPERATING REVENUES ($000) $ 132,517 305,760 360,298 393,605 371,180 372,119 ANNUAL INTEREST($000)(18) $ 34,422 68,844 83,244 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 3.85 4.44 4.33 4.03 3.80 3.81 2003-15 AVG INTEREST COVERAGE (20) 4.26 Year Ending December 31, 2009 2010 2011 2012 2013 - ------------------------ --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 41.4% 39.1% 40.2% 37.9% 34.6% Contract Energy Sales (GWh)(4) 22,607 12,712 10,007 8,847 7,832 Other Energy Sales (GWh)(4) 81 7,976 11,080 11,073 10,199 --------- --------- -------- -------- -------- Total Energy Sales (GWh) 22,688 20,688 21,087 19,919 18,031 Fuel Consumption (BBtu) 159,253 151,266 154,268 146,438 134,639 Average Net Heat Rate (Btu/kWh)(5) 7,575 7,615 7,557 7,596 7,661 SO(2) Allowances Purchased (Tons)(6) 81 76 78 72 67 NO(X) Allowances Purchased (Tons)(7) 262 229 247 226 187 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 25.17 28.42 28.92 29.75 33.71 Other Capacity Price ($/MWh)(10) 36.69 46.49 58.16 62.97 67.71 Other Energy Price ($/MWh)(10) 67.92 45.82 47.50 49.19 50.01 Fuel Price ($/MMBtu)(11) 3.80 4.52 4.66 4.83 5.03 SO(2) Allowances ($/Ton)(12) 175 180 184 189 194 NO(X) Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Franklin (14) 131,115 85,679 25,853 0 0 Harris (14) 152,418 92,958 78,739 78,414 78,276 McIntosh 129,972 133,886 136,160 136,194 146,116 Stanton 48,203 48,774 48,643 48,616 39,633 Wansley 107,349 0 0 0 0 Other Electricity Revenues Dahlberg 34,756 40,155 53,123 55,143 56,160 Franklin (14) 0 76,580 215,281 261,637 250,668 Harris 0 97,886 160,951 157,673 160,536 McIntosh 0 0 0 0 0 Stanton 0 0 0 0 6,586 Wansley 0 274,876 296,908 298,633 284,121 --------- --------- --------- --------- --------- Total Operating Revenues 603,813 850,794 1,015,658 1,036,310 1,022,096 OPERATING EXPENSES ($000) Fuel Dahlberg 4,025 2,440 4,997 3,521 1,634 Franklin 0 43,728 116,955 140,367 132,679 Harris 0 58,119 93,161 89,748 92,139 McIntosh 0 0 0 0 0 Stanton 0 0 0 0 3,111 Wansley 0 168,183 173,721 172,677 162,036 Purchased Power (15) 78,500 40,280 33,325 32,638 22,842 Operations & Maintenance (16) 107,464 105,802 112,082 111,551 107,005 Administration and General (17) 33,364 33,872 34,386 34,924 35,465 --------- --------- --------- --------- --------- Total Operating Expenses 223,353 452,424 568,628 585,427 556,911 NET OPERATING REVENUES ($000) 380,460 398,370 447,030 450,883 465,184 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 3.90 4.08 4.58 4.62 4.76 2003-15 AVG INTEREST COVERAGE (20)
A-74 EXHIBIT A-6 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY E - REDUCED AVAILABILITY
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ------------------------ ---------- ---------- ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 31.4% 29.7% 27.0% 25.0% 23.2% 21.7% Contract Energy Sales (GWh)(4) 6,352 6,051 5,629 5,115 4,738 3,576 Other Energy Sales (GWh)(4) 10,006 9,455 8,477 7,909 7,385 7,620 ---------- ---------- ---------- ---------- ---------- ---------- Total Energy Sales (GWh) 16,358 15,506 14,106 13,024 12,123 11,197 Fuel Consumption (BBtu) 123,357 117,070 107,425 99,651 93,298 87,267 Average Net Heat Rate (Btu/kWh)(5) 7,740 7,750 7,822 7,855 7,901 7,928 SO(2) Allowances Purchased (Tons)(6) 62 58 54 49 46 43 NO(X) Allowances Purchased (Tons)(7) 152 121 83 64 50 37 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 35.88 37.81 41.22 45.27 48.29 47.96 Other Capacity Price ($/MWh)(10) $ 67.83 71.68 74.42 76.04 79.21 83.11 Other Energy Price ($/MWh)(10) $ 52.74 53.05 55.13 57.70 59.65 62.84 Fuel Price ($/MMBtu)(11) $ 5.38 5.58 5.84 6.08 6.26 6.50 SO(2) Allowances ($/Ton)(12) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 0 Franklin (14) $ 0 0 0 0 0 0 Harris (14) $ 79,351 80,281 79,159 78,259 79,323 16,327 McIntosh $ 148,534 148,515 152,902 153,285 149,478 155,196 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 55,259 56,835 58,471 59,764 62,426 65,796 Franklin (14) $ 241,903 228,440 221,620 214,821 215,370 213,110 Harris $ 148,867 149,893 143,976 144,002 145,036 233,752 McIntosh $ 0 0 0 0 0 0 Stanton $ 82,687 83,838 85,181 85,258 84,730 82,506 Wansley $ 271,783 270,803 257,330 258,344 251,521 251,493 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Revenues $1,028,384 1,018,605 998,639 993,733 987,884 1,018,180 OPERATING EXPENSES ($000) Fuel Dahlberg $ 1,167 277 0 0 0 0 Franklin $ 127,891 117,528 113,842 107,000 102,764 94,791 Harris $ 83,939 86,245 81,640 81,570 79,698 122,251 McIntosh $ 0 0 0 0 0 0 Stanton $ 49,518 49,768 50,265 49,571 49,893 47,669 Wansley $ 155,239 155,240 142,789 140,144 133,588 128,385 Purchased Power (15) $ 21,810 20,992 20,005 19,207 18,323 11,597 Operations & Maintenance (16) $ 103,820 107,274 101,347 100,409 100,247 98,758 Administration and General (17) $ 36,022 36,601 37,186 37,792 38,416 39,052 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Expenses $ 579,406 573,926 547,073 535,693 522,930 542,504 NET OPERATING REVENUES ($000) $ 448,978 444,679 451,566 458,040 464,954 475,676 ANNUAL INTEREST($000)(18) $ 97,644 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.60 4.55 4.62 4.69 4.76 4.87 2003-15 AVG INTEREST COVERAGE (20) 4.26 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 19.9% 19.2% 17.5% 17.5% Contract Energy Sales (GWh)(4) 551 0 0 0 Other Energy Sales (GWh)(4) 9,557 9,744 8,892 8,892 ---------- ---------- ---------- ---------- Total Energy Sales (GWh) 10,108 9,744 8,892 8,892 Fuel Consumption (BBtu) 80,427 77,982 71,290 71,290 Average Net Heat Rate (Btu/kWh)(5) 7,957 8,003 8,018 8,018 SO(2) Allowances Purchased (Tons)(6) 40 39 36 36 NO(X) Allowances Purchased (Tons)(7) 16 12 (2) (2) COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 50.29 0.00 0.00 0.00 Other Capacity Price ($/MWh)(10) 84.87 87.74 89.36 91.68 Other Energy Price ($/MWh)(10) 64.45 66.02 67.65 69.40 Fuel Price ($/MMBtu)(11) 6.75 6.91 7.17 7.32 SO(2) Allowances ($/Ton)(12) 232 238 244 251 NO(X) Allowances ($/Ton)(13) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Franklin (14) 0 0 0 0 Harris (14) 0 0 0 0 McIntosh 27,698 0 0 0 Stanton 0 0 0 0 Wansley 0 0 0 0 Other Electricity Revenues Dahlberg 67,299 69,661 70,940 72,784 Franklin (14) 203,088 207,672 192,994 198,011 Harris 276,122 273,562 274,201 281,330 McIntosh 208,308 270,755 252,021 258,573 Stanton 84,061 81,962 83,297 85,463 Wansley 249,369 248,785 246,442 252,849 ---------- ---------- ---------- ---------- Total Operating Revenues 1,115,945 1,152,397 1,119,895 1,149,010 OPERATING EXPENSES ($000) Fuel Dahlberg 0 0 0 0 Franklin 88,189 89,109 77,629 79,188 Harris 142,645 140,032 138,920 142,047 McIntosh 105,948 136,518 123,179 125,895 Stanton 49,276 47,556 48,349 49,206 Wansley 127,445 125,371 122,770 125,581 Purchased Power (15) 0 0 0 0 Operations & Maintenance (16) 98,440 99,478 103,380 119,355 Administration and General (17) 39,705 40,375 41,060 41,768 ---------- ---------- ---------- ---------- Total Operating Expenses 651,648 678,438 655,286 683,039 NET OPERATING REVENUES ($000) 464,296 473,959 464,609 465,971 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.75 4.85 4.76 4.77 2003-15 AVG INTEREST COVERAGE (20)
A-75 FOOTNOTES TO EXHIBIT A-6 The footnotes to Exhibit A-6 are the same as the footnotes for Exhibit A-1, except: 3. Availability of the Generating Facilities is assumed to be 5 percentage points less than that assumed in the Base Case based on a 5 percentage point increase in the forced outage rate for each of the Generating Facilities, resulting in a reduction in the capacity factors for each of the Generating Facilities such that annual generation is reduced by 5 percent from that assumed in the Base Case. A-76 EXHIBIT A-7 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY F - INCREASED HEAT RATE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 - ------------------------ --------- --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 31.3% 29.5% 31.7% 39.1% 43.8% 44.9% Contract Energy Sales (GWh)(4) 5,943 11,442 16,544 20,333 22,763 23,315 Other Energy Sales (GWh)(4) 1,116 765 0 9 38 73 --------- --------- -------- -------- -------- -------- Total Energy Sales (GWh) 7,059 12,207 16,544 20,342 22,800 23,388 Fuel Consumption (BBtu) 51,132 97,596 130,461 160,238 177,009 181,583 Average Net Heat Rate (Btu/kWh)(5) 8,096 8,177 8,101 8,069 7,951 7,951 SO(2) Allowances Purchased (Tons)(6) 25 49 65 82 88 92 NO(X) Allowances Purchased (Tons)(7) 0 (60) 187 254 319 344 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 34.44 34.72 29.42 26.55 23.42 23.20 Other Capacity Price ($/MWh)(10) $ 16.91 18.52 16.99 17.18 16.83 19.29 Other Energy Price ($/MWh)(10) $ 52.82 48.71 0.00 67.31 68.32 65.64 Fuel Price ($/MMBtu)(11) $ 6.33 7.84 0.00 251.15 63.23 35.96 SO(2) Allowances ($/Ton)(12) $ 150 154 158 162 166 171 NO(X) Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 16,645 34,138 0 0 0 0 Franklin (14) $ 85,818 109,905 116,396 120,196 122,832 124,145 Harris (14) $ 36,237 115,862 142,441 146,622 144,089 144,558 McIntosh $ 0 0 87,301 130,323 123,410 127,323 Stanton $ 10,374 45,040 44,420 45,276 45,484 45,836 Wansley $ 55,624 92,339 96,116 97,366 97,269 99,010 Other Electricity Revenues Dahlberg $ 2,223 4,429 13,540 14,271 15,987 20,192 Franklin (14) $ 3,222 12,310 0 0 0 0 Harris $ 62,689 29,934 0 0 0 0 McIntosh $ 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 --------- --------- --------- --------- --------- --------- Total Operating Revenues $ 272,832 443,957 500,214 554,054 549,071 561,064 OPERATING EXPENSES ($000) Fuel Dahlberg $ 58 0 0 448 1,839 3,697 Franklin $ 4,196 13,343 5,099 5,686 6,359 6,659 Harris $ 49,098 27,734 6,977 7,540 7,680 8,118 McIntosh $ 0 0 4,663 7,185 7,352 7,762 Stanton $ 613 2,464 1,964 2,168 2,135 2,203 Wansley $ 3,570 5,783 6,527 6,860 7,138 7,632 Purchased Power (15) $ 43,081 13,258 20,974 22,153 24,224 25,754 Operations & Maintenance (16) $ 33,111 60,868 77,862 92,184 102,830 108,674 Administration and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873 --------- --------- --------- --------- --------- --------- Total Operating Expenses $ 146,457 150,417 153,800 176,145 191,947 203,372 NET OPERATING REVENUES ($000) $ 126,375 293,540 346,414 377,909 357,125 357,692 ANNUAL INTEREST($000)(18) $ 34,422 68,844 83,244 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 3.67 4.26 4.16 3.87 3.66 3.66 2003-15 AVG INTEREST COVERAGE (20) 4.10 Year Ending December 31, 2009 2010 2011 2012 2013 - ------------------------ --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 43.6% 41.2% 42.3% 40.0% 36.5% Contract Energy Sales (GWh)(4) 22,607 12,712 10,007 8,847 7,832 Other Energy Sales (GWh)(4) 86 8,491 11,721 11,674 10,804 -------- -------- -------- -------- -------- Total Energy Sales (GWh) 22,692 21,203 21,728 20,521 18,636 Fuel Consumption (BBtu) 176,303 167,459 170,785 162,118 149,052 Average Net Heat Rate (Btu/kWh)(5) 7,954 7,996 7,935 7,976 8,044 SO(2) Allowances Purchased (Tons)(6) 89 84 87 81 73 NO(X) Allowances Purchased (Tons)(7) 320 283 301 280 237 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 23.70 27.06 27.44 28.12 32.21 Other Capacity Price ($/MWh)(10) 36.69 46.49 58.16 62.97 67.71 Other Energy Price ($/MWh)(10) 67.93 45.84 47.51 49.19 50.06 Fuel Price ($/MMBtu)(11) 31.39 4.75 4.77 4.92 5.12 SO(2) Allowances ($/Ton)(12) 175 180 184 189 194 NO(X) Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Franklin (14) 124,376 82,134 25,853 0 0 Harris (14) 144,040 89,115 74,485 74,217 74,430 McIntosh 121,774 126,117 127,802 127,964 138,295 Stanton 46,076 46,560 46,476 46,609 39,515 Wansley 99,498 0 0 0 0 Other Electricity Revenues Dahlberg 35,052 40,321 53,484 55,407 56,286 Franklin (14) 0 81,488 225,938 271,958 260,111 Harris 0 104,379 167,795 164,181 167,052 McIntosh 0 0 0 0 0 Stanton 0 0 0 0 9,790 Wansley 0 287,063 309,602 311,136 295,566 --------- --------- --------- --------- --------- Total Operating Revenues 570,816 857,177 1,031,435 1,051,472 1,041,045 OPERATING EXPENSES ($000) Fuel Dahlberg 4,450 2,695 5,524 3,897 1,804 Franklin 6,534 53,433 130,297 153,180 144,623 Harris 8,129 70,355 106,128 102,276 104,557 McIntosh 7,956 7,539 8,107 7,985 7,586 Stanton 2,107 2,119 2,038 1,958 7,814 Wansley 7,614 184,096 190,228 189,073 177,290 Purchased Power (15) 25,204 13,054 10,511 10,282 5,270 Operations & Maintenance (16) 110,030 108,315 114,804 114,734 109,409 Administration and General (17) 33,364 33,872 34,386 34,924 35,465 --------- --------- --------- --------- --------- Total Operating Expenses 205,389 475,477 602,023 618,309 593,818 NET OPERATING REVENUES ($000) 365,427 381,699 429,412 433,163 447,227 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 3.74 3.91 4.40 4.44 4.58 2003-15 AVG INTEREST COVERAGE (20)
A-77 EXHIBIT A-7 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY F - INCREASED HEAT RATE
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ------------------------ ---------- ---------- ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 33.1% 31.3% 28.5% 26.3% 24.5% 22.8% Contract Energy Sales (GWh)(4) 6,352 6,051 5,629 5,115 4,738 3,576 Other Energy Sales (GWh)(4) 10,550 9,968 8,937 8,339 7,786 8,061 ---------- ---------- ---------- ---------- ---------- ---------- Total Energy Sales (GWh) 16,901 16,020 14,567 13,453 12,524 11,638 Fuel Consumption (BBtu) 136,563 129,603 118,928 110,320 103,286 96,611 Average Net Heat Rate (Btu/kWh)(5) 8,127 8,138 8,213 8,248 8,296 8,324 SO(2) Allowances Purchased (Tons)(6) 68 64 60 56 52 49 NO(X) Allowances Purchased (Tons)(7) 196 162 121 99 86 70 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 34.12 35.99 39.32 43.28 46.20 46.07 Other Capacity Price ($/MWh)(10) $ 67.83 71.68 74.42 76.04 79.21 83.11 Other Energy Price ($/MWh)(10) $ 52.74 53.05 55.13 57.70 59.65 62.83 Fuel Price ($/MMBtu)(11) $ 5.42 5.62 5.89 6.13 6.31 6.51 SO(2) Allowances ($/Ton)(12) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 0 Franklin (14) $ 0 0 0 0 0 0 Harris (14) $ 75,619 76,488 75,534 74,859 75,898 16,327 McIntosh $ 141,097 141,329 145,813 146,477 143,008 148,445 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 55,353 56,856 58,471 59,764 62,426 65,796 Franklin (14) $ 250,895 236,471 229,122 221,854 222,225 219,581 Harris $ 154,761 155,722 149,400 149,374 150,355 243,589 McIntosh $ 0 0 0 0 0 0 Stanton $ 85,586 86,686 88,008 88,055 87,464 85,084 Wansley $ 282,582 281,329 266,973 267,947 260,555 260,275 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Revenues $1,045,893 1,034,881 1,013,321 1,008,330 1,001,931 1,039,097 OPERATING EXPENSES ($000) Fuel Dahlberg $ 1,290 308 0 0 0 0 Franklin $ 139,283 127,763 123,639 116,179 111,756 103,055 Harris $ 95,341 97,935 92,648 92,331 90,442 136,152 McIntosh $ 7,213 6,970 6,880 6,602 6,275 6,542 Stanton $ 53,172 53,444 53,999 53,230 53,583 51,120 Wansley $ 169,764 169,812 156,247 153,449 146,321 140,559 Purchased Power (15) $ 5,040 4,895 4,646 4,447 4,285 1,949 Operations & Maintenance (16) $ 106,027 109,415 103,650 102,325 102,485 100,685 Administration and General (17) $ 36,022 36,601 37,186 37,792 38,416 39,052 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Expenses $ 613,153 607,143 578,894 566,355 553,563 579,115 NET OPERATING REVENUES ($000) $ 432,740 427,738 434,427 441,975 448,368 459,982 ANNUAL INTEREST($000)(18) $ 97,644 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.43 4.38 4.45 4.53 4.59 4.71 2003-15 AVG INTEREST COVERAGE (20) 4.10 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 21.0% 20.2% 18.4% 18.4% Contract Energy Sales (GWh)(4) 551 0 0 0 Other Energy Sales (GWh)(4) 10,107 10,274 9,375 9,375 ------ ------ ------ ------ Total Energy Sales (GWh) 10,657 10,274 9,375 9,375 Fuel Consumption (BBtu) 89,039 86,331 78,922 78,922 Average Net Heat Rate (Btu/kWh)(5) 8,355 8,403 8,419 8,419 SO(2) Allowances Purchased (Tons)(6) 44 44 40 40 NO(X) Allowances Purchased (Tons)(7) 45 43 25 25 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 50.29 0.00 0.00 0.00 Other Capacity Price ($/MWh)(10) 84.87 87.74 89.36 91.68 Other Energy Price ($/MWh)(10) 64.45 66.02 67.65 69.40 Fuel Price ($/MMBtu)(11) 6.66 6.80 7.05 7.21 SO(2) Allowances ($/Ton)(12) 232 238 244 251 NO(X) Allowances ($/Ton)(13) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Franklin (14) 0 0 0 0 Harris (14) 0 0 0 0 McIntosh 27,698 0 0 0 Stanton 0 0 0 0 Wansley 0 0 0 0 Other Electricity Revenues Dahlberg 67,299 69,661 70,940 72,784 Franklin (14) 208,898 213,547 197,972 203,119 Harris 285,657 282,765 283,337 290,702 McIntosh 217,143 279,817 259,961 266,720 Stanton 86,687 84,437 85,808 88,039 Wansley 257,924 257,133 254,567 261,186 ---------- ---------- ---------- ---------- Total Operating Revenues 1,151,306 1,187,360 1,152,585 1,182,550 OPERATING EXPENSES ($000) Fuel Dahlberg 0 0 0 0 Franklin 95,739 96,750 84,041 85,766 Harris 155,922 153,038 151,803 155,265 McIntosh 118,570 149,130 134,357 137,364 Stanton 52,905 51,000 51,880 52,829 Wansley 139,518 137,224 134,347 137,459 Purchased Power (15) 0 0 0 0 Operations & Maintenance (16) 100,114 105,714 100,405 121,018 Administration and General (17) 39,705 40,375 41,060 41,768 ---------- ---------- ---------- ---------- Total Operating Expenses 702,472 733,230 697,893 731,468 NET OPERATING REVENUES ($000) 448,833 454,130 454,692 451,082 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.60 4.65 4.66 4.62 2003-15 AVG INTEREST COVERAGE (20)
A-78 FOOTNOTES TO EXHIBIT A-7 The footnotes to Exhibit A-7 are the same as the footnotes for Exhibit A-1, except: 5. Heat rate for each of the Generating Facilities is assumed to be 5 percent higher than that assumed in the Base Case. A-79 EXHIBIT A-8 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY G - INCREASED OPERATING EXPENSES
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 - ------------------------ --------- --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 31.3% 29.5% 31.7% 39.1% 43.8% 44.9% Contract Energy Sales (GWh)(4) 5,943 11,442 16,544 20,333 22,763 23,315 Other Energy Sales (GWh)(4) 1,116 765 0 9 38 73 --------- --------- --------- --------- --------- --------- Total Energy Sales (GWh) 7,059 12,207 16,544 20,342 22,800 23,388 Fuel Consumption (BBtu) 48,697 92,948 124,247 152,609 168,579 172,934 Average Net Heat Rate (Btu/kWh)(5) 7,710 7,788 7,715 7,685 7,572 7,572 SO(2) Allowances Purchased (Tons)(6) 24 47 62 77 83 86 NO(X) Allowances Purchased (Tons)(7) 0 (70) 165 229 292 314 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 34.44 34.72 29.42 26.55 23.42 23.20 Other Capacity Price ($/MWh)(10) $ 16.91 18.52 16.99 17.18 16.83 19.29 Other Energy Price ($/MWh)(10) $ 52.82 48.71 0.00 67.31 68.32 65.64 Fuel Price ($/MMBtu)(11) $ 5.38 4.96 0.00 3.76 3.58 3.69 SO(2) Allowances ($/Ton)(12) $ 150 154 158 162 166 171 NO(X) Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 16,645 34,138 0 0 0 0 Franklin (14) $ 85,818 109,905 116,396 120,196 122,832 124,145 Harris (14) $ 36,237 115,862 142,441 146,622 144,089 144,558 McIntosh $ 0 0 87,301 130,323 123,410 127,323 Stanton $ 10,374 45,040 44,420 45,276 45,484 45,836 Wansley $ 55,624 92,339 96,116 97,366 97,269 99,010 Other Electricity Revenues Dahlberg $ 2,223 4,429 13,540 14,271 15,987 20,192 Franklin (14) $ 3,222 12,310 0 0 0 0 Harris $ 62,689 29,934 0 0 0 0 McIntosh $ 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 --------- --------- --------- --------- --------- --------- Total Operating Revenues $ 272,832 443,957 500,214 554,054 549,071 561,064 OPERATING EXPENSES ($000) Fuel Dahlberg $ 38 0 0 429 1,753 3,520 Franklin $ 1,221 8,423 0 0 0 0 Harris $ 45,315 21,309 0 0 0 0 McIntosh $ 0 0 0 0 0 0 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Purchased Power (15) $ 43,081 13,258 20,974 22,153 24,224 25,754 Operations & Maintenance (16) $ 36,422 66,948 85,634 101,391 113,108 119,535 Administration and General (17) $ 14,001 29,661 32,704 35,113 35,629 36,156 --------- --------- --------- --------- --------- --------- Total Operating Expenses $ 140,078 139,599 139,312 159,086 174,714 184,965 NET OPERATING REVENUES ($000) $ 132,754 304,359 360,902 394,968 374,358 376,099 ANNUAL INTEREST($000)(18) $ 34,422 68,844 83,244 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 3.86 4.42 4.34 4.04 3.83 3.85 2003-15 AVG INTEREST COVERAGE (20) 4.27 Year Ending December 31, 2009 2010 2011 2012 2013 - ------------------------ --------- --------- --------- --------- --------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 43.6% 41.2% 42.3% 40.0% 36.5% Contract Energy Sales (GWh)(4) 22,607 12,712 10,007 8,847 7,832 Other Energy Sales (GWh)(4) 86 8,491 11,721 11,674 10,804 --------- --------- --------- --------- --------- Total Energy Sales (GWh) 22,692 21,203 21,728 20,521 18,636 Fuel Consumption (BBtu) 167,909 159,487 162,653 154,397 141,954 Average Net Heat Rate (Btu/kWh)(5) 7,575 7,615 7,557 7,596 7,660 SO(2) Allowances Purchased (Tons)(6) 85 80 83 76 70 NO(X) Allowances Purchased (Tons)(7) 290 257 274 253 213 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 23.70 27.06 27.44 28.12 32.21 Other Capacity Price ($/MWh)(10) 36.69 46.49 58.16 62.97 67.71 Other Energy Price ($/MWh)(10) 67.93 45.84 47.51 49.19 50.06 Fuel Price ($/MMBtu)(11) 3.80 4.49 4.63 4.80 5.00 SO(2) Allowances ($/Ton)(12) 175 180 184 189 194 NO(X) Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 0 Franklin (14) 124,376 82,134 25,853 0 0 Harris (14) 144,040 89,115 74,485 74,217 74,430 McIntosh 121,774 126,117 127,802 127,964 138,295 Stanton 46,076 46,560 46,476 46,609 39,515 Wansley 99,498 0 0 0 0 Other Electricity Revenues Dahlberg 35,052 40,321 53,484 55,407 56,286 Franklin (14) 0 81,488 225,938 271,958 260,111 Harris 0 104,379 167,795 164,181 167,052 McIntosh 0 0 0 0 0 Stanton 0 0 0 0 9,790 Wansley 0 287,063 309,602 311,136 295,566 --------- --------- --------- --------- --------- Total Operating Revenues 570,816 857,177 1,031,435 1,051,472 1,041,045 OPERATING EXPENSES ($000) Fuel Dahlberg 4,242 2,569 5,267 3,711 1,718 Franklin 0 46,993 123,819 146,873 138,743 Harris 0 62,530 97,649 94,037 96,545 McIntosh 0 0 0 0 0 Stanton 0 0 0 0 5,867 Wansley 0 176,261 182,099 180,998 169,780 Purchased Power (15) 25,204 13,054 10,511 10,282 5,270 Operations & Maintenance (16) 121,025 119,087 126,214 126,137 120,289 Administration and General (17) 36,697 37,253 37,828 38,409 39,009 --------- --------- --------- --------- --------- Total Operating Expenses 187,168 457,748 583,387 600,448 577,221 NET OPERATING REVENUES ($000) 383,648 399,429 448,048 451,025 463,824 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 3.93 4.09 4.59 4.62 4.75 2003-15 AVG INTEREST COVERAGE (20)
A-80 EXHIBIT A-8 SOUTHERN POWER COMPANY, INC. FACILITIES PROJECTED OPERATING RESULTS SENSITIVITY G - INCREASED OPERATING EXPENSES
Year Ending December 31, 2014 2015 2016 2017 2018 2019 - ------------------------ ---------- ---------- ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 33.1% 31.3% 28.5% 26.3% 24.5% 22.8% Contract Energy Sales (GWh)(4) 6,352 6,051 5,629 5,115 4,738 3,576 Other Energy Sales (GWh)(4) 10,550 9,968 8,937 8,339 7,786 8,061 ---------- ---------- ---------- ---------- ---------- ---------- Total Energy Sales (GWh) 16,901 16,020 14,567 13,453 12,524 11,638 Fuel Consumption (BBtu) 130,059 123,431 113,265 105,067 98,368 92,010 Average Net Heat Rate (Btu/kWh)(5) 7,740 7,750 7,822 7,855 7,901 7,928 SO(2) Allowances Purchased (Tons)(6) 66 62 57 52 49 46 NO(X) Allowances Purchased (Tons)(7) 174 143 102 81 68 54 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) $ 34.12 35.99 39.32 43.28 46.20 46.07 Other Capacity Price ($/MWh)(10) $ 67.83 71.68 74.42 76.04 79.21 83.11 Other Energy Price ($/MWh)(10) $ 52.74 53.05 55.13 57.70 59.65 62.83 Fuel Price ($/MMBtu)(11) $ 5.34 5.53 5.79 6.03 6.21 6.44 SO(2) Allowances ($/Ton)(12) $ 199 204 209 215 220 226 NO(X) Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373 2,435 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg $ 0 0 0 0 0 0 Franklin (14) $ 0 0 0 0 0 0 Harris (14) $ 75,619 76,488 75,534 74,859 75,898 16,327 McIntosh $ 141,097 141,329 145,813 146,477 143,008 148,445 Stanton $ 0 0 0 0 0 0 Wansley $ 0 0 0 0 0 0 Other Electricity Revenues Dahlberg $ 55,353 56,856 58,471 59,764 62,426 65,796 Franklin (14) $ 250,895 236,471 229,122 221,854 222,225 219,581 Harris $ 154,761 155,722 149,400 149,374 150,355 243,589 McIntosh $ 0 0 0 0 0 0 Stanton $ 85,586 86,686 88,008 88,055 87,464 85,084 Wansley $ 282,582 281,329 266,973 267,947 260,555 260,275 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Revenues $1,045,893 1,034,881 1,013,321 1,008,330 1,001,931 1,039,097 OPERATING EXPENSES ($000) Fuel Dahlberg $ 1,229 291 0 0 0 0 Franklin $ 133,670 122,726 118,812 111,665 107,328 98,985 Harris $ 87,889 90,309 85,446 85,355 83,464 129,387 McIntosh $ 0 0 0 0 0 0 Stanton $ 51,374 51,636 52,163 51,430 51,765 49,421 Wansley $ 162,611 162,635 149,621 146,902 140,054 134,564 Purchased Power (15) $ 5,040 4,895 4,646 4,447 4,285 1,949 Operations & Maintenance (16) $ 116,579 120,305 113,973 112,527 112,707 110,731 Administration and General (17) $ 39,622 40,258 40,909 41,570 42,255 42,954 ---------- ---------- ---------- ---------- ---------- ---------- Total Operating Expenses $ 598,014 593,056 565,570 553,896 541,859 567,992 NET OPERATING REVENUES ($000) $ 447,879 441,825 447,751 454,434 460,072 471,105 ANNUAL INTEREST($000)(18) $ 97,644 97,644 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.59 4.52 4.59 4.65 4.71 4.82 2003-15 AVG INTEREST COVERAGE (20) 4.27 Year Ending December 31, 2020 2021 2022 2023 - ------------------------ ---------- ---------- ---------- ---------- CONSOLIDATED - ------------ PERFORMANCE Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 Average Capacity Factor (%)(3) 21.0% 20.2% 18.4% 18.4% Contract Energy Sales (GWh)(4) 551 0 0 0 Other Energy Sales (GWh)(4) 10,107 10,274 9,375 9,375 ---------- ---------- ---------- ---------- Total Energy Sales (GWh) 10,657 10,274 9,375 9,375 Fuel Consumption (BBtu) 84,797 82,221 75,165 75,165 Average Net Heat Rate (Btu/kWh)(5) 7,957 8,003 8,018 8,018 SO(2) Allowances Purchased (Tons)(6) 43 42 38 38 NO(X) Allowances Purchased (Tons)(7) 31 28 11 11 COMMODITY PRICES General Inflation (%)(8) 2.60 2.60 2.60 2.60 Contract Electricity Price ($/MWh)(9) 50.29 0.00 0.00 0.00 Other Capacity Price ($/MWh)(10) 84.87 87.74 89.36 91.68 Other Energy Price ($/MWh)(10) 64.45 66.02 67.65 69.40 Fuel Price ($/MMBtu)(11) 6.69 6.85 7.10 7.26 SO(2) Allowances ($/Ton)(12) 232 238 244 251 NO(X) Allowances ($/Ton)(13) 2,498 2,563 2,630 2,698 OPERATING REVENUES ($000) Contract Electricity Revenues Dahlberg 0 0 0 0 Franklin (14) 0 0 0 0 Harris (14) 0 0 0 0 McIntosh 27,698 0 0 0 Stanton 0 0 0 0 Wansley 0 0 0 0 Other Electricity Revenues Dahlberg 67,299 69,661 70,940 72,784 Franklin (14) 208,898 213,547 197,972 203,119 Harris 285,657 282,765 283,337 290,702 McIntosh 217,143 279,817 259,961 266,720 Stanton 86,687 84,437 85,808 88,039 Wansley 257,924 257,133 254,567 261,186 ---------- ---------- ---------- ---------- Total Operating Revenues 1,151,306 1,187,360 1,152,585 1,182,550 OPERATING EXPENSES ($000) Fuel Dahlberg 0 0 0 0 Franklin 92,020 92,989 80,882 82,525 Harris 149,382 146,630 145,457 148,754 McIntosh 112,453 142,923 128,857 131,721 Stanton 51,114 49,309 50,143 51,047 Wansley 133,575 131,388 128,651 131,615 Purchased Power (15) 0 0 0 0 Operations & Maintenance (16) 110,080 116,235 110,399 133,070 Administration and General (17) 43,670 44,408 45,168 45,941 ---------- ---------- ---------- ---------- Total Operating Expenses 692,293 723,881 689,556 724,673 NET OPERATING REVENUES ($000) 459,012 463,479 463,029 457,877 ANNUAL INTEREST($000)(18) 97,644 97,644 97,644 97,644 ANNUAL INTEREST COVERAGE (19) 4.70 4.75 4.74 4.69 2003-15 AVG INTEREST COVERAGE (20)
A-81 FOOTNOTES TO EXHIBIT A-8 The footnotes to Exhibit A-8 are the same as the footnotes for Exhibit A-1, except: 16. Assumed to be 10 percent higher than that assumed in the Base Case, with the exception of the cost of emissions allowances. 17. Assumed to be 10 percent higher than that assumed in the Base Case. A-82 ANNEX B Southern Power Independent Market Expert's Report for the SERC and FRCC Regions May 28, 2003 Southern Power Independent Market Expert's Report for the SERC and FRCC Regions May 28, 2003 Company Confidential (C) PA Knowledge Limited 2003 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 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. i TABLE OF CONTENTS 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 1-3 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 and HR 3406 2-1 2.2.3 Energy Policy Act of 2002 2-1 2.2.4 The Prospect for Energy Legislation 2-2 2.3 State Restructuring 2-2 2.3.1 Alabama 2-2 2.3.2 Florida 2-4 2.3.3 Georgia 2-5 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 2-7 2.4.5 RTOs - Regional Transmission Organizations 2-7 2.4.6 Additional Regulatory and Market Developments 2-11 2.5 Prospects for the Future 2-13 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
ii 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 4-6 4.3.5 Nuclear 4-7 4.4 SO(2)/NOx Emission Allowance Prices 4-7 4.4.1 Sulfur Dioxide Emission Allowance Prices 4-7 4.4.2 Development of NOx 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 5-5 5.3.5 Price Forecasts 5-6 5.3.6 Critical Market Factors 5-9 5.3.7 Dispatch Curves 5-10 5.4 FRCC 5-11 5.4.1 Background 5-11 5.4.2 Power Markets 5-11 5.4.3 Transmission System 5-12 5.4.4 Market Characteristics 5-13 5.4.5 Price Forecasts 5-14 5.4.6 Critical Market Factors 5-17 5.4.7 Dispatch Curves 5-18
iii 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 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 2003-2022. The actual unit specific results were provided to the independent engineer (R.W. Beck) for inclusion in the financial projections for the years 2003-2023.(1) 1.2 ASSET PORTFOLIO DESCRIPTION Southern Power has 4,373 MW in operation, 411 MW that will be in operation in October 2003, and 1,240 MW scheduled to be in operation in June 2005, as summarized in Figure 1-1 and Table 1-1. 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 low fuel, high fuel, and overbuild sensitivity cases analyzed in Chapter 5. Another key fundamental assumption upon 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. TABLE 1-1 REGIONAL MARKET LOCATION OF SOUTHERN POWER GENERATING ASSETS
REGIONAL ASSET TYPE TOTAL CAPACITY(1) MARKET DISTRIBUTION (MW) SERC Gas/Oil - 100% 5,613 FRCC Gas/Oil - 100% 411(2)
(1) SERC capacity rating at 95 degrees Fahrenheit and FRCC capacity rating at 70 degrees Fahrenheit per R.W Beck. (2) Southern Power owns a 65% interest in the 633 MW Stanton facility. FIGURE 1-1 SOUTHERN POWER ASSETS IN GENERATION PORTFOLIO [MAP] DEMAND. Peak demand in the regions is forecasted to grow from 2003 through 2022 at annual compound growth rates of approximately(2): SERC 1.9% FRCC 2.3% - --------- (1) Results for 2023 were held constant in real terms. (2) Source: EIA Annual Energy Outlook 2002. 1-1 FUEL PRICES. Forecasts for natural gas and oil use futures prices in the near term and a consensus fuel price forecast (derived from published fuel price forecasts) in the long term. Delivered prices are then constructed on a regional basis by adding a basis differential.3 The natural gas and oil fuel price forecasts used are found in 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 (2003 through 2005) capacity additions are based on 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. 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. TABLE 1-2 CAPACITY ADDITIONS AND RETIREMENTS(1)
CAPACITY CAPACITY CAPACITY ADDITIONS ADDITIONS ADDITIONS 2003-2005 2006-2022 2006-2022 REGION (MW) (MW) (MW) SERC 23,066 62,905 9,087 FRCC 4,162(2) 26,000 98
- --------- (1) Total capacity at the end of 2002 in each region was: SERC 191,441 MW FRCC 42,347 MW. (2) 3,640 MW of generic CC generation were added in 2005 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 - --------- (3) Regional price differentials were calculated by comparing price history for that location to price history at the Henry Hub. 1-2 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. 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 90-day average ending January 6, 2003 of Henry Hub futures gas prices through December 2005. Prices then decrease linearly to the consensus forecast price in 2007. The oil forecast 90-day average ends January 6, 2003, and goes through December 2004, decreasing linearly to the consensus forecast price in 2006. 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 HIGH FUEL CASE evaluates the effects of higher gas and oil prices represented as a $0.50/MMBtu increase in the 2003 gas and oil base prices with escalation remaining unchanged (coal prices are not changed). - - The LOW FUEL CASE evaluates the effects of lower gas and oil prices represented as a $0.50/MMBtu reduction in the 2003 gas and oil base 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 as the market reaches equilibrium:
2005 2008 SERC 0 MW 7,280 MW FRCC 2,600 MW 0 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 for the base case while Figure 1-3 shows the percentage difference in terms of gross revenues for each sensitivity case as compared to the base case. 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 the relevant generation markets organized by 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 2003-2022. 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 locations of the assets in the generating portfolio are identified on the curves. 1-3 FIGURE 1-2 SUMMARY OF PROJECTED GROSS REVENUES(1) (BASE CASE) [CHART] FIGURE 1-3 GROSS REVENUES(1) (% CHANGE FROM BASE CASE) [CHART] FIGURE 1-4 AVERAGE REGIONAL ALL-IN PRICE FORECASTS(1) ($/MWh) SERC FRCC [CHART] [CHART] 1-4 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 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 2.4.5. 2.2.2 SAFE ACT OF 2001 AND HR 3406 Securing America's Future Energy (SAFE) Act of 2001 is the House's primary energy legislation. SAFE currently does not have an electricity section; however, HR 3406 is now being considered by House leadership as possible House language on electricity to be put forward in the deliberations in 2003 with the Senate over joint energy legislation. HR 3406 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 the North American Electric Reliability Council (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. 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 ENERGY LEGISLATION 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. Due to the significant differences between the two bills and to political maneuvering throughout 2002, the bill is not anticipated to be taken up again until early 2003. 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 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, 23 states plus the District of Columbia have either enacted retail choice restructuring legislation or issued a comprehensive regulatory order on restructuring. Subsequently, six of the 23 have taken action to delay or suspend retail access implementation. The remaining states are either investigating the subject or have done nothing to address the topic. (West Virginia has had no activity since early in 2001 and is counted as not active in Figure 2-1.) 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 2-2 FIGURE 2-1 STATUS OF STATE ELECTRIC INDUSTRY RESTRUCTURING ACTIVITY AS OF JANUARY 2003 [MAP] surrounding it restructure, noting also that some low-cost states had recognized the benefits of 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. In October 2002, FERC granted initial approval to the SeTrans RTO, which will include Alabama, Arkansas, Florida, Georgia, Louisiana, Mississippi, South Carolina, and Texas, and is scheduled to begin operation in 2004. It will be one of the nation's largest RTOs, serving an area with more than 73,000 MW and operating 53,000 miles of transmission with an investment in assets in excess of $9 billion. The 2-3 proposal includes locational marginal pricing and stakeholder advisory committees. The business model is organized around the key governance concept of an independent; incentive-driven, third party Independent System Administrator (ISA) that will manage, but not own the transmission facilities dedicated to the RTO. An ISA was chosen by the SeTrans RTO in November 2002. While the ISA will operate the grid, market monitoring will be performed by a separate independent organization. 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." Action in Florida has centered around building of new power plants. In September 2002, the Florida PSC announced a proposed rulemaking to revise the state's competitive bidding process by requiring utilities to submit bids for projects at the same time as competitors. Under the current competitive bidding rules utilities have always selected their own bids, which are made after all other bids are submitted. There are two proposed RTOs in Florida. GridFlorida RTO began as a for-profit ISO, formed to own and operate assets of FP&L and operate facilities retained by PFC and TECO. FERC conditionally approved GridFlorida in March 2001; however, in November 2001, the PSC ruled that GridFlorida must file as a not-for-profit RTO. GridFlorida filed such a plan for service March 2002, and in August 2002 the Florida PSC approved part of the plan and allowed recovery of the related costs from ratepayers. In October 2002, FERC granted initial approval to the SeTrans RTO, which will include Alabama, Arkansas, Florida, Georgia, Louisiana, Mississippi, South Carolina, and Texas, and is scheduled to begin operation in 2004. It will be one of the nation's largest RTOs, serving an area with more than 73,000 MW and operating 53,000 miles of transmission with an investment in assets in excess of $9 billion. The proposal includes locational marginal pricing and stakeholder advisory committees. The business model is organized around the key governance concept of an independent; incentive-driven, third party Independent System Administrator (ISA) that will manage, but not own the transmission facilities dedicated to the RTO. An ISA was chosen by the SeTrans RTO in November 2002. While the ISA will operate the grid, market monitoring will be performed by a separate independent organization. 2-4 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. In October 2002, FERC granted initial approval to the SeTrans RTO, which will include Alabama, Arkansas, Florida, Georgia, Louisiana, Mississippi, South Carolina, and Texas, and is scheduled to begin operation in 2004. It will be one of the nation's largest RTOs, serving an area with more than 73,000 MW and operating 53,000 miles of transmission with an investment in assets in excess of $9 billion. The proposal includes locational marginal pricing and stakeholder advisory committees. The business model is organized around the key governance concept of an independent; incentive-driven, third party Independent System Administrator (ISA) that will manage, but not own the transmission facilities dedicated to the RTO. An ISA was chosen by the SeTrans RTO in November 2002. While the ISA will operate the grid, market monitoring will be performed by a separate independent organization. 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 (in transition to form MRO - Midwest Reliability Organization, which will replace the MAPP and SPP Regional Reliability Councils) - - 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 (in transition to form MRO - Midwest Reliability Organization, which will replace the MAPP and SPP Regional Reliability Councils) - - WECC - Western Electricity Coordinating Council - AZ-NM-NV - Arizona-New Mexico-Southern Nevada - CA - California - CO-WY - Colorado-Wyoming - NW - Northwest. 2-5 FIGURE 2-2 NERC REGIONS IN THE UNITED STATES [MAP] 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. 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 (WECC) - - the ERCOT Interconnection. 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 2-6 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 Continued concerns with traditional means of grid management, particularly with respect to open access for all wholesale market participants, prompted FERC to issue Order 2000 in December 1999. Order 2000 strongly encourages all transmission-owning entities to place their transmission facilities under the control of independent Regional Transmission Organizations (RTOs) and establishes minimum characteristics and functions of RTOs, leaving 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 - - 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) and 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, three fundamental models 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 New England, New York ISO, California 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, RTO West, and the current PJM structures are all examples of hybrid models. - - TRANSCO MODEL. A single for-profit, independent entity operates and controls a collective pool of transmission assets. The transco would perform all RTO functions. The proposed Alliance RTO, GridSouth and GridFlorida would have operated as transcos. The only RTOs based on the "transco model" still in development at this time are WestConnect and SeTrans, which incorporate a for-profit independent system administrator in their design. 2-7 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. While this schedule has slipped considerably and FERC is no longer publicly establishing dates for RTO formation and operation goals, FERC continues to pressure utilities to identify the RTO in which they will participate. 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 some of the current RTO filings submitted to FERC: FULLY APPROVED RTOS - - MISO. The Midwest ISO (MISO) was conditionally approved by FERC in September 1998 and began regional transmission services on February 1, 2002. FERC approved MISO on December 20, 2001, making it the first fully approved RTO. FERC has subsequently approved a 12.88% return on equity for the transmission assets of all transmission-owning members of MISO. A merger of MISO and SPP was approved by both Boards, pending FERC approval, in April 2002 and a combined tariff was filed with FERC in November 2002. MISO now has five ITCs operating under it. One newer addition is Michigan Electric Transmission Company, the former Consumers Energy transmission system recently purchased by Trans-Elect, an independent company specialized in transmission system operation and construction, and GE Capital. CONDITIONALLY APPROVED RTOS - - PJM INTERCONNECTION. The PJM ISO and its member transmission owners filed to continue current practices, with some additional RTO functions to be assumed by the non-profit ISO. While the utilities would continue to have legal ownership of existing transmission assets, they would be "tenants in common" for future assets. The PJM RTO was conditionally approved on July 12, 2001. However, PJM has not yet been fully approved as an RTO, largely due to issues of geographic scope. PJM includes PJM West, a gridco created from the transmission assets of Allegheny Energy. AEP, a founding member of the former Alliance RTO, has also applied to join PJM as part of PJM West. PJM's scope promises to almost triple over the next year as five former members of the Alliance RTO, AEP, ComEd, Dominion Virginia Power, Illinois Power, and Dayton Power & Light have announced their intention to join PJM. Three of the five have also indicated a preference to join PJM as part of a gridco managed by National Grid. (While Illinois Power is one of the three, the purchase of its transmission assets by Trans-Elect, a MISO member, puts in question the likelihood of this announcement coming to fruition.) To obtain FERC authorization of the new PJM members to the west, PJM and MISO agreed to form a common market by October 2005. One study puts the savings from a combination of MISO, PJM, and SPP at $7 billion over ten years. - - GRIDFLORIDA, LLC. FP&L, PFC, and TECO 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 GridFlorida must file as a not-for-profit RTO. GridFlorida filed such a plan for service on March 20, 2002, and in August 2002 the Florida PSC approved part of the plan and allowed recovery of the related costs from ratepayers. - - GRIDSOUTH LLC. CP&L, Duke Energy, and SCE&G filed to form a for-profit company (in which transmission owners would hold a passive 2-8 FIGURE 2-3 RTOS AND GRIDCOS IN THE UNITED STATES AS OF NOVEMBER 2002 [MAP] interest) to operate their grid facilities. GridSouth was conditionally approved by FERC on March 14, 2002. However, due to uncertainties surrounding RTO development, the GridSouth companies withdrew their applications before the North Carolina and South Carolina Utilities Commissions and are awaiting further direction before re-filing. - - RTO WEST. Most of the utilities covering an area equivalent to the Northwest Power Pool plus Nevada filed to form a hybrid RTO. Under the plan, a non-profit entity (RTO West) would operate the transmission assets owned by eight individual utilities (Avista Corp., Sierra Pacific Resources, Portland General Electric, PacifiCorp, Bonneville Power Authority (BPA), Idaho Power, Northwestern Corp. and Puget Sound) plus British Columbia Hydro. A for-profit gridco, TransConnect, would operate under RTO West and manage the transmission assets of a subset of the investor-owned utilities (IOUs) in RTO West. In September 2002, FERC approved the majority of RTO West's Stage 2 market design and governance proposal. RTO West stated that it plans to be operational in late 2005 or 2006. FERC has recently reduced pressure on the Western RTOs to form one RTO and has announced a process to develop a compatible market design in the Western Interconnect. - - SETRANS RTO. 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. In October 2002, FERC approved SeTrans' petition for declaratory order, generally approving its proposals around governance, delegation of functions to an ITC, and its process for choosing an independent system administrator (ISA). SeTrans subsequently announced that its preferred candidate for ISA is the team of Energy Supply Board of Ireland and Accenture, and SeTrans is negotiating terms exclusively with them. - - WESTCONNECT RTO. WestConnect is a proposed transco that would include the transmission 2-9 assets of Arizona Public Service Company, El Paso Electric Company, Public Service of New Mexico, and Tucson Electric Power Company. The members of WestConnect are essentially the former IOU members of the now dissolved DesertStar ISO organization. In October 2002, FERC approved or conditionally approved elements of WestConnect's proposal to form a for-profit transmission organization while allowing for participation of non-jurisdictional transmission owners (such as Salt River Project and Western Area Power Administration.) WestConnect's RTO proposal included a tariff and protocols covering virtually every aspect of its operations. OTHERS - - CALIFORNIA ISO (CA-ISO). The CA-ISO began operations in March 1998 with the California Power Exchange (Cal-PX) operating markets in parallel. In early 2001, CA-ISO took over market operations as the Cal-PX suspended operations. CA-ISO filed on June 1, 200,1 for certification as an RTO but did not receive approval due in part to concerns about geographic scope. While FERC's initial concept envisioned only one RTO controlling virtually the entire Western Interconnection, FERC recently acknowledged that it might be reasonable to have three organizations - CA-ISO, RTO West, and WestConnect - cooperatively managing the Western Grid. At the same time, FERC is seeking significant changes to CA-ISO governance and market design provisions. CA-ISO implemented Phase 1 of a new market design in October 2002, which includes raising a price cap on electricity bids and a procedure that automatically lowers bids in ISO markets that are "too high." CA-ISO is also working to adopt a day-ahead market and to implement locational marginal pricing as well as to enhance enforcement of market rules. - - ERCOT. While ERCOT is labeled on the RTO map, it is not technically an RTO. Since ERCOT's grid lies entirely within the state of Texas and it has limited interconnections with other grids, ERCOT does not fall under FERC jurisdiction. At the behest of its regulator, the Public Utility Commission of Texas, ERCOT assumed more fully the roles of an ISO in the late 1990s, and today ERCOT is responsible for administering the state's power grid and developing market structure, infrastructure, and business processes to facilitate retail competition in the state. - - NEW YORK ISO (NY-ISO). The existing non-profit ISO and its member transmission owners filed to generally continue current practices, with some additional functions to be assumed by the RTO. The filing held open the possibility of migrating toward a hybrid model if appropriate. The NY-ISO has not yet been approved as an RTO, largely due to issues of geographic scope. A proposed merger between NY-ISO and ISO New England was recently called off by ISO officials due to concerns about unequal benefits of such a merger between the two ISOs. The two ISOs are now focusing on obtaining the same benefits from implementing standard market design (SMD) and resolving seams issues. - - ISO NEW ENGLAND (ISO-NE). The existing New England ISO entity filed its intention to serve as the RTO for the New England region in conjunction with a proposed gridco (New England ITC) in a hybrid RTO structure. Similar to the status of NY-ISO, FERC has stated that ISO-NE does not encompass the geographic scope for RTO approval. In September 2002, FERC accepted market design changes proposed by ISO-NE, including locational marginal pricing, financial transmission rights, and incentives to cut demand during peak periods. Instead of pursuing a previously planned merger with NY-ISO, ISO-NE is now planning to obtain similar benefits through the implementation of SMD. - - SOUTHWEST POWER POOL (SPP). Several southeastern IOUs and municipal utilities filed to have their assets operated by the non-profit RTO. On February 21, 2002, SPP announced that it would seek a definitive agreement to merge with MISO. This merger is proceeding, pending final FERC approval. ITCS/GRIDCOS In addition to the evolving RTOs, there are also a number of ITCs/gridcos that have been formed or are being formed to operate under various RTOs. - - AMERICAN TRANSMISSION COMPANY (ATC). ATC is a for-profit gridco owning the assets of most of the Wisconsin utilities. ATC was the earliest of the ITCs and is now a member of MISO. - - 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. 2-10 - - GRIDAMERICA. Three former members of the disbanded Alliance RTO, FirstEnergy, NIPSCO, and Ameren, elected to form a gridco under the management of National Grid and operating under the MISO umbrella. FERC accepted GridAmerica's bid to become part of MISO in late July 2002, conditioned on the formation of one market by MISO and PJM. MISO and GridAmerica signed an agreement for GridAmerica to operate under MISO as an ITC in November 2002. GridAmerica plans to be operational in April 2003 with 2002 FERC filing approval. - - MICHIGAN ELECTRIC TRANSMISSION COMPANY (METC). METC is an ITC that holds all of the former Consumers Energy transmission assets and operates under MISO. METC is jointly owned by GE Capital and Trans-Elect. - - PJM SOUTH. PJM South is an extension of PJM to accommodate the addition of Dominion Virginia Power to the PJM grid. The agreement signed by PJM and Dominion in June 2002 still requires state approval, but it received conditional federal approval along with the RTO choices of the other former Alliance companies. Dominion has not yet filed a request to form a gridco under PJM but is expected to do so based on the company's earlier transmission filings. - - TRANSLINK TRANSMISSION COMPANY. TRANSLink is a for-profit gridco. Its members consist of Alliant Energy, Corn Belt Power Cooperative, MidAmerican Energy, Nebraska Public Power District, Omaha Public Power District, and Xcel Energy Inc. TRANSLink has filed to operate under MISO. On April 25, 2002, FERC approved TRANSLink, and the ITC has recently entered into agreement on standard market design with MISO, PJM, and SPP. - - PJM WEST. PJM West, a gridco operating under PJM, began operations on April 1, 2002. PJM West currently consists of the transmission assets of Allegheny Energy. More recently, AEP, ComEd, Illinois Power, and Dayton Power & Light have indicated an interest in joining PJM, either as part of the PJM West ITC or by forming their own gridco. DQE continues in discussions with the Pennsylvania regulator to enable the company to join PJM West as well. - - INTERNATIONAL TRANSMISSION COMPANY. Detroit Edison formed the International Transmission Company subsidiary as a gridco that will operate under MISO. - - TRANSCONNECT. TransConnect is currently comprised of three RTO West companies: Avista Corp., Sierra Pacific Resources (Nevada Power Company), and Portland General Electric. The gridco will operate under RTO West. - - NORTHEAST ITC. In January 2001, the for-profit Northeast ITC filed with ISO-NE for gridco status with FERC. Under the filing, Northeast ITC will operate under ISO-NE and will have primary responsibility for existing transmission facilities, offer transmission service under the regional tariff and arrange for construction of new transmission facilities and generator interconnections. 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 REGULATORY AND MARKET DEVELOPMENTS In addition to the RTO efforts, several other recent FERC initiatives and market developments 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 issued a draft Notice of Proposed Ratemaking (NOPR) on SMD during July 2002 with the objective of establishing rules that support genuine wholesale competition, efficient transmission systems, the right pricing signals for transmission investment, reduction in generation and demand, and more customer options. Key elements of SMD include the use of locational marginal pricing (LMP), the separation of market monitoring units from RTO management, and RTO operation of day-ahead and real-time energy markets. Technical conferences on the SMD proposal are planned for January 2003. There is considerable resistance to SMD by a number of state and regional 2-11 groups that are concerned about FERC infringement on state jurisdiction over retail service and regional market differences that require different solutions. 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. With the announcements over the last year by all three concerning their new participation in conditionally RTOs, this order is now less of an issue for the companies. C. GENERATOR INTERCONNECTION STANDARDS In October 2001, FERC issued an advance notice of proposed rule-making (NOPR) with the intent of obtaining industry consensus around a standard generator interconnection agreement and procedures. Reflecting the industry input provided in the interim, on April 24, 2002, FERC issued its NOPR for national generator interconnection standards. FERC proposed to continue its policy of requiring generators to pay the full cost of direct-assignment facilities and initially pay for any additional network facilities needed to accommodate the interconnection. FERC also imposed a 90-day timeline for transmission providers to complete interconnection feasibility studies, system impact studies, and facilities studies that determine whether and how a project will affect the grid. In response, concerns were raised by industry regarding needed regional variations as well as the differing needs of small generators. On August 16, 2002, FERC issued an advance NOPR focused on smaller generation units (defined as less than 20 MW). FERC's stated objective was to finalize rules on interconnection - at least for the larger generators - by the end of 2002. D. MERCHANT TRANSMISSION Over the past several years increasing transmission costs and lack of investment in the grid have created favorable opportunities in the United States for merchant transmission investment. With merchant transmission investment, market forces rather than FERC-approved tariffs will determine the rates charged for transmission service and the facilities' owners will bear the risk of inadequate returns. Merchant transmission facilities have the potential to alter the wholesale generation market landscape in a number of markets in the United States as transmission facilities are put in the most congested markets to tap lower-priced resources previously unavailable. There has been significant activity in the U.S. merchant transmission arena in 2002 and progress has been made on several fronts. Cross Sound Cable, a 330 MW, 24-mile interconnection between Connecticut and Long Island, New York, has begun construction and is expected to enter service in summer 2003. On the West coast, Trans-Elect, Pacific Gas & Electric, and WAPA have received FERC authorization to move forward with the financing and construction of an 84-mile, 500-kV line upgrading Path 15 in California. This line, which is designed to ease the significant constraints impeding power flows between the Northern and Southern California grids, is expected to be operational in late 2004. There have also been major developments recently in three additional merchant transmission projects. Construction is planned for 2004-2005 on the Harbor Cable project, a transmission link between the PJM and New York City grids. On another front, TXU Energy has announced that it will provide funding for the Neptune Transmission System venture, an ambitious 2,000-mile, 4,800 MW link between Canada, New England, New Jersey, and New York City. This funding will enable the venture to complete permitting of the New Jersey to New York leg, achieve financing and start construction with completion of Phase 1 planned for 2005. Phase 1 consists of two 600-MW lines from New Jersey, one to Manhattan, the other to Long Island. In contrast, the Lake Erie Link is on hold as the planned owners seek to confirm the commercial viability of the project. Approval reviews have been halted on this project, which involves the construction of three 325-MW lines from Ontario to three locations on Lake Erie. TransEnergie, a Hydro-Quebec subsidiary, is an owner of this project as well as of the Cross Sound Cable and Harbor Cable ventures. TransEnergie is 2-12 also quite active in both Australia and South America, with two projects in operation in each country and more planned. 2.5 PROSPECTS FOR THE FUTURE The past year significantly altered industry expectations on several fronts and prompted an unprecedented call for strategic review and action across the energy industry. While the California energy crisis continued to reinforce numerous concerns around electricity market deregulation early in the year, the Enron bankruptcy and assorted power marketing scandals magnified these issues and highlighted additional uncertainties in the area of corporate governance, credit, and financial accounting. In the wake of such dramatic upheaval, it is interesting to contemplate the prospects for the future and the potential impacts on merchant generation. Over the past year, the merchant generation industry has experienced deep scrutiny. Analysts and rating agencies are aggressively questioning the viability and business strategies of merchant energy businesses: - - The Enron bankruptcy has magnified the risks inherent in this business sector. Specific concerns over audit practices, trade accounting, and corporate financial practices have surfaced. - - Highly leveraged and cash constrained merchant businesses are under the microscope to demonstrate that projected cash flows will cover debt obligations and preferred stock dividend payments. The current and forward market landscape suggests that holders of merchant generation-based debt and equity positions face an extended period of uncertainty: - - Project plans exceed anticipated capacity requirements in several markets. - - Declining forward prices (electricity and natural gas) signal an expectation that capacity is adequate in several regions. - - Re-regulation initiatives in several areas are underway in response to the economy, California, and Enron. - - Contracting debt tenor combined with scheduled project re-financings suggests an impending credit crunch. - - Recent equity market movements reflect a sea change in the perception of risk in merchant generation. 2-13 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 generating capacity database (MerCap) 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. 4. 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. 5. REFINE PLANT DISPATCH WITH VOLATILITY ANALYSIS (OPTIONAL). Depending on the type and location of plants in question, PA refines the price forecast to account for price volatility by projecting multiple price paths calibrated to historical price patterns. This optional step provides 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 MerCap 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. 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 spreads - - 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 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(4) 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.(5) 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. - --------- (4) 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). (5) 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. 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 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 2006, based on a detailed review of the announced plans of developers (tracked in PA's MerCap database) and utilities (contained in planning council reports). Capacity additions after 2005 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. 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 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 2005 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 2003, 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. 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 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 belPA 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 - - 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 2003 through 2022 is summarized in Table 4-1. TABLE 4-1 PROJECTED AVERAGE ANNUAL LOAD GROWTH RATES(1) (2003-2022)
REGION DEMAND ENERGY - --------------------- ------ ------ SERC 1.9% 1.9% 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 by 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. 4-1 TABLE 4-2 HENRY HUB PROJECTIONS(1) (REAL 2001 $/MMBTU)
AVERAGE ANNUAL GROWTH 2003 2005 2010 2015 2020 RATE ---- ---- ---- ---- ---- ------- EIA 2.67 2.99 3.21 3.45 3.67 1.9% GTI 2.94 2.61 2.70 2.51 3.01 0.1% DRI/WEFA 3.20 3.16 3.06 3.09 3.14 (0.1)% S&P 3.44 3.16 3.24 3.41 3.67 0.4% CONSENSUS 3.06 2.98 3.05 3.11 3.37 0.6%
(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 ---- ------------- 2003 4.06 2004 3.77 2005 3.54
(1) Based on previous 90 calendar day closing prices ending 01/06/03. FIGURE 4-1 HENRY HUB GAS PRICES 1993-2002 [CHART] 4.3.1 NATURAL GAS The primary inputs into the analysis were forecasts from the Energy Information Administration (EIA),(6) The Gas Technology Institute (GTI), DRI/WEFA, and Standard & Poor's (S&P). 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 2005 using a 90-day average of NYMEX futures prices. Natural gas prices are expected to trend back to the long-run consensus by 2007. Table 4-3 displays the near-term price projection. Figure 4-1 shows historical gas prices for the Henry Hub from January 1993 through December 2002. There has been unprecedented volatility over the past two years. In the past 12 months alone, pricing has shifted from below the long-term consensus forecast to heights well above the long-term consensus forecast. 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 LP. 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 - ------------ (6) 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 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)
2003 2005 2010 2015 2020 ---- ---- ---- ---- ---- SERC-Southern 4.64 4.11 3.63 3.67 3.90 FRCC 4.72 4.19 3.71 3.75 3.98
(1) Gas prices include LDC charges and other delivery charges. 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 2004, rather than the long-run equilibrium price. In this case, prices are expected to trend back to the long-run consensus by 2006. 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 2003 2005 2010 2015 2020 RATE ----- ----- ----- ----- ----- -------- EIA 22.87 23.22 23.86 24.52 25.21 0.6% GTI 22.00 19.12 19.12 19.12 19.12 (0.8)% DRI/WEFA 23.46 24.21 24.54 25.93 27.42 0.9% CONSENSUS 22.78 22.18 22.51 23.19 23.92 0.3%
(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 ---- ---------------- 2003 25.04 2004 22.24 2005(2) 22.21
(1) Based on previous 90 calendar day closing prices ending 01/06/03. (2) Average between futures price 2004 and long-term consensus 2006. TABLE 4-7 DELIVERED NO. 2 FUEL OIL PRICE (2001 $/MMBTU)
2003 2005 2010 2015 2020 ---- ---- ---- ---- ---- SERC-Southern 5.70 5.10 5.15 5.30 5.46 FRCC 5.82 5.21 5.27 5.41 5.57
TABLE 4-8 DELIVERED NO. 6 FUEL OIL PRICE (2001 $/MMBTU)
2003 2005 2010 2015 2020 ---- ---- ---- ---- ---- SERC-Southern 3.57 3.16 3.20 3.30 3.40 FRCC 3.70 3.30 3.34 3.44 3.54
4-4 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(7) 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(8) 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. 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 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. - ------------ (7) Includes 0.3% residual oil, low sulfur No. 2 Fuel Oil, and jet fuel. (8) "Free on Board," indicating that the price includes the costs of loading coal onto a train, truck, or barge. 4-5 Prices for most types of coal are expected to decline fairly steeply from the extraordinary 2001 levels over the following three years.(9) 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 trend of declining real coal prices involves PRB coals.(10) Due to the very low mining costs and 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.(11) 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 that 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. 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 - ------------ (9) 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. (10) 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). (11) 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 and winter capabilities. Monthly energy patterns were developed from nine 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. In 2003 and 2004, PA overrides the consensus emission allowance forecast with forward prices from Cantor Fitzgerald, current as of late December 2002. Thus, the price of SO(2) allowances starts at $132 per ton in 2003, 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) ---- ----- 2003(1) $132 2005(2) $193 2008 $286 2010 $322 2015 $383 2020 $317
(1) Based on forward market prices. (2) Average of 2004 forwards and 2006 consensus. PA's forecast of SO(2) allowance prices was developed using its proprietary Multi-Pollutant Optimization Model (MPOM). MPOM is a linear programming model that 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 that will meet the national 4-7 SO(2) emissions caps(12) 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 2003(1) $4,760 SIP CALL 2004(1) $4,363 2008 $3,415 2010 $2,822 2015 $3,149 2020 $2,423
(1) Based on forward market prices. 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).(13) 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. The marginal NO(x) control technology that is required under the OTR regulations is Selective Non-Catalytic Reduction (SNCR). As shown in 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 that 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 2005 and 2015, the NO(x) allowance price is expected to remain within a relatively narrow range of $3,781/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. - ------------ (12) 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. (13) 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 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 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. FIGURE 4-2 TRANSFER CAPABILITY(1) (MW) [CHART] 4-9 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 within transmission organizations. This assumes that the current pancaking(14) 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 in the Eastern Interconnection and $2.00/MWh in WECC. 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 2005 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 2006 through 2022, 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 2006, 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. - ------------ (14) Pancaking transmission rates result when power crosses more than one transmission system and is subject to two or more tariffs. 4-10 TABLE 4-12 CAPACITY ADDITIONS (MW), 2003-2005
SIZE UNIT ON-LINE DEVELOPER (PLANT) (MW)(1) TYPE YEAR ----------------- ------- ----- ------- SERC -- TOTAL = 23,066 MW Calpine (Carville) 440 Cogen 2003 Calpine (Decatur) 794 CC 2003 Calpine (Hillabee) 770 CC 2003 Calpine (Morgan) 790 CC 2003 Calpine (Santa Rosa) 240 CC 2003 Choctaw Gas Generation LLC (Choctaw) 787 CC 2003 Cogentrix (Caledonia) 830 CC 2003 Cogentrix (Southaven) 866 CC 2003 Duke (Mill Creek) 640 CT 2003 FPL Group (Calhoun) 616 CT 2003 Intergen (Cottonwood) 1,200 CC 2003 Intergen (Magnolia) 900 CC 2003 Occidental Chemical (Taft) 778 Cogen 2003 Oglethorpe Power (Talbot County 2) 216 CT 2003 Panda (El Dorado) 2,200 CC 2003 Progress (Effingham CT) (2) 314 CT 2003 Progress (Washington) 608 CT 2003 Reliant (French Camp) 800 CC 2003 Southern Company (Harris) 1,256 CC 2003 Southern Company (Franklin 2) 624 CC 2003 Tenaska (Coral) 900 CC 2003 Williams (Memphis Refinery (Phase I)) 265 CC 2003 Calpine (Columbia) 550 Cogen 2004 Oglethorpe Power (Chattahoochee) 468 CC 2004 Progress (Effingham CC) 490 CC 2004 Progress (Rowan 4&5 CC) 473 CC 2004 SCE&G (Hardeeville) 875 CC 2004 Tenaska (Virginia Station) 885 CC 2004 Tractebel (Hot Springs) 720 CC 2004 Calpine (Washington Parish) 577 CC 2005 East Kentucky Power Cooperative (Gilbert) 268 Coal 2005 Southern Power (McIntosh 10&11) 1,240 CC 2005 FRCC -- TOTAL = 4,162 MW Calpine (Auburndale) 115 CT 2003 TECO (Bayside Repower) 900 CC 2003 Florida Power Corporation (Hines Unit 2) 495 CC 2003 Calpine (Osprey Energy Center) 529 CC 2003 Florida Power & Light Company (Sanford) 1,000 CC 2003 Southern Co & OUC (Stanton A) 633 CC 2003 Orion Power Holdings (Atlantic CPV) 250 CC 2004 City of Lakeland (McIntosh Unit 4) 240 Coal 2004
(1) Summer rating. (2) Retires when combined cycle comes online. 4-11 TABLE 4-13 CAPACITY ADDITIONS AND RETIREMENTS (MW) 2006-2022
CC CT CUMULATIVE PLANTS PLANTS RETIRE- CAPACITY YEAR(1) ADDED ADDED MENTS(2) ADDITIONS -------- ------- ------ -------- ---------- SERC 2006 0 0 (7,249) (7,249) 2007 0 0 (9) (7,258) 2008 0 0 0 (7,258) 2009 4,160 0 0 (3,098) 2010 4,680 0 0 1,582 2011 5,200 0 (76) 6,706 2012 4,160 0 (116) 10,750 2013 4,680 0 (79) 15,351 2014 4,680 0 (42) 19,989 2015 4,160 0 0 24,149 2016 3,120 1,035 0 28,304 2017 4,160 345 0 32,809 2018 2,600 1,725 0 37,134 2019 4,160 0 (280) 41,014 2020 4,160 0 (116) 45,058 2021 4,680 0 (391) 49,347 2022 5,200 0 (729) 53,818 ===== ====== ===== ====== ====== TOTAL 59,800 3,105 (9,087) 53,818 FRCC 2006 1,560 0 0 1,560 2007 1,040 0 0 2,600 2008 1,040 0 0 3,640 2009 2,080 0 0 5,720 2010 1,560 0 0 7,280 2011 1,560 0 0 8,840 2012 1,040 0 0 9,880 2013 1,560 0 0 11,440 2014 2,080 0 0 13,520 2015 1,560 0 0 15,080 2016 1,040 0 0 16,120 2017 1,560 0 (1) 17,679 2018 1,560 0 0 19,239 2019 2,080 0 (32) 21,287 2020 1,560 0 0 22,847 2021 1,560 0 (65) 24,343 2022 1,560 0 0 25,903 ===== ====== ===== ====== ====== TOTAL 26,000 0 (98) 25,903
(1) 2003 through 2005 additions are shown in Table 4-12. 3,640 MW of CC generation were added to FRCC in 2005. (2) Retirements are assumed to occur on January 1 of year. SERC has no retirements in 2003-2005. FRCC has no retirements in 2003-2005. 4-12 4.7 FINANCIAL ASSUMPTIONS 4.7.1 GENERIC PLANT CHARACTERISTICS The starting points for the DCF calculations 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 2006. Capital costs per kW of output are assumed to decrease at 1% per annum (real 2001 $) to reflect technological improvements in turbine design and plant construction. Table 4-15 indicates the assumed schedule and effect of technology improvement on new unit heat rates. 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. TABLE 4-14 GENERATING CHARACTERISTICS OF NEW UNITS (REAL 2001 $)
CAPITAL FIXED COST O&M(1) VARIABLE SIZE ($/kW) ($/kW-YEAR) O&M ($/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)
2003 2004-2008 2009-2013 2014-2018 2019+ --------- ---------- ---------- ---------- --------- CC 6,950 6,811 6,675 6,541 6,411 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. 4-13 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 (including the base case) 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 90-day average ending January 6, 2003, of Henry Hub futures gas prices through December 2005. Prices then decrease linearly to the consensus forecast price in 2007. The oil forecast 90-day average ends January 6, 2003, and goes through December 2004, decreasing linearly to the consensus forecast price in 2006. 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. - - The HIGH FUEL CASE evaluates the effects of higher gas and oil prices represented as a $0.50/MMBtu increase in the 2003 gas and oil base prices with escalation remaining unchanged (coal prices are not changed). - - The LOW FUEL CASE evaluates the effects of lower gas and oil prices represented as a $0.50/MMBtu reduction in the 2003 gas and oil base 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 when the market reaches equilibrium. Based on announced merchant projects, PA assumed additional capacity was added in SERC in 2008 and FRCC in 2005. (See Table 5-2.) Subsequent to this period of capacity abundance, as the regions experience load growth, PA assumed the markets eventually return to economic equilibrium.
TABLE 5-2 OVERBUILD CASE MERCHANT PLANT CAPACITY ADDITIONS(1) (MW) ------------------------------------------------------- REGION 2005 2008 ------------------------- -------------- -------------- SERC 0 7,280 FRCC 2,600 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 5-1 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. 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 2003. 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 forecast 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 historical electricity price information obtained from Bloomberg LP. The values are the on-peak daily index values for April 1999 through December 2002 for the regions of interest. Figure 5-1 Historical Electricity Prices (Daily On-Peak Index) (nominal $) [Chart] 5-2 5.3 SERC 5.3.1 BACKGROUND 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. SERC includes 37 members and 27 associate members and covers an area of approximately 464,000 square miles over 13 states. SERC is also the largest of the NERC regions measured by total generation and total load. From a national perspective, SERC lags behind the Northeast, the Midwest, 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. The SERC region is subdivided into four pricing areas: Entergy (SERC-Entergy), Southern Company (SERC-Southern), Tennessee Valley Authority (SERC-TVA), and Virginia and Carolinas (SERC-VACAR). Southern Power's plants in SERC are located in the Southern pricing area. (See Figure 5-2.) 5.3.2 POWER MARKETS 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. FIGURE 5-2 GENERATION ASSETS IN THE SERC REGION [Chart] The SERC Executive Committee has created 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 MIC may be responsible for drafting new market procedures, should SERC establish a formalized regional power market at some point in the future. The recent approval of the SeTrans RTO by FERC on October 10, 2002, would contribute to the formation of a regional market power market. 5.3.3 TRANSMISSION SYSTEM Several of the largest utilities in the United States (Southern Company, Entergy, and the TVA) dominate SERC'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. 5-3 Initial efforts to form RTOs were not successful. Entergy had proposed the creation of an independent transmission company to operate and manage its transmission assets in Arkansas, Mississippi, Texas, and Louisiana, and filed this proposal with FERC for approval. The Louisiana PSC moved to block the Entergy TRANSCO, citing possible higher costs for retail customers due to the removal of Entergy's transmission grid from state jurisdiction. In addition, Dominion Resources initially joined the Alliance RTO, which failed to get FERC approval, so on June 26, 2002, Dominion signed a memorandum of understanding with PJM to have Dominion's 6,000-mile transmission grid in Virginia and North Carolina operated on a regional basis by PJM. FERC approved the companies' decisions and required PJM to complete the formation of a single market over the two RTOs by October 1, 2004. According to a PJM presentation on October 23, 2002, Dominion will be integrated into PJM by October 1, 2003. At the end of 2000, Southern Company initiated the formation of a regional RTO called the SeTrans RTO. This organization now includes members such as Entergy Corporation, Cleco Power LLC, Dalton Utilities, Georgia Transmission Corporation, JEA - Jacksonville (FL), the Municipal Electric Authority of Georgia, Sal Rayburn G&T Electric Cooperative, Santee Cooper, Southern Company, and the City of Tallahassee. Once operational, it will be one of the nation's largest RTOs, serving an area with more than 73,000 MW and operating 53,000 miles of transmission with an investment in assets in excess of $9 billion. On October 10, 2002, FERC granted approval to initial plans for SeTrans RTO. The proposal includes locational marginal pricing and stakeholder advisory committees. The business model is organized around the key governance concept of an independent; incentive-driven, third party Independent System Administrator (ISA) that will manage, but not own the transmission facilities dedicated to the RTO. An ISA was chosen by the SeTrans RTO in November 2002. While the ISA will operate the grid, market monitoring will be performed by a separate independent organization. On November 14, 2002, the Louisiana PSC asked FERC to reconsider and reverse its approval. The PSC said that it allows the RTO to evade the jurisdiction of retail regulators over transmission planning and investment issues that would harm ratepayers and impair the reliability of the grid. The PSC questioned the use of locational marginal pricing and firm transmission rights. 5-4 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 55% of the energy produced and 36% of the installed capacity in the region. Nuclear facilities produce 27% of the energy and account for 15% of the installed capacity. Gas- and oil-fired units produce 12% of the energy and account for 40% 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 - 2003 [Chart] B. MARKET DYNAMICS Southern Power's assets evaluated in this report located in SERC include gas-fired plants representing 5,613 MW of capacity. Figure 5-4 illustrates the load and resource balance for SERC through the end of the study period. Peak demand in the SERC market is forecasted to grow at an annual compound rate of approximately 1.9% from 2003 through 2022. A required system-wide reserve margin of 15% is assumed through 2006; it drops to 13% from 2007 through the remainder of the study period. Historical prices for SERC were presented in Figure 5-1. FIGURE 5-4 SERC LOAD AND RESOURCE BALANCE [Chart] 5-5 5.3.5 PRICE FORECASTS A. BASE CASE MARKET RESULTS The base case models near-term fuel prices based on recent actual spot prices and futures prices through December 2005, decreasing linearly to the long-term consensus view by 2007. 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 $1.60/MWh and $6.00/MWh. Base case forecasts of compensation for capacity, energy prices, 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] 5-6 B. SENSITIVITY CASES ANALYSIS The all-in prices for the low fuel, high fuel and overbuild sensitivity cases described in Section 5.2 are shown in Figure 5-6 for the SERC-Southern pricing area. 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 $2.20 to $3.00/MWh, as compared to 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 added in 2008 depresses market prices by up to $2.60/MWh in 2009 before returning to equilibrium in 2011. FIGURE 5-6 SERC-SOUTHERN SENSITIVITY CASES ALL-IN PRICE FORECASTS(1) ($/MWH) [Chart} SERC-SOUTHERN--ALL-IN PRICE FORECASTS
YEAR BASE CASE HIGH FUEL LOW FUEL OVERBUILD - ---- --------- --------- -------- --------- 2003 37.50 40.30 34.70 37.50 2004 35.70 38.60 33.00 35.70 2005 34.60 37.40 31.90 34.40 2006 33.50 36.60 30.70 33.40 2007 32.90 35.70 30.20 32.90 2008 33.50 36.50 31.00 31.50 2009 34.90 37.40 32.40 32.30 2010 34.90 37.40 32.70 34.40 2011 35.90 38.20 33.50 35.50 2012 36.10 38.30 33.60 35.90 2013 35.60 38.00 33.40 35.60 2014 35.10 37.50 32.90 35.10 2015 34.70 37.20 32.50 35.10 2016 34.60 37.10 32.60 34.90 2017 34.90 37.30 32.40 35.10 2018 34.90 37.50 32.50 35.20 2019 35.60 38.20 32.90 35.80 2020 35.50 38.10 32.80 35.80 2021 35.50 38.20 32.70 35.80 2022 35.00 37.80 32.40 35.20
(1) Results are expressed in real 2001 dollars. 5-7 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 2003-2022. FIGURE 5-7 GROSS MARGINS FOR SOUTHERN POWER'S SERC ASSETS BY CASE(1) (REAL 2001 $) [Chart] 5-8 5.3.6 CRITICAL MARKET FACTORS A. SPARK SPREADS Figure 5-8 shows the spark spreads, which are the net prices of electricity after fuel costs for combined cycles. Spark spreads are calculated by subtracting fuel costs from the market clearing prices. Variable O&M costs are not included in PA's calculation of spark spreads. PA used a heat rate of 6,950 Btu/kWh for the spark spreads. The spark spreads for SERC in Figure 5-8 are depressed in early years due to the surplus of merchant capacity. As the market absorbs the excess capacity and moves to equilibrium, the spark spread for the base case hovers between $11/MWh and $14/MWh. B. GAS PRICES Natural gas accounts for 37% and 12% of capacity and energy, respectively, in the SERC region in 2003. These resources significantly influence the marginal cost of energy. By 2022, natural gas is the marginal fuel over 88% 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 new units. Because the market is in an overbuild situation, the fall in gas prices in 2003-2007 does not trigger a significant drop in all-in prices. All-in prices hover around $35/MWh in the long term as the consensus gas forecast is around $3.30/MMBtu. C. NEW CAPACITY For 2003-2005, over 23,000 MW of merchant capacity is expected to be added to the SERC region. Capital investment in merchant generation is treated as a sunk cost; therefore, the merchant surplus creates an overbuild situation that 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-SOUTHERN -- SPARK SPREADS & FUEL ON THE MARGIN [Chart] FIGURE 5-9 SERC-SOUTHERN -- FUEL FORECASTS & MARKET RESULTS [Chart] FIGURE 5-10 SERC-SOUTHERN -- LOAD & CAPACITY DEMAND [Chart] 5-9 capacity market. The average annual load growth rate of 1.9% 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 first ten years of the base case. 5.3.7 DISPATCH CURVES Dispatch curves for the SERC region for 2006 and 2012 are shown in Figure 5-11. These curves order generation plants based on short-run variable cost (fuel and O&M). The dispatch curves show the annual average marginal dispatch cost of Southern Power's assets as compared to the other generators in the market. FIGURE 5-11 SERC DISPATCH CURVES FOR 2006 AND 2012 SERC - 2006 SERC - 2012 [CHART] 5-10 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 activity in the establishment of retail competition. There are currently 32 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, IOUs serve almost 80% of the demand in FRCC. In addition, a number of small municipal utilities in the state purchase power from other utilities under wholesale power agreements. The region has twelve separate control areas and covers about 50,000 square miles. As in other states dominated by IOUs, the electricity market in Florida 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. Figure 5-12 shows the FRCC region and the location of Southern Power's generating asset. 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 10% of Florida's electric capacity is served by non-utility generators.(15) The Florida Public Service Commission (FPSC) encouraged the use of the wholesale market for inter-utility sales through the FIGURE 5-12 GENERATION ASSETS IN THE FRCC REGION [MAP} 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 decision by FPL, FPC, and TECO to maintain a 20% reserve margin, there has been considerable interest by merchant plant developers. Although independent energy companies have made 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. Utilities were required to issue requests for proposals (RFPs) for steam-driven generation capacity additions exceeding 75 MW. In September 2002, the FPSC announced a proposed rulemaking to revise the state's competitive bidding process by requiring utilities to submit bids for projects at the same time as - ---------- (15) 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. 5-11 competitors, thereby precluding utilities from bidding after competitors' bids were submitted. In January, 2003, the FPSC revised bidding rules for IOUs constructing new plants. To increase transparency and the number of bidders, utilities inviting RFPs will be required to divulge in advance the methodology and criteria used to evaluate bids. Bidders will be able to take objections to RFPs to the FPSC for expedited dispute resolution. 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. Joint studies of the Florida/Southern transmission interface indicate that adequate capability exists for additional power imports into FRCC above the approximately 1,600 MW currently being imported on a firm basis. 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 FPSC 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 FPSC revising the form and function of Grid Florida to address the perceived problems. Specifically, Grid Florida filed to be a non-profit ISO structure. Pursuant to a workshop discussing the March 2002 filing and subsequent comments, the FPSC issued an order in September 2002 determining GridFlorida's compliance with the FPSC's earlier order and asked GridFlorida to address market design issues by late September 2002. Subsequently, reconsideration motions were filed by parties and responses filed by the RTO applicants. In October 2002, the Office of Public Counsel filed an administrative appeal of the FPSC's order with the Florida Supreme Court. 5-12 5.4.4 MARKET CHARACTERISTICS A. FUEL MIX As illustrated in Figure 5-13, 62% of the generating capacity in FRCC consists of gas- and oil-fired units with coal accounting for 23%. Nuclear facilities account for 8% 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 26% of the energy produced. The fuel producing the largest portion of energy in FRCC is coal at 45%. The fuel mix of FRCC plants is unique due to the mix of baseload and peaking capacity and the region's highly constrained gas distribution network. Both constraints allow for opportunities and uncertainty around the delivery and potential redirection of fuel into load pockets to take advantage of valuation discrepancies. As FRCC continues to develop, these gaps will be closed and financially firm contracts and distributed generation will absorb the uncertainty. FRCC is also unique in that it needs a significant amount of gas pipeline capacity. Combined cycle units are purchasing pipeline capacity at significant rates (~$30/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 the building of combined cycle units 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 5-14 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% from 2003 through 2022. 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. With this characteristic in load shape, peaking plants are able to take advantage of two periods of high-priced occurrences. FIGURE 5-13 FRCC FUEL MIX ENERGY AND CAPACITY - 2003 [MAP] FIGURE 5-14 FRCC LOAN AND RESOURCE BALANCE [MAP] 5-13 5.4.5 PRICE FORECASTS A. BASE CASE MARKET RESULTS The base case models near-term fuel prices based on recent actual spot prices and futures prices through December 2005 decreasing linearly to the long-term consensus view by 2007. 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 $4.00/MWh and $7.20/MWh. Base case forecasts of compensation for capacity, energy prices, and all-in prices are shown in Figure 5-15 for the FRCC region. FIGURE 5-15 FRCC COMPENSATION FOR CAPACITY, ENERGY, AND ALL-IN PRICE FORECASTS(1) FRCC--MARKET RESULTS [Chart]
COMPENSATION ENERGY ALL-IN FOR CAPACITY PRICE PRICE YEAR ($/KW-YR) ($/MWH) ($/MWH) - ---- ------------ ------- ------- 2003 62.90 39.80 47.00 2004 61.40 37.60 44.60 2005 43.70 36.30 41.30 2006 42.70 34.80 39.60 2007 37.00 33.80 38.00 2008 35.00 33.90 37.90 2009 39.70 33.50 38.00 2010 43.60 32.90 37.90 2011 46.10 32.90 38.10 2012 46.20 32.90 38.10 2013 51.20 32.30 38.20 2014 53.40 32.00 38.10 2015 55.70 31.70 38.00 2016 57.30 31.60 38.20 2017 56.90 31.90 38.40 2018 56.50 31.90 38.40 2019 56.10 32.30 38.70 2020 55.70 32.30 38.70 2021 55.30 32.30 38.60 2022 54.90 31.80 38.10
5-14 B. SENSITIVITY CASES ANALYSIS The all-in prices for the low fuel, high fuel, and overbuild sensitivity cases described in Section 5.2 are shown in Figure 5-16 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 $2.60 to $3.20/MWh, as compared to the base case. Conversely, the low fuel case yields consistently lower all-in prices, of the same magnitude, as compared to the base case. In the overbuild case, the additional merchant surplus added in 2005 depresses market prices by $3.20/MWh in that year before returning to equilibrium in 2008. FIGURE 5-16 FRCC SENSITIVITY CASES ALL-IN PRICE FORECASTS(1) ($/MWH) FRCC--ALL-IN PRICE FORECASTS [CHART]
YEAR BASE CASE HIGH FUEL LOW FUEL OVERBUILD - ---- --------- --------- -------- --------- 2003 47.00 50.00 43.80 47.00 2004 44.60 47.80 41.50 44.60 2005 41.30 44.00 38.50 38.10 2006 39.60 42.40 36.90 37.70 2007 38.00 40.60 35.40 37.00 2008 37.90 40.60 35.30 37.70 2009 38.00 40.70 35.40 38.00 2010 37.90 40.60 35.40 38.00 2011 38.10 40.80 35.50 38.20 2012 38.10 40.90 35.50 38.30 2013 38.20 41.00 35.50 38.30 2014 38.10 40.90 35.40 38.20 2015 38.00 40.70 35.40 38.20 2016 38.20 41.10 35.70 38.40 2017 38.40 41.40 35.70 38.80 2018 38.40 41.30 35.60 39.00 2019 38.70 41.90 35.90 38.70 2020 38.70 41.80 35.90 38.70 2021 38.60 41.60 35.70 38.80 2022 38.10 41.10 35.40 38.30
5-15 C. PROJECTED GROSS MARGINS Figure 5-17 shows projected gross margins for Southern Power's FRCC assets evaluated in this report for the base case and sensitivity cases for the period 2004-2022. FIGURE 5-7 GROSS MARGINS FOR SOUTHERN POWER'S FRCC ASSETS BY CASE(1) (REAL 2001 $) [Chart] 5-16 5.4.6 CRITICAL MARKET FACTORS A. SPARK SPREADS Figure 5-18 shows the spark spreads, which are the net prices of electricity after fuel costs for combined cycles. Spark spreads are calculated by subtracting fuel costs from the market clearing prices. Variable O&M costs are not included in PA's calculation of spark spreads. PA used a heat rate of 6,950 Btu/kWh for the spark spreads. The spark spreads for FRCC in Figure 5-18 decline in early years because of the increase in natural gas as the marginal fuel. Once the market reaches equilibrium in 2005, the spark spreads remain consistent at $14/MWh for the base case. B. GAS PRICES Natural gas accounts for 36% and 14% of capacity and energy, respectively, in the FRCC region in 2003. These resources significantly influence the marginal cost of energy. By 2022, natural gas is the marginal fuel nearly 88% of the time (see Figure 5-18). 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 5-19 shows the fuel forecasts overlaid on the base case price results. The fuel forecasts represent the delivered natural gas prices for new units. Because the FRCC market is not overbuilt in the early years, the high gas prices yield correspondingly high all-in prices, which fall as the market trends to consensus gas prices in 2007. C. NEW CAPACITY For 2003-2005, over 4,100 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 5-20. D. LOAD GROWTH Due to the factors described above, load growth is a key driver in the FRCC region. A higher load growth allows any merchant capacity to be absorbed in the capacity market. The average annual load growth 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 5-20 illustrates the load FIGURE 5-18 FRCC -- SPARK SPREADS & FUEL ON THE MARGIN [Chart] FIGURE 5-19 FRCC -- FUEL FORECASTS & MARKET RESULTS [Chart] FIGURE 5-20 FRCC -- LOAD & CAPACITY DEMAND [Chart] 5-17 growth and reserve margin assumptions for the first ten years of the base case. 5.4.7 DISPATCH CURVES Dispatch curves for the FRCC region for 2006 and 2012 are shown in Figure 5-21. These curves order generation plants based on short-run variable cost (fuel and O&M). The dispatch curves show the annual average marginal dispatch cost of Southern Power's asset as compared to the other generators in the market. FIGURE 5-21 FRCC DISPATCH CURVES FOR 2006 AND 2012 FRCC--2006 FRCC--2012 [Chart] 5-18 $575,000,000 SOUTHERN POWER COMPANY A SUBSIDIARY OF (SOUTHERN COMPANY LOGO) OFFER TO EXCHANGE ALL OUTSTANDING 4.875% SENIOR NOTES, SERIES C DUE JULY 15, 2015 FOR 4.875% SENIOR NOTES, SERIES D DUE JULY 15, 2015 (REGISTERED UNDER THE SECURITIES ACT OF 1933) UNTIL , 200 , 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. PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS Section 145 of Title 8 of the Delaware Code gives a corporation power to indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. The same section also gives a corporation power to indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise against expenses (including attorneys' fees) actually and reasonably incurred by him in connection with the defense or settlement of such action or suit if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the Court of Chancery or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Court of Chancery or such other court shall deem proper. Also, the section states that, to the extent that a present or former director or officer of a corporation has been successful on the merits or otherwise in defense of any such action, suit or proceeding, or in defense of any claim, issue or matter therein, he shall be indemnified against expenses (including attorneys' fees) actually and reasonably incurred by him in connection therewith. The By-Laws of Southern Power Company provide in substance that no present or future director or officer of the corporation, or his heirs, executors or administrators, shall be liable for any act, omission, step or conduct taken or had in good faith, which is required, authorized or approved by any order or orders issued pursuant to the Public Utility Holding Company Act of 1935, as amended, the Federal Power Act, as amended, or any federal or state statute or municipal ordinance regulating the corporation or its parent by reason of their being holding or investment companies, public utility companies, public utility holding companies or subsidiaries of public utility holding companies. In any action, suit or proceeding based on any act, omission, step or conduct, as in this paragraph described, the provisions hereof shall be brought to the attention of the court. In the event that the foregoing provisions of this paragraph are found by the court not to constitute a valid defense on the grounds of not being applicable to the particular class of plaintiff, each such director and officer, and his heirs, executors and administrators, shall be reimbursed for, or indemnified against, all expenses and liabilities incurred by him or imposed on him, in connection with, or arising out of, any such action, suit or proceeding based on any act, omission, step, or conduct taken or had in good faith as in this paragraph described. Such expenses and liabilities shall include judgments, court costs and attorneys' fees. The By-Laws of Southern Power Company further provide as follows: "Each person who is or was a director of the corporation or officer or employee of the corporation holding one or more positions of management through and inclusive of managers (but not positions below the level of such managers) (such positions being hereinafter referred to as "Management Positions") and who was or is a party or was or is threatened to be made a party to any threatened, pending or completed claim, II-1 action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he is or was a director of the corporation or officer or employee of the corporation holding one or more Management Positions, or is or was serving at the request of the corporation as a director (or the equivalent), alternate director, officer, employee, agent or trustee of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, shall be indemnified by the corporation as a matter of right against any and all expenses (including attorneys' fees) actually and reasonably incurred by him and against any and all claims, judgments, fines, penalties, liabilities and amounts paid in settlement actually incurred by him in defense of such claim, action, suit or proceeding, including appeals, to the full extent permitted by applicable law. The indemnification provided by this section shall inure to the benefit of the heirs, executors and administrators of such person. Expenses (including attorneys' fees) incurred by a director of the corporation or officer or employee of the corporation holding one or more Management Positions with respect to the defense of any such claim, action, suit or proceeding may be advanced by the corporation prior to the final disposition of such claim, action, suit or proceeding, as authorized by the board of directors in the specific case, upon receipt of an undertaking by or on behalf of such person to repay such amount unless it shall ultimately be determined that such person is entitled to be indemnified by the corporation under these bylaws or otherwise; provided, however, that the advancement of such expenses shall not be deemed to be indemnification unless and until it shall ultimately be determined that such person is entitled to be indemnified by the corporation." Southern Power Company has an insurance policy covering its liabilities and expenses which might arise in connection with its lawful indemnification of its directors and officers for certain of their liabilities and expenses and also covering its officers and directors against certain other liabilities and expenses. II-2 ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a) Exhibits
EXHIBIT NUMBER DESCRIPTION - ------- ----------- 1.1 -- Purchase Agreement dated as of July 1, 2003 among Southern Power Company and Citigroup Global Markets Inc. and Lehman Brothers Inc. (as representative of the Purchasers named therein). 3.1 -- Certificate of Incorporation of Southern Power Company dated January 8, 2001 (Designated in Registration No. 333-98553, as Exhibit 3.1). 3.2 -- Bylaws of Southern Power Company effective January 8, 2001 (Designated in Registration No. 333-98553, as Exhibit 3.2). 4.1 -- Indenture dated as of June 1, 2002, between Southern Power Company and The Bank of New York, as Trustee and Indentures supplemental thereto through July 8, 2003 (Designated in Registration No. 333-98553, as Exhibits 4.1 and 4.2 and in Form 10-Q for the quarter ended June 30, 2003, File No. 333-98553 as Exhibit (4)(g).) 4.2 -- Registration Rights Agreement dated as of July 8, 2003 among Southern Power Company and the Initial Purchasers named therein. 4.3 -- Form of Exchange Senior Note (included in Exhibit 4.2). 5.1 -- Opinion of Balch & Bingham LLP as to the legality of the Exchange Senior Notes. 12.1 -- Calculation of Ratio of Earnings to Fixed Charges. 23.1 -- Consent of Deloitte & Touche LLP, Independent Auditor. 23.2 -- Consent of Balch & Bingham LLP (included in Exhibit 5.1). 23.3 -- Consent of R. W. Beck, Inc. 23.4 -- Consent of PA Consulting Services, Inc. 24.1 -- Powers of Attorney and Resolution. 25.1 -- Statement of Eligibility of The Bank of New York, as Trustee on Form T-1. 99.1 -- Form of Letter of Transmittal. 99.2 -- Form of Notice of Guaranteed Delivery. 99.3 -- Form of Letter to Clients. 99.4 -- Form of Letter to Brokers, Dealers, Commercial Banks, Trust Companies and Other Nominees.
Exhibits listed above which have heretofore been filed with the Commission and which were designated as noted above are hereby incorporated herein by reference and made a part hereof with the same effect as if filed herewith. ITEM 22. UNDERTAKINGS (a) The undersigned Registrant hereby undertakes: (1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement: (i) to include any prospectus required by Section 10(a)(3) of the Securities Act of 1933; (ii) to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20 percent change in the maximum aggregate offering price set forth in the "Calculation of Registration Fee" table in the effective registration statement; II-3 (iii) to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement; Provided, however, that paragraphs (a)(1)(i) and (a)(1)(ii) do not apply if the information required to be included in a post-effective amendment by those paragraphs is contained in periodic reports filed with or furnished to the Securities and Exchange Commission filed by the Registrant pursuant to Section 13 or Section 15(d) of the Securities and Exchange Act of 1934 that are incorporated by reference in the registration statement. (2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. (3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering. (b) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. (c) The undersigned Registrant hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11 or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first-class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request. (d) The undersigned Registrant hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective. II-4 SIGNATURES Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed by the undersigned, thereunto duly authorized, in the City of Atlanta, State of Georgia on November 14, 2003. SOUTHERN POWER COMPANY By: W. PAUL BOWERS President, Chief Executive Officer and Director By: /s/ WAYNE BOSTON ------------------------------------ (Wayne Boston, Attorney-in-fact) Pursuant to the requirements of the Securities Act of 1933, the registration statement has been signed by the following persons in the capacities and on the dates indicated.
SIGNATURE TITLE DATE --------- ----- ---- * President, Chief Executive ------------------------------------------------ Officer and Director (Principal (W. Paul Bowers) Executive Officer) * Senior Vice President, ------------------------------------------------ Comptroller and Chief Financial (Cliff S. Thrasher) Officer (Principal Financial Officer and Principal Accounting Officer) * Director ------------------------------------------------ (H. Allen Franklin) * Director ------------------------------------------------ (Thomas A. Fanning) * Director ------------------------------------------------ (Charles D. McCrary) * Director ------------------------------------------------ (David M. Ratcliffe) *By: /s/ WAYNE BOSTON November 14, 2003 ------------------------------------------ (Wayne Boston, Attorney-in-fact)
II-5 EX-1.1 3 x1_1.txt Exhibit 1.1 $575,000,000 4.875% Senior Notes, Series C due July 15, 2015 SOUTHERN POWER COMPANY PURCHASE AGREEMENT July 1, 2003 Citigroup Global Markets Inc. 388 Greenwich Street New York, New York 10013 Lehman Brothers Inc. 745 Seventh Avenue New York, New York 10019 As Representatives of the Several Initial Purchasers named on Schedule I hereto Ladies and Gentlemen: Southern Power Company, a Delaware corporation (the "Company"), confirms its agreement (the "Agreement") with you and each of the other Initial Purchasers named in Schedule I hereto (collectively, the "Initial Purchasers", which term shall also include any initial purchaser substituted as hereinafter provided in Section 10 hereof) for whom you are acting as representatives (in such capacity you shall hereinafter be referred to as the "Representatives"), with respect to the sale by the Company and the purchase by the Initial Purchasers, acting severally and not jointly, of $575,000,000 aggregate principal amount of the 4.875% Senior Notes, Series C due July 15, 2015 (the "Senior Notes") as set forth in Schedule I hereto. The Senior Notes will be offered without being registered under the Securities Act of 1933, as amended (the "Securities Act"), in reliance on certain exemptions therefrom and in transactions not subject thereto. The Company has prepared a preliminary offering memorandum, dated June 30, 2003, including any and all annexes attached thereto, (the "Preliminary Offering Memorandum") and an offering memorandum, dated the date hereof, including any and all annexes attached thereto, (the "Offering Memorandum") setting forth information regarding the Company and the transactions described herein. The Senior Notes will be issued pursuant to an indenture, dated as of June 1, 2002 (the "Base Indenture"), between the Company and The Bank of New York, as trustee (the "Trustee"), as supplemented by a second supplemental indenture to the Base Indenture (the "Second Supplemental Indenture," and together with the Base Indenture and any other amendments or supplements thereto, the "Indenture"), between the Company and the Trustee. The Initial Purchasers and their direct and indirect transferees will be entitled to the benefits of a Registration Rights Agreement, dated the date hereof (the "Registration Rights Agreement") pursuant to which the Company will file with the Securities and Exchange Commission (the "Commission") (i) a registration statement under the Securities Act (the "Exchange Offer Registration Statement") registering senior notes of the Company ("Exchange Notes") which are identical in all material respects to each issue of the Senior Notes (except the Exchange Notes will not contain terms with respect to transfer restrictions and additional interest) and (ii) under certain circumstances, a shelf registration statement pursuant to Rule 415 under the Securities Act (the "Shelf Registration Statement"). Capitalized terms used but not defined herein shall have the meanings assigned thereto in the Offering Memorandum. SECTION 1. REPRESENTATIONS AND WARRANTIES. The Company represents and warrants to the Initial Purchasers as follows: (a) The Offering Memorandum does not on the date of this Agreement and, as it may be then amended and supplemented, will not on the Closing Date, contain an untrue statement of a material fact or omit to state a material fact necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading; except that this representation and warranty does not apply to (i) statements or omissions made in reliance upon and in conformity with written information furnished to the Company by or on behalf of any Initial Purchaser specifically for use in the Offering Memorandum and (ii) the Independent Engineer's Report or the Independent Market Expert's Report attached as Annex A and Annex B, respectively, to the Offering Memorandum. The factual information provided by the Company to R.W. Beck, Inc. ("Beck") for inclusion in its Independent Engineer's Report contained in Annex A to the Offering Memorandum was to the Company's knowledge, accurate in all material respects as of the time it was furnished. (b) The Preliminary Offering Memorandum, as of its date, did not contain an untrue statement of a material fact or omit to state a material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading, except that the Company makes no warranty or representation to the Initial Purchasers with respect to: (i) statements or omissions made in reliance upon and in conformity with written information furnished to the Company by or on behalf of any Initial Purchaser specifically for use in the Preliminary Offering Memorandum and (ii) the Independent Engineer's Report or the Independent Market Expert's Report attached as Annex A and Annex B, respectively, to the Preliminary Offering Memorandum. (c) The historical financial statements of the Company contained in the Offering Memorandum have been prepared in conformity with generally accepted accounting principles in the United States and fairly present the financial position of the Company as of the dates set forth therein. (d) Since the date as of which information is given in the Offering Memorandum, except as otherwise stated therein, there has been no material adverse change in the business, properties or financial condition of the Company. (e) The Company is a corporation duly organized and existing under the laws of the State of Delaware and has due corporate authority to conduct its business and to own and operate the properties used by it in such business, as described in the Offering Memorandum, to enter into and perform its obligations under this Agreement, the Registration Rights Agreement and the Indenture and to issue and sell the Senior Notes to the Initial Purchasers. (f) This Agreement has been duly authorized, executed and delivered by the Company. (g) The Indenture has been duly authorized by the Company and, on the Closing Date, will have been duly executed and delivered by the Company, and, assuming due authorization, execution and delivery of the Indenture by the Trustee, the Indenture will, on the Closing Date, constitute a valid and binding obligation of the Company, enforceable against the Company in accordance with its terms except to the extent that enforcement thereof may be limited by (1) bankruptcy, insolvency, reorganization, receivership, liquidation, fraudulent conveyance, moratorium or other similar laws affecting creditors' rights generally or (2) general principles of equity (regardless of whether enforcement is considered in a proceeding at law or in equity) (the "Enforceability Exceptions"); the Indenture will conform in all material respects to all statements relating thereto contained in the Offering Memorandum. (h) The issuance and delivery of the Senior Notes have been duly authorized by the Company and, on the Closing Date, the Senior Notes will have been duly executed by the Company and, when authenticated in the manner provided for in the Indenture and delivered against payment therefor as described in the Offering Memorandum, will constitute valid and legally binding obligations of the Company, enforceable against the Company in accordance with their terms, except to the extent that enforcement thereof may be limited by the Enforceability Exceptions; the Senior Notes will be in the form contemplated by, and entitled to the benefits of, the Indenture and will conform in all material respects to all statements relating thereto in the Offering Memorandum. (i) The Registration Rights Agreement has been duly authorized by the Company and, on the Closing Date, will have been duly executed and delivered by the Company and, assuming due authorization, execution and delivery of the Registration Rights Agreement by the other parties thereto, the Registration Rights Agreement will, on the Closing Date, constitute a valid and binding obligation of the Company, enforceable against the Company in accordance with its terms except to the extent the enforcement thereof may be limited by the Enforceability Exceptions and except as indemnification or contribution obligations thereunder may be limited under applicable laws; the Registration Rights Agreement will conform in all material respects to all statements relating thereto in the Offering Memorandum. (j) Neither the Company nor any of its affiliates (as defined in Rule 501(b) of Regulation D under the Securities Act, an "Affiliate") has directly, or through any agent, (i) sold, offered for sale, solicited offers to buy or otherwise negotiated in respect of any security (as defined in the Securities Act) which is or will be integrated with the sale of the Senior Notes in a manner that would require the registration under the Securities Act of the Senior Notes or (ii) engaged in any form of general solicitation or general advertising in connection with the offering of the Senior Notes (as those terms are used in Regulation D under the Securities Act), or acted in any manner involving a public offering of the Senior Notes within the meaning of Section 4(2) of the Securities Act. (k) The Senior Notes are eligible for resale pursuant to Rule 144A under the Securities Act ("Rule 144A") and will not be, at the Closing Date, of the same class (within the meaning of Rule 144A) as securities listed on a national securities exchange registered under Section 6 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), or quoted in a U.S. automated inter-dealer quotation system. (l) With respect to those Senior Notes sold in reliance on Regulation S under the Securities Act, (i) none of the Company, its Affiliates or any person acting on its or their behalf (other than the Initial Purchasers, as to whom the Company makes no representation) has engaged or will engage in any directed selling efforts within the meaning of Regulation S and (ii) each of the Company and its Affiliates and any person acting on its or their behalf (other than the Initial Purchasers, as to whom the Company makes no representation) has complied and will comply with the offering restrictions requirement of Regulation S. (m) The execution, delivery and performance by the Company of this Agreement, the Registration Rights Agreement, the Indenture and the Senior Notes and the consummation by the Company of the transactions contemplated herein and therein and compliance by the Company with its obligations hereunder and thereunder shall have been duly authorized by all necessary corporate action on the part of the Company and do not and will not result in any violation of the charter or bylaws of the Company, and do not and will not conflict with, or result in a breach of any of the terms or provisions of, or constitute a default under, or result in the creation or imposition of any lien, charge or encumbrance upon any property or assets of the Company under (A) any contract, indenture, mortgage, loan agreement, note, lease or other agreement or instrument to which the Company is a party or by which it may be bound or to which any of its properties may be subject (except for conflicts, breaches or defaults which would not, individually or in the aggregate, be materially adverse to the Company or materially adverse to the transactions contemplated by this Agreement), or (B) any existing applicable law, rule, regulation, judgment, order or decree of any government, governmental instrumentality or court, domestic or foreign, or any regulatory body or administrative agency or other governmental body having jurisdiction over the Company, or any of its properties. (n) No authorization, approval, consent or order of any court or governmental authority or agency is necessary in connection with the issuance and sale by the Company of the Senior Notes or the transactions by the Company contemplated in this Agreement and the Offering Memorandum, except (A) such as may be required under the Public Utility Holding Company Act of 1935, as amended (the "Holding Company Act"); (B) such consents, approvals, authorizations, registrations or qualifications as may be required under state securities or Blue Sky laws and (C) such consents, approvals, authorizations, registrations and qualifications as may be required under the Securities Act and the Trust Indenture Act of 1939, as amended (the "Trust Indenture Act") in connection with the transactions contemplated in the Registration Rights Agreement. (o) The projected financial information contained in the Offering Memorandum (excluding the Independent Market Expert's Report, attached as Annex B to the Offering Memorandum) (i) are, in the judgment of the Company as to the matters covered thereby, reasonable as of their date and (ii) are based on reasonable assumptions as to all factual and legal matters material to the estimates therein, all of which assumptions, to the extent material, are fairly disclosed in the Offering Memorandum. To the knowledge of the Company, none of the information forming the basis of such projections and assumptions has changed since they were originally prepared so as to materially affect such projections and assumptions. (p) Assuming the accuracy of the Initial Purchasers' representations contained herein, and the Initial Purchasers' compliance with its agreements hereunder, the Company is not required by applicable law or regulation, in connection with the offer, sale and delivery of the Senior Notes to the Initial Purchasers, and the initial resales by the Initial Purchasers, each in the manner contemplated by this Agreement and the Offering Memorandum, to register the Senior Notes under the Securities Act or to qualify the Indenture under the Trust Indenture Act. SECTION 2. SALE AND DELIVERY TO THE INITIAL PURCHASERS; CLOSING; SALE AND RESALE BY THE INITIAL PURCHASERS. (a) On the basis of the representations and warranties herein contained and subject to the terms and conditions herein set forth, the Company agrees to sell to each Initial Purchaser, and each Initial Purchaser, severally and not jointly, agrees to purchase from the Company, the principal amount of Senior Notes set forth in Schedule I to this Agreement opposite the name of such Initial Purchaser (plus any additional amount of Senior Notes that such Initial Purchaser may become obligated to purchase pursuant to the provisions of Section 10 hereof), at the prices set forth in Schedule I to this Agreement. (b) Payment for and delivery of certificates for the Senior Notes shall be made at the offices of Dewey Ballantine LLP, 1301 Avenue of the Americas, New York, New York 10019 at 10:00 A.M., New York time, on July 8, 2003 (unless postponed in accordance with the provisions of Section 10) or such other time, place or date as shall be agreed upon by the Representatives and the Company (such time and date of payment and delivery being herein called the "Closing Date"). Payment shall be made to the Company by wire transfer in federal funds at the Closing Date against delivery of the Senior Notes to Citigroup Global Markets Inc. ("Citigroup"). It is understood that each Initial Purchaser has authorized Citigroup, for its account, to accept delivery of, receipt for, and make payment of the principal amount of the Senior Notes which it has agreed to purchase. Citigroup, individually and not as Representatives of the Initial Purchaser, may (but shall not be obligated to) make payment of the principal amount of the Senior Notes to be purchased by any Initial Purchaser whose payment has not been received by the Closing Date, but such payment shall not relieve such Initial Purchaser from its obligations hereunder. (c) The Senior Notes in which interests are sold to Qualified Institutional Buyers (as defined in Rule 144A) in reliance on Rule 144A will be issued in the form of two or more Global Notes (the "Rule 144A Global Notes"). The Senior Notes in which interests are sold to persons other than U.S. persons (as defined in Regulation S under the Securities Act ("Regulation S")) in offshore transactions in reliance on Regulation S will each be issued in the form of two or more Global Notes (the "Regulation S Global Notes"). Upon issuance by the Company, the Trustee will authenticate and deliver the Rule 144A Global Notes and the Regulation S Global Notes and will record Cede & Co., as the nominee of DTC, on its books as the registered owner of the Senior Notes. The Senior Notes in which interests are sold to a limited number of institutional investors who are "accredited investors" (as defined in Rule 501(a)(1), (2), (3) or (7) under the Securities Act) will be issued in certificated form without coupons and registered in such names as each Initial Purchaser may request upon at least forty-eight hours' prior notice to the Company. For the purpose of expediting the checking of the Senior Notes by the Initial Purchasers, the Company agrees to make the Senior Notes available to the Initial Purchasers for such purpose at the offices of the Trustee in New York, New York not later than 2:00 PM, New York City time, on the business day preceding the Closing Date, or at such other time and place as may be agreed upon by the Company and the Initial Purchasers. (d) Resale of the Securities: Each Initial Purchaser represents and warrants to, and agrees with the Company that: (1) It is a Qualified Institutional Buyer and an "accredited investor" within the meaning of Rule 501(a) under the Securities Act; (2) It has not offered or sold, and will not offer or sell, Senior Notes except (i) to persons whom it reasonably believes to be Qualified Institutional Buyers or, if any such person is buying for one or more institutional accounts for which such person is acting as fiduciary or agent, only when such person has represented to such Initial Purchaser that each such account is a Qualified Institutional Buyer to whom such notice has been given that such sale or delivery is being made in reliance on Rule 144A, in each case in transactions meeting the requirements of Rule 144A, (ii) to a limited number of other institutional investors whom the Company believes to be "accredited investors" (as defined in Rule 501(a) (1), (2), (3) or (7) of Regulation D) that, prior to their purchase of the Senior Notes, deliver to it a letter substantially in the form of Annex C to the Offering Memorandum or (iii) in the case of offers outside the United States to persons other than U.S. Persons (within the meaning of Regulation S) to whom it reasonably believes offers and sales of the Senior Notes may be made in reliance upon Regulation S under the Securities Act; and (3) Neither it nor any of its Affiliates or any person acting on its or their behalf has made or will make offers or sales of Senior Notes in the United States by means of any form of general solicitation or general advertising (within the meaning of Regulation D) or in any manner involving a public offering (within the meaning of Section 4(2) under the Securities Act) in the United States. (e) Each Initial Purchaser represents, warrants, and agrees with respect to offers and sales outside the United States that: (1) such Initial Purchaser understands that no action has been or will be taken in any jurisdiction by the Company that would permit a public offering of the Senior Notes, or possession or distribution of the Offering Memorandum or Preliminary Offering Memorandum or any other offering or publicity material relating to the Senior Notes, in any country or jurisdiction where action for that purpose is required; (2) such Initial Purchaser will comply with all applicable laws and regulations in each jurisdiction in which it acquires, offers, sells or delivers Senior Notes or has in its possession or distributes the Offering Memorandum or Preliminary Offering Memorandum or any such other material, in all cases at its own expense; (3) the Senior Notes have not been registered under the Securities Act and may not be offered or sold within the United States or to, or for the account or benefit of, U.S. persons except in accordance with Rule 144A or Regulation S or pursuant to another exemption from, or in transactions not subject to, the registration requirements of the Securities Act; (4) such Initial Purchaser has offered the Senior Notes and will offer and sell the Senior Notes (A) as part of its distribution at any time and (B) otherwise until 40 days after the later of the commencement of the offering and the Closing Date, only in accordance with Rule 903 of Regulation S or as otherwise permitted in Section 2(d) of this Agreement; accordingly, neither such Initial Purchaser, its Affiliates nor any persons acting on its or their behalf have engaged or will engage in any directed selling efforts (within the meaning of Regulation S) with respect to the Senior Notes, and the Initial Purchaser, its Affiliates and any such persons have complied and will comply with the offering restrictions requirement of Regulation S; (5) such Initial Purchaser has (A) not offered or sold and will not offer or sell any Senior Notes to persons in the United Kingdom except to persons whose ordinary activities involve them in acquiring, holding, managing or disposing of investments (as principal or agent) for the purposes of their businesses or otherwise in circumstances which have not resulted and will not result in an offer to the public in the United Kingdom within the meaning of the Public Offers of Securities Regulations 1995; (B) only communicated or caused to be communicated and will only communicate or cause to be communicated any invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act 2000 (the "FSMA")) received by it in connection with the issue or sale of any Senior Notes in circumstances in which Section 21(1) of the FSMA does not apply to the Company and (C) complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the Senior Notes in, from or otherwise involving the United Kingdom; and (6) such Initial Purchaser agrees that, at or prior to confirmation of sales of the Senior Notes, it will have sent to each distributor, dealer or person receiving a selling concession, fee or other remuneration that purchases Senior Notes from it during the restricted period a confirmation or notice to substantially the following effect: "The Securities covered hereby have not been registered under the U.S. Securities Act of 1933, as amended (the "Securities Act") and may not be offered and sold within the United States or to, or for the account or benefit of, U.S. persons (i) as part of their distribution at any time or (ii) otherwise until 40 days after the later of the commencement of the offering and the closing date, except in either case in accordance with Regulation S (or Rule 144A or any other exemption from the registration requirements of the Securities Act if available) under the Securities Act. Terms used above have the meaning given to them by Regulation S." Terms used in this Section 2(e) have the meanings given to them by Regulation S. SECTION 3. COVENANTS OF THE COMPANY. The Company covenants with the Initial Purchasers as follows: (a) To prepare the Offering Memorandum in a form approved by the Initial Purchasers and to furnish to the Initial Purchasers, without charge, as many copies of the Preliminary Offering Memorandum and the Offering Memorandum and any supplements and amendments thereto as the Initial Purchasers may reasonably request. (b) If, at any time prior to completion of the initial resales of the Senior Notes by the Initial Purchasers to purchasers, any event shall occur or condition exist as a result of which it is necessary, in the opinion of Dewey Ballantine LLP, to amend or supplement the Offering Memorandum in order that the Offering Memorandum will not include an untrue statement of a material fact or omit to state a material fact necessary in order to make the statements therein not misleading in light of the circumstances existing at the time it is delivered to a purchaser or a potential purchaser, or if it is necessary to amend or supplement the Offering Memorandum to comply with applicable law, to promptly prepare such amendment or supplement as may be necessary to correct such untrue statement or omission or so that the Offering Memorandum, as so amended or supplemented, will comply with applicable law and to furnish the Initial Purchasers such number of copies as they may reasonably request. (c) So long as the Senior Notes are outstanding and are "restricted securities" within the meaning of Rule 144(a)(3) under the Securities Act, to furnish to holders of Senior Notes and prospective purchasers of Senior Notes designated by such holders, upon request of such holders or such prospective purchasers, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act, unless such information is contained, at the time of such request, in documents filed with the Commission pursuant to Section 13 or 15(d) of the Exchange Act. (d) The Company will endeavor, in cooperation with the Initial Purchasers, to qualify the Senior Notes for offering and sale under the applicable securities laws of such states and the other jurisdictions of the United States as the Initial Purchasers may designate and to pay filing fees, reasonable attorneys' fees and disbursements in connection therewith in an amount not exceeding $15,000 in the aggregate (including filing fees and disbursements paid or incurred prior to the date this Agreement becomes effective); provided, however, that the Company shall not be obligated to qualify as a foreign corporation in any jurisdiction in which it is not so qualified or to file a consent to service of process or to file annual reports or to comply with any other requirements in connection with such qualification deemed by the Company to be unduly burdensome. (e) The Company covenants (i) not to solicit any offer to buy or offer to sell the Senior Notes by means of any form of general solicitation or general advertising (as those terms are used in Regulation D under the Securities Act) or in any manner involving a public offering within the meaning of Section 4(2) of the Securities Act and (ii) not to engage, or permit its Affiliates or any person acting on their behalf to engage, in any directed selling efforts (as defined in Regulation S) with respect to the Senior Notes sold pursuant to Regulation S and to comply and cause its Affiliates and each person acting on their behalf to comply with the offering restrictions of Regulation S with respect to those Senior Notes sold pursuant thereto (it being understood that the Company and its Affiliates shall not have responsibility for the actions of the Initial Purchasers or any of their respective Affiliates). (f) The Company covenants not to offer, sell, contract to sell or otherwise dispose of any additional securities of the Company or to issue any securities convertible into or exchangeable for the Senior Notes or with respect to any debt securities substantially similar to the Senior Notes (except for the securities issued pursuant to this Agreement), without the consent (which consent shall not be unreasonably withheld) of the Initial Purchasers during the period beginning from the date of this Agreement and continuing to and including the earlier of (i) the termination of trading restrictions on the Senior Notes, as communicated to the Company by the Initial Purchasers and (ii) 15 days following the Closing Date. (g) The Company agrees not to, and will cause its Affiliates not to, sell, offer for sale or solicit offers to buy or otherwise negotiate in respect of any security (as defined in the Securities Act) in a transaction that could be integrated with the sale of the Senior Notes in a manner that would require the registration under the Securities Act of the Senior Notes. (h) During the period of two years after the Closing Date, the Company will not, and will not permit any of its Affiliates to, purchase, agree to purchase or otherwise acquire any of the Senior Notes which constitute "restricted securities" under Rule 144 under the Securities Act. SECTION 4. PAYMENT OF EXPENSES. (a) The Company agrees to pay all expenses incidental to the performance of its obligations under this Agreement, including, but not limited to, the expenses of (i) the preparation and printing of the Preliminary Offering Memorandum and the Offering Memorandum and any amendments and supplements thereto, (ii) distributing the Preliminary Offering Memorandum and the Offering Memorandum and any amendments or supplements thereto, (iii) the preparation, issuance and delivery of the certificate(s) for the Senior Notes to the Initial Purchasers, (iv) the fees and disbursements of the Company's counsel and accountants, (v) the qualification of the Senior Notes under securities laws in accordance with the provisions of Section 3(d) hereof, including filing fees and the reasonable fees and disbursements of Dewey Ballantine LLP, counsel for the Initial Purchasers, in connection therewith and in connection with the preparation of any blue sky survey, (vi) the printing and delivery to the Initial Purchasers of copies of any blue sky survey, (vii) the fee of the National Association of Securities Dealers, Inc. in connection with its review of the offering contemplated by this Agreement, if applicable, (viii) the fees and expenses of the Trustee, including the fees and disbursements of counsel for the Trustee in connection with the Indenture and the Notes, (ix) any fees payable in connection with the rating of the Senior Notes, (x) the cost and charges of any transfer agent or registrar, (xi) the cost of qualifying the Senior Notes with DTC; and (xii) all reasonable fees, disbursements and expenses of independent engineers, independent market experts and any other third party consultants who have prepared reports, attached as annexes to the Preliminary Offering Memorandum and Offering Memorandum, or otherwise. (b) In addition, the Company agrees to pay the reasonable and documented third party out of pocket expenses incurred by the Representatives in connection with the offer and sale of the Senior Notes to the Initial Purchasers (including (i) all out of pocket expenses incurred by the Initial Purchasers with respect to the "road show" including expenses relating to slide production, Bloomberg taping and travel and (ii) reasonable and documented fees and expenses of counsel to the Initial Purchasers). SECTION 5. CONDITIONS OF INITIAL PURCHASERS' OBLIGATIONS. The obligations of the Initial Purchasers to purchase and pay for the Senior Notes are subject to the following conditions: (a) Any required order or orders of the Commission under the Holding Company Act permitting the transactions contemplated hereby substantially in accordance with the terms and conditions hereof shall be in full force and effect and shall contain no provision unacceptable to the Initial Purchasers or the Company (but all provisions of such order or orders heretofore entered, copies of which have heretofore been delivered to the Representatives, are deemed acceptable to the Initial Purchasers and the Company and all provisions of such order or orders hereafter entered shall be deemed acceptable to the Initial Purchasers and the Company unless within 24 hours after receiving a copy of any such order any party to this Agreement shall give notice to the other parties to the effect that such order contains an unacceptable provision). (b) On the Closing Date the Representatives shall have received: (1) The opinion, dated the Closing Date, of Balch & Bingham LLP, counsel for the Company, substantially in the form attached hereto as Schedule II. (2) The opinion, dated the Closing Date, of Pillsbury Winthrop LLP, counsel to the Trustee, substantially in the form attached hereto as Schedule III. (3) The opinion, dated as of the Closing Date, of Dewey Ballantine LLP, counsel for the Initial Purchasers, substantially in the form attached hereto as Schedule IV. (4) At the Closing Date, there shall not have been, since the date hereof or since the respective dates as of which information is given in the Offering Memorandum, any material adverse change in the business, properties or financial condition of the Company, whether or not arising in the ordinary course of business, and the Representatives shall have received a certificate of the President or any Vice President of the Company, dated as of the Closing Date, to the effect that (i) there has been no such material adverse change, (ii) the representations and warranties in Section 1 hereof are true and correct with the same force and effect as though expressly made at and as of the Closing Date and (iii) the Company has complied with all agreements and satisfied all conditions on its part to be performed or satisfied on or prior to the Closing Date. (5) On the Closing Date, the Representatives shall have received from Deloitte & Touche LLP a letter dated as of the Closing Date to the effect that: (A) they are independent public accountants with respect to the Company within the meaning of the Securities Act and the rules and regulations under the Securities Act; (B) in their opinion, the financial statements audited by them and included in the Offering Memorandum comply as to form in all material respects with the applicable accounting requirements of the Exchange Act and the rules and regulations under the Exchange Act; and (C) on the basis of certain limited procedures performed through a specified date not more than five business days prior to the date of such letter, namely (i) reading the minute books of the Company; (ii) performing the procedures specified by the American Institute of Certified Public Accountants ("AICPA") for a review of interim financial information as described in Statement on Auditing Standards No. 71, "Interim Financial Information" or Statement on Auditing Standards No. 100, "Interim Financial Information", as applicable, on the unaudited financial statements, if any, of the Company included in the Offering Memorandum and of the latest available unaudited financial statements of the Company, if any, for any calendar quarter subsequent to the date of those included in the Offering Memorandum; and (iii) making inquiries of certain officials of the Company who have responsibility for financial and accounting matters regarding such unaudited financial statements or any specified unaudited amounts derived therefrom (it being understood that the foregoing procedures do not constitute an audit performed in accordance with generally accepted auditing standards and they would not necessarily reveal matters of significance with respect to the comments made in such letter, and accordingly that Deloitte & Touche LLP make no representations as to the sufficiency of such procedures for the Initial Purchasers' purposes), nothing came to their attention that caused them to believe that: (1) any material modifications should be made to the unaudited condensed financial statements included in the Offering Memorandum for them to be in conformity with generally accepted accounting principles; (2) such unaudited condensed financial statements do not comply as to form in all material respects with the applicable accounting requirements of the Exchange Act as it applies to Form 10-Q and the related published rules and regulations thereunder; (3) the unaudited amounts for Operating Revenues, Earnings Before Income Taxes and Net Income and the unaudited Ratio of Earnings to Fixed Charges set forth in the Offering Memorandum do not agree with the amounts set forth in or derived from the unaudited financial statements for the same period or were not determined on a basis substantially consistent with that of the corresponding audited amounts or ratios included in the Offering Memorandum; (4) as of a specified date not more than five business days prior to the date of delivery of such letter, there has been any change in the capital stock or long-term debt of the Company or any decrease in net assets as compared with amounts shown in the latest audited balance sheet, except in each case for changes or decreases which (i) the Offering Memorandum discloses have occurred or may occur, (ii) are occasioned by the declaration of dividends, (iii) are occasioned by draw-downs under existing pollution control financing arrangements, (iv) are occasioned by draw-downs and regularly scheduled payments of capitalized lease obligations, (v) are occasioned by the purchase or redemption of bonds or stock to satisfy mandatory or optional redemption provisions relating thereto, (vi) are occasioned by the reclassification of current maturities of long-term debt, or (vii) are disclosed in such letter; and (5) the unaudited amounts for Operating Revenues, Earnings Before Income Taxes and Net Income and the unaudited Ratio of Earnings to Fixed Charges for any calendar quarter subsequent to those set forth in (3) above, which, if available, shall be set forth in such letter, do not agree with the amounts set forth in or derived from the unaudited financial statements for the same period or were not determined on a basis substantially consistent with that of the corresponding audited amounts or ratios included in the Offering Memorandum. Deloitte & Touche LLP shall also have compared specified dollar amounts (or percentages derived from such dollar amounts) and other financial information contained in the Offering Memorandum, (in each case to the extent that such dollar amounts, percentages and other financial information are derived from the general accounting records of the Company and its subsidiaries subject to the internal controls of the Issuer's accounting system or are derived directly from such records by analysis or computation) with the results obtained from inquiries, a reading of such general accounting records and other procedures specified in such letter and have found such dollar amounts, percentages and other financial information to be in agreement with such results, except as otherwise specified in such letter. (6) On the Closing Date, Dewey Ballantine LLP, counsel for the Initial Purchasers shall have been furnished with such documents and opinions as they may reasonably require for the purpose of enabling them to pass upon the issuance and sale of the Senior Notes as herein contemplated and related proceedings, or in order to evidence the accuracy of any of the representations or warranties, or the fulfillment of any of the conditions, herein contained; and all proceedings taken by the Company in connection with the issuance and sale of the Senior Notes as herein contemplated shall be satisfactory in form and substance to the Representatives and Dewey Ballantine LLP, counsel for the Initial Purchasers. (7) That no amendment or supplement to the Preliminary Offering Memorandum or the Offering Memorandum shall be unsatisfactory in form to Dewey Ballantine LLP or shall contain information (other than with respect to an amendment or supplement relating solely to the activity of the Initial Purchasers) which, in the reasonable judgment of the Representatives, shall materially impair the marketability of the Senior Notes. (8) Beck shall have consented to the references to it in the Offering Memorandum and the use of the Independent Engineer's Report prepared by Beck and contained in Annex A to the Offering Memorandum; and confirmed that nothing has come to their attention in connection with the preparation of the Independent Engineer's Report which would cause it to believe that the Independent Engineer's Report, as of its date, or any statements in the Offering Memorandum specifically attributed to it, as of the date of the Offering Memorandum, were inaccurate or misleading in any material respect, as evidenced by a certificate satisfactory to the Initial Purchasers of an authorized officer of Beck, delivered and dated as of the Closing Date. (9) PA Consulting Services, Inc. ("PA") shall have consented to the references to it in the Offering Memorandum and the use of the Independent Market Expert's Report prepared by PA and contained in Annex B to the Offering Memorandum; and since the date of the Independent Market Expert's Report, no event affecting the Report or the matters referred to therein shall have occurred (i) which shall make untrue or incorrect in any material respect, as of the date of this Agreement, any information or statement contained in the Independent Market Expert's Report or in the Offering Memorandum relating to matters referred to in the Independent Market Expert's Report or (ii) which is not reflected in the Offering Memorandum but should be reflected therein in order to make the statements and information contained in the Offering Memorandum relating to matters referred to in the Independent Market Expert's Report, in light of the circumstances under which they were made, not misleading, as evidenced by a certificate satisfactory to the Initial Purchasers of an authorized officer of PA, delivered and dated as of the Closing Date. (10) The Initial Purchasers shall have received on the Closing Date the Registration Rights Agreement executed by the Company and the Representatives. (11) The Company shall have performed its obligations when and as provided under this Agreement. If any condition specified in this Section shall not have been fulfilled when and as required to be fulfilled, this Agreement may be terminated by the Representatives by notice to the Company at any time prior to the Closing Date, and such termination shall be without liability of any party to any other party except as provided in Sections 4, 7 and 9(b) hereof. SECTION 6. CONDITIONS OF THE OBLIGATIONS OF THE COMPANY. The obligations of the Company shall be subject to the conditions set forth in Section 5(a). In case such conditions shall not have been fulfilled, this Agreement may be terminated by the Company by mailing or delivering written notice thereof to the Representatives. Any such termination shall be without liability of any party to any other party except as otherwise provided in Sections 4, 7 and 9(b) hereof. SECTION 7. INDEMNIFICATION. (a) The Company agrees to indemnify and hold harmless each of the Initial Purchasers and each person, if any, who controls any such Initial Purchaser within the meaning of Section 15 of the Securities Act or Section 20(a) of the Exchange Act, against any and all losses, claims, damages or liabilities, joint or several, to which they or any of them may become subject under the Securities Act, Exchange Act or otherwise, and to reimburse such Initial Purchaser and such controlling person or persons, if any, for any legal or other expenses incurred by them in connection with defending any actions, insofar as such losses, claims, damages, liabilities or actions arise out of or are based upon any untrue statement or alleged untrue statement of a material fact contained in the Preliminary Offering Memorandum or Offering Memorandum or, if the Company shall furnish to the Initial Purchasers any amendments or any supplements thereto, or arise out of or are based upon any omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading, except insofar as such losses, claims, damages, liabilities or actions arise out of or are based upon any such untrue statement or alleged untrue statement or omission or alleged omission which was made in such Preliminary Offering Memorandum or Offering Memorandum or any such amendment or supplement thereto in reliance upon and in conformity with information furnished in writing to the Company by, or through the Representatives on behalf of, the Initial Purchasers for use therein and except that this indemnity with respect to the Preliminary Offering Memorandum or with respect to the Offering Memorandum, if the Company shall have furnished any amendment or supplement thereto, shall not inure to the benefit of any Initial Purchaser (or of any person controlling such Initial Purchaser) on account of any losses, claims, damages, liabilities or actions arising from the sale of the Senior Notes to any person if a copy of the Offering Memorandum, as the same may then be amended or supplemented, shall not have been sent or given by or on behalf of such Initial Purchaser to such person with or prior to the written confirmation of the sale involved and the untrue statement or alleged untrue statement or omission or alleged omission was corrected in the Offering Memorandum as supplemented or amended at the time of such confirmation. Each Initial Purchaser agrees, within ten days after the receipt by it of notice of the commencement of any action in respect of which indemnity may be sought by it, or by any person controlling it, from the Company on account of its agreement contained in this Section 7, to notify the Company in writing of the commencement thereof but the omission of such Initial Purchaser so to notify the Company of any such action shall not release the Company from any liability which it may have to such Initial Purchaser or to such controlling person otherwise than on account of the indemnity agreement contained in this Section 7. In case any such action shall be brought against an Initial Purchaser or any such person controlling such Initial Purchaser and such Initial Purchaser shall notify the Company of the commencement thereof as above provided, the Company shall be entitled to participate in (and, to the extent that it shall wish, including the selection of counsel, to direct) the defense thereof, at its own expense. In case the Company elects to direct such defense and select such counsel, any Initial Purchaser or controlling person shall have the right to employ its own counsel, but, in any such case, the fees and expenses of such counsel shall be at the expense of such Initial Purchaser or such controlling person unless the employment of such counsel has been authorized in writing by the Company in connection with defending such action. No indemnifying party shall, without the written consent of the indemnified party, effect the settlement or compromise of, or consent to the entry of any judgment with respect to, any pending or threatened action or claim in respect of which indemnification may be sought hereunder (whether or not the indemnified party is an actual or potential party to such action or claim) unless such settlement, compromise or judgment (i) includes an unconditional release of the indemnified party from all liability arising out of such action or claim and (ii) does not include any statement as to, or an admission of, fault, culpability or a failure to act, by or on behalf of any indemnified party. In no event shall any indemnifying party have any liability or responsibility in respect of the settlement or compromise of, or consent to the entry of any judgment with respect to, any pending or threatened action or claim effected without its prior written consent. (b) Each Initial Purchaser agrees severally and not jointly, to indemnify and hold harmless the Company and each of its directors and officers and each person, if any, who controls the Company within the meaning of Section 15 of the Securities Act or Section 20(a) of the Exchange Act to the same extent and upon the same terms as the indemnity agreement of the Company set forth in Section 7(a) hereof, but only with respect to alleged untrue statements or omissions made in the Preliminary Offering Memorandum or the Offering Memorandum, or such documents as amended or supplemented, in reliance upon and in conformity with information furnished in writing to the Company by, or through the Representatives on behalf of, such Initial Purchaser for use therein. SECTION 8. REPRESENTATIONS, WARRANTIES AND AGREEMENTS TO SURVIVE DELIVERY. All representations, warranties and agreements contained in this Agreement, or contained in certificates of officers of the Company submitted pursuant hereto, shall remain operative and in full force and effect, regardless of any investigation made by or on behalf of any Initial Purchaser or controlling person, or by, or on behalf of the Company and shall survive delivery of the Senior Notes to the Initial Purchasers. SECTION 9. TERMINATION OF AGREEMENT. (a) The Representatives may terminate this Agreement, by notice to the Company, at any time at or prior to the Closing Date if (i) trading in securities on the New York Stock Exchange shall have been generally suspended or there shall have been a material disruption in settlement in securities generally, (ii) minimum or maximum ranges for prices shall have been generally established on the New York Stock Exchange by the Commission or by the New York Stock Exchange, (iii) a general banking moratorium shall have been declared by federal or New York State authorities, or (iv) there shall have occurred any outbreak or escalation of major hostilities in which the United States is involved, any declaration of war by the United States Congress or any other substantial national or international calamity or emergency (including, without limitation, acts of terrorism) affecting the United States, in any such case provided for in clauses (i) through (iv) with the result that, in the reasonable judgement of the Representatives, the marketability of the Senior Notes shall have been materially impaired. (b) If this Agreement shall be terminated by the Representatives pursuant to subsection (a) above or because of any failure or refusal on the part of the Company to comply with the terms or to fulfill any of the conditions of this Agreement, or if for any reason the Company shall be unable to perform its obligations under this Agreement, then in any such case, the Company will reimburse the Initial Purchasers for the reasonable and documented third party out of pocket expenses described in Section 4(b) of this Agreement. Upon such reimbursement, the Company shall be absolved from any further liability hereunder, except as provided in Sections 4(a) and 7. SECTION 10. DEFAULT BY AN INITIAL PURCHASER If an Initial Purchaser shall fail on the Closing Date to purchase the Senior Notes that it is obligated to purchase under this Agreement (the "Defaulted Securities"), the Representatives shall have the right, within 24 hours thereafter, to make arrangements for the non-defaulting Initial Purchasers, or any other initial purchasers, to purchase all, but not less than all, of the Defaulted Securities in such amounts as may be agreed upon and upon the terms herein set forth. If, however, the Representatives shall not have completed such arrangements within such 24-hour period, then: (a) if the principal amount of Defaulted Securities does not exceed 10% of the Senior Notes, the non-defaulting Initial Purchasers shall be obligated, severally and not jointly, to purchase the full amount thereof in the proportions that their respective underwriting obligations hereunder bear to the underwriting obligations of all non-defaulting Initial Purchasers, or (b) if the principal amount of Defaulted Securities exceeds 10% of the Senior Notes, this Agreement shall terminate without liability on the part of any non-defaulting Initial Purchaser. No action taken pursuant to this Section shall relieve any defaulting Initial Purchaser from liability in respect of its default. In the event of any such default which does not result in a termination of this Agreement, either the Representatives or the Company shall have the right to postpone the Closing Date for a period not exceeding seven days in order to effect any required changes in the Offering Memorandum or in any other documents or arrangements. SECTION 11. NOTICES. All notices and other communications hereunder shall be in writing and shall be deemed to have been duly given if mailed or transmitted by any standard form of telecommunication. Notices to the Initial Purchasers shall be directed to the Representatives at Lehman Brothers Inc., 745 7th Avenue, New York, New York 10019, Attention: Debt Capital Markets, Power Group, Fax: 212-526-0943 and Citigroup Global Markets Inc., 388 Greenwich Street, New York, New York 10013, Attention: Barry Gold, Fax: 212-723-8677; notices to the Company shall be mailed to 270 Peachtree Street, N.W., Atlanta, Georgia 30303, Attention: Treasurer, with a copy to Southern Company Services, Inc., 270 Peachtree Street, N.W., Atlanta, Georgia 30303, Attention: Christopher J. Kysar. SECTION 12. PARTIES. This Agreement shall inure to the benefit of and be binding upon the Initial Purchasers, the Company and their respective successors. Nothing expressed or mentioned in this Agreement is intended or shall be construed to give any person, firm or corporation, other than the Initial Purchasers and the Company and their respective successors and the controlling persons and officers and directors referred to in Section 7 and their heirs and legal representatives, any legal or equitable right, remedy or claim under or in respect of this Agreement or any provision herein contained. This Agreement and all conditions and provisions hereof are intended to be for the sole and exclusive benefit of the Initial Purchasers and the Company and their respective successors, and said controlling persons and officers and directors and their heirs and legal representatives, and for the benefit of no other person, firm or corporation. No purchaser of Senior Notes from any of the Initial Purchasers shall be deemed to be a successor by reason merely of such purchase. SECTION 13. GOVERNING LAW AND TIME. This Agreement shall be governed by and construed in accordance with the laws of the State of New York applicable to agreements made and to be performed in said State. Except as otherwise set forth herein, specified times of day refer to New York City time. SECTION 14. COUNTERPARTS. This Agreement may be executed by any one or more of the parties hereto in any number of counterparts, each of which shall be deemed to be an original, but all such respective counterparts shall together constitute one and the same instrument. If the foregoing is in accordance with your understanding of our agreement, please sign and return to the Company a counterpart hereof, whereupon this instrument, along with all counterparts, will become a binding agreement between the Initial Purchasers and the Company in accordance with its terms. Very truly yours, SOUTHERN POWER COMPANY By: ---------------------------------------- Name: --------------------------------- Title: ------------------------------ CONFIRMED AND ACCEPTED, as of the date first above written CITIGROUP GLOBAL MARKETS INC. By: ----------------------------------------- Name: --------------------------------------- Title: ------------------------------------ LEHMAN BROTHERS INC. By: ----------------------------------------- Name: --------------------------------------- Title: ------------------------------------ As Representatives of the Several Initial Purchasers named in Schedule I hereto SCHEDULE I I. Purchase Price The purchase prices to be paid by the Initial Purchasers for the Senior Notes shall be as follows: Initial Purchasers' Initial Purchasers' Price to Public Discount Purchase Price ------------------- -------------------- ------------------- Series C Notes 99.738% 0.700% 99.038% II. Principal Amount to be Purchased Principal Amount of Initial Purchasers Series C Notes - -------------------------------------------------- ------------------- Citigroup Global Markets Inc. .................... $201,250,000 Lehman Brothers Inc. ............................. 201,250,000 Mizuho International plc ......................... 57,500,000 Tokyo-Mitsubishi International plc ............... 57,500,000 Barclays Capital Inc. ............................ 14,375,000 Commerzbank Capital Markets Corp. ................ 14,375,000 ING Financial Markets LLC ........................ 14,375,000 Scotia Capital (USA) Inc. ........................ 14,375,000 -------------- Aggregate Principal Amount $575,000,000 Schedule II [Letterhead of BALCH & BINGHAM LLP] ________, 2003 Citigroup Global Markets Inc. 388 Greenwich Street New York, New York 10013 Lehman Brothers Inc. 745 Seventh Avenue New York, New York 10019 As Representatives of the Several Initial Purchasers SOUTHERN POWER COMPANY ___ % Senior Notes, Series C due July 15, 2015 Ladies and Gentlemen: We have acted as counsel to Southern Power Company (the "Company") in connection with (i) the Company's issuance of $575,000,000 aggregate principal amount of its ___% Senior Notes, Series C due July 15, 2015 (the "Notes") pursuant to a Senior Note Indenture dated as of June 1, 2002, by and between the Company and The Bank of New York, as trustee (the "Trustee"), as heretofore supplemented and as further supplemented by the Second Supplemental Indenture dated as of __________, 2003 (collectively, the "Indenture"); and (ii) the purchase by the Representatives of the Notes pursuant to the terms of a Purchase Agreement dated June __, 2003, among the Company and the initial purchasers named in Schedule I thereto (the "Initial Purchasers") for whom you are acting as the Representatives (the "Purchase Agreement"). The Notes are subject to the Registration Rights Agreement dated the date hereof by and among the Company and you, as the Representatives (the "Registration Rights Agreement"). This opinion is being delivered to you as Representatives pursuant to Section 5(b)(1) thereof. All capitalized terms not otherwise defined herein shall have the meanings set forth in the Purchase Agreement. In rendering the opinions expressed below, we have examined the offering memorandum dated __________, 2003 (the "Offering Memorandum"), the Indenture, the Notes, the Registration Rights Agreement and the Purchase Agreement. In addition, we have examined, and have relied as to matters of fact upon, the documents delivered to you at the closing (except the Notes, of which we have examined specimens), and we have made such other and further investigations as we deemed necessary to express the opinions hereinafter set forth. In such examination, we have assumed the genuineness of all signatures, the legal capacity of natural persons, the authenticity of all documents submitted to us as originals, the conformity to original documents of all documents submitted to us as certified or photostatic copies and the authenticity of the originals of such latter documents. The Indenture, the Registration Rights Agreement, the Notes and the Purchase Agreement are herein referred to as the "Agreements". Based upon the foregoing, and subject to the qualifications and limitations stated herein, we are of the opinion, relying as to matters of New York law upon the opinion dated the date hereof rendered to you by Dewey Ballantine LLP and relying as to matters of Florida law upon the attached opinion of Beggs & Lane to the Company, that: 1 The Company has been duly organized and is validly existing and in good standing as a corporation under the laws of the State of Delaware and has due corporate authority to conduct its business and to own and operate the properties used by it in such business as described in the Offering Memorandum and to enter into and perform its obligations under the Agreements. 2 The execution, delivery and performance by the Company of the Purchase Agreement have been duly authorized by all necessary corporate action, and the Purchase Agreement has been duly executed and delivered by the Company. 3 All orders, consents, or other authorizations or approvals of the Commission legally required under the Public Utility Holding Company Act of 1935, as amended, for the issuance and delivery of the Notes have been obtained; such orders are sufficient for the issuance and the delivery of the Notes; the issuance and the delivery of the Notes conform in all material respects with the terms of such orders; and no other order, consent or other authorization or approval of the States of Delaware, Georgia, Florida, Alabama or United States governmental body (other than in connection or in compliance with the provisions of the securities or "blue sky" laws of any jurisdiction, as to which we express no opinion) is legally required for the issuance and delivery of the Notes in accordance with the terms of the Purchase Agreement. 4 The Indenture has been duly authorized, executed and delivered by the Company and, assuming the due authorization, execution and delivery thereof by the Trustee constitutes a valid and legally binding instrument of the Company, enforceable against the Company in accordance with its terms, subject to the qualifications that the enforceability of the Company's obligations under the Indenture may be limited by bankruptcy, insolvency, reorganization, moratorium and other similar laws relating to or affecting creditors' rights generally and by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law); and the Indenture conforms as to legal matters in all material respects to the description thereof in the Offering Memorandum. 5 The Notes have been duly authorized and executed by the Company and, when authenticated by the Trustee in the manner provided in the Indenture and delivered to and paid for by the Initial Purchasers pursuant to the Purchase Agreement, will constitute valid and binding obligations of the Company, enforceable against the Company in accordance with their terms, subject to the qualifications that the enforceability of the Company's obligations under the Notes may be limited by bankruptcy, insolvency, reorganization, moratorium and other similar laws relating to or affecting creditors' rights generally and by general principles of equity; and the Notes conform as to legal matters in all material respects to the description thereof in the Offering Memorandum. 6 The Registration Rights Agreement has been duly authorized, executed and delivered by the Company and, assuming the due authorization, execution and delivery thereof by the other parties thereto, constitutes a valid and legally binding instrument of the Company, enforceable against the Company in accordance with its terms, except to the extent that the enforceability of the Company's obligations under the Registration Rights Agreement may be limited by bankruptcy, insolvency, reorganization, moratorium and other similar laws relating to or affecting creditors' rights generally and by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law) and except to the extent indemnification or contribution provisions thereunder may be limited under applicable law; the Registration Rights Agreement conforms in all material respects to all statements relating thereto in the Offering Memorandum. 7 The statements as to matters of law and legal conclusions contained in the Offering Memorandum under the caption "Certain U.S. Federal Income Tax Considerations" are correct in all material respects. 8 Assuming (a) the accuracy of the representations and warranties of the Company set forth in Section 1 of the Purchase Agreement and of the Initial Purchasers set forth in Section 2 of the Purchase Agreement, (b) the due performance by the Company of the covenants and agreements set forth in Section 3 of the Purchase Agreement and the due performance by the Initial Purchasers of the covenants and agreements set forth in Section 2 of the Purchase Agreement, (c) compliance by the Initial Purchasers with the offering and transfer procedures and restrictions described in the Offering Memorandum and (d) the accuracy of the representations and warranties made in accordance with the Offering Memorandum by purchasers to whom the Initial Purchasers initially resells the Notes, the offer, sale and delivery of the Notes to the Initial Purchasers in the manner contemplated by the Purchase Agreement and the Offering Memorandum and the initial resale of the Notes by the Initial Purchasers in the manner contemplated in the Offering Memorandum and the Purchase Agreement do not require registration of the Notes under the Securities Act (it being understood that we express no opinion as to any subsequent resale of any Notes) and the Indenture is not required to be qualified under the Trust Indenture Act. 9 The execution, delivery and performance by the Company of the Agreement does not and will not result in any violation of the Certificate of Incorporation or the By-Laws of the Company, and do not and will not conflict with, or result in a breach of any of the terms or provisions of, or constitute a default under, or result in the creation or imposition of any lien, charge or encumbrance upon any property or assets of the Company under (A) any material contract, indenture, mortgage, loan agreement, note, lease or any other agreement or instrument known to us to which the Company is a party or by which it may be bound or to which any of its properties may be subject (except for such conflicts, breaches or defaults or liens, charges or encumbrances that would not have a material adverse effect on the condition (financial or otherwise) of the Company), (B) any existing applicable law, rule or regulation applicable to the Company (other than the securities or blue sky laws of any jurisdiction, as to which we express no opinion) or (C) any judgment, order or decree known to us of any government, governmental instrumentality, or court, domestic or foreign, or any regulatory body or administrative agency or other governmental body having jurisdiction over the Company. 10 The Company is not, nor after giving effect to the sale of the Notes will be, an "investment company" or a company "controlled" by an "investment company" within the meaning of the Investment Company Act of 1940, as amended. We have not independently verified the accuracy, completeness or fairness of the statements made or included in the Offering Memorandum and take no responsibility therefor, except as and to the extent set forth in paragraphs 4, 5, 6 and 7 above. In the course of the preparation by the Company of the Offering Memorandum, we participated in conferences with certain officers and employees of the Company, with representatives of Deloitte & Touche LLP and with your counsel. Based upon our examination of the Offering Memorandum, our investigations made in connection with the preparation of the Offering Memorandum and our participation in the conferences referred to above, nothing came to our attention which gives us reason to believe that the Offering Memorandum, as of its date, contained, or on the date hereof contains, any untrue statement of a material fact or omitted as of its date or omits as of the date hereof to state any material fact required to be stated therein or necessary in order to make the statements therein not misleading, except that in each case we express no opinion or belief with respect to (i) the financial statements or other financial or statistical data contained in the Offering Memorandum or (ii) the Independent Engineer's Report or the Independent Market Expert's Report attached as Annex A and B, respectively, to the Offering Memorandum. We are members of the State Bars of Alabama and Georgia and we do not express any opinion herein concerning any law other than the laws of such States and, to the extent set forth herein, the law of the States of New York, Florida, Delaware General Corporation Law and the federal law of the United States. This opinion is rendered to you in connection with the above-described transaction. This opinion may not be relied upon by you for any other purpose, or relied upon by or furnished to any other person without our prior written consent. Yours very truly, BALCH & BINGHAM LLP Schedule III [Letterhead of PILLSBURY WINTHROP LLP] __________, 2003 Citigroup Global Markets Inc. 388 Greenwich Street New York, New York 10013 Lehman Brothers Inc. 745 Seventh Avenue New York, New York 10019 As representatives of the several initial purchasers (the "Initial Purchasers") named on Schedule I to the Purchase Agreement dated ____, 2003 among the Initial Purchasers and Southern Power Company (the "Company") Southern Power Company 270 Peachtree Street, N.W. Atlanta, Georgia 30303 Southern Power Company ___% Senior Notes, Series C due July 15, 2015 Ladies and Gentlemen: We have acted as counsel for The Bank of New York, a New York banking corporation ("BNY") in connection with the several purchases by the Initial Purchasers of $575,000,000 aggregate principal amount of ___% Senior Notes, Series C due July 15, 2015 (the "Notes") issued by the Company. The Notes are being issued under the Senior Note Indenture dated as of June 1, 2002 between the Company and BNY, as trustee (in such capacity, the "Trustee"), as heretofore supplemented and as further supplemented by the Second Supplemental Indenture dated as of _____, 2003 between the Company and the Trustee (collectively, the "Indenture"). For purposes of this opinion, we have reviewed the Indenture and such other documents, records and papers, and satisfied ourselves as to such other matters, as we have deemed necessary or appropriate for this opinion. As to questions of fact material to this opinion, we have relied on certificates of BNY and of public officials. In such review, we have assumed the genuineness of all signatures, the legal capacity of natural persons, the authenticity of all documents submitted to us as originals, the conformity to the originals of all documents submitted to us as copies or forms and the authenticity of the originals of such latter documents. We have assumed that BNY has been duly incorporated and that the Indenture has been duly authorized, executed and delivered by the Company and constitutes the valid and binding agreement of, and is enforceable in accordance with its terms against, the Company. Based upon the foregoing and subject to the qualifications below, we are of the opinion that: 1) BNY is a banking corporation validly existing under the laws of the State of New York with corporate power and authority to enter into and perform its obligations under the Indenture. 2) The Indenture has been duly authorized, executed and delivered by BNY and constitutes a valid and binding agreement of BNY enforceable against BNY in accordance with its terms, except as may be limited by bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium and other similar laws relating to or affecting creditors' rights generally and general equitable principles (whether considered in a proceeding in equity or at law) and by an implied covenant of reasonableness, good faith and fair dealing. We are members of the Bar of the State of New York and, for purposes of this opinion, do not hold ourselves out as experts on the laws of any jurisdiction other than the State of New York. The opinions expressed herein are limited to matters governed by the laws of the State of New York This opinion is solely for the benefit of the Company and the several Initial Purchasers in connection with the issuance and sale by the Company of the Notes and may not be relied upon by the Company or the several Initial Purchasers for any other purpose, or relied upon or furnished to any other person, without our prior written consent. Very truly yours, PILLSBURY WINTHROP LLP Schedule IV [Letterhead of DEWEY BALLANTINE LLP] _____, 2003 Citigroup Global Markets Inc. 388 Greenwich Street New York, New York 10013 Lehman Brothers Inc. 745 Seventh Avenue New York, New York 10019 As Representatives of the Several Initial Purchasers SOUTHERN POWER COMPANY ___% Senior Notes, Series C due July 15, 2015 Ladies and Gentlemen: We have represented you in connection with (i) the issuance by Southern Power Company (the "Company") of $575,000,000 of its ___% Senior Notes, Series C due July 15, 2015 (the "Notes") pursuant to a Senior Note Indenture dated as of June 1, 2002, by and between the Company and The Bank of New York, as trustee (the "Trustee"), as heretofore supplemented and as further supplemented by the Second Supplemental Indenture dated as of ____, 2003 (collectively, the "Indenture"); and (ii) the purchase by you of the Notes pursuant to the terms of a Purchase Agreement dated June ___, 2003, among the Company and the initial purchasers named in Schedule I thereto (the "Initial Purchasers") for whom you are acting as Representatives (the "Purchase Agreement"). The Notes are subject to the Registration Rights Agreement dated the date hereof by and among the Company and the Representatives (the "Registration Rights Agreement"). This opinion is being delivered to you as Representatives pursuant to Section 5(c)(4) thereof. All capitalized terms not otherwise defined herein shall have the meanings set forth in the Purchase Agreement. In rendering the opinions expressed below, we have examined the Offering Memorandum dated _________, 2003 (the "Offering Memorandum"), the Indenture, the Notes, the Registration Rights Agreement and the Purchase Agreement. In addition, we have examined, and have relied as to matters of fact upon, the documents delivered to you at the closing (except the Notes, of which we have examined specimens), and we have made such other and further investigations as we deemed necessary to express the opinions hereinafter set forth. In such examination, we have assumed the genuineness of all signatures, the legal capacity of natural persons, the authenticity of all documents submitted to us as originals, the conformity to original documents of all documents submitted to us as certified or photostatic copies and the authenticity of the originals of such latter documents. The Indenture, the Registration Rights Agreement, the Notes and the Purchase Agreement are herein referred to as the "Agreements". Based upon the foregoing, and subject to the qualifications and limitations stated herein, we are of the opinion: 1. The Company has been duly incorporated and is validly existing as a corporation in good standing under the laws of the State of Delaware and has due corporate authority to conduct its business and to own and operate the properties used by it in such business as described in the Offering Memorandum and to enter into and perform its obligations under the Agreements. 2. The execution, delivery and performance by the Company of the Purchase Agreement have been duly authorized by all necessary corporate action, and the Purchase Agreement has been duly executed and delivered by the Company. 3. All orders, consents, or other authorizations or approvals of the Commission legally required under the Public Utility Holding Company Act of 1935, as amended, for the issuance and delivery of the Notes have been obtained; such orders are sufficient for the issuance and delivery of the Notes; the issuance and delivery of the Notes conform in all material respects with the terms of such orders; and no other order, consent or other authorization or approval of the State of New York or United States governmental body (other than in connection or in compliance with the provisions of the securities or "blue sky" laws of any jurisdiction, as to which we express no opinion) is legally required for the issuance and delivery of the Notes in accordance with the terms of the Purchase Agreement. 4. The Indenture has been duly authorized, executed and delivered by the Company and, assuming the due authorization, execution and delivery thereof by the Trustee constitutes a valid and legally binding instrument of the Company, enforceable against the Company in accordance with its terms, subject to the qualifications that the enforceability of the Company's obligations under the Indenture may be limited by bankruptcy, insolvency, reorganization, moratorium and other similar laws relating to or affecting creditors' rights generally and by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law); and the Indenture conforms as to legal matters in all material respects to the description thereof in the Offering Memorandum. 5. The Notes have been duly authorized and executed by the Company and, when authenticated by the Trustee in the manner provided in the Indenture and delivered to and paid for by the Initial Purchasers pursuant to the Purchase Agreement, will constitute valid and binding obligations of the Company enforceable against the Company in accordance with their terms, subject to the qualifications that the enforceability of the Company's obligations under the Notes may be limited by bankruptcy, insolvency, reorganization, moratorium and other similar laws relating to or affecting creditors' rights generally and by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law); and the Notes conform as to legal matters in all material respects to the description thereof in the Offering Memorandum. 6. The Registration Rights Agreement has been duly authorized, executed and delivered by the Company and, assuming the due authorization, execution and delivery thereof by the other parties thereto, constitutes a valid and legally binding instrument of the Company, enforceable against the Company in accordance with its terms, except to the extent that the enforceability of the Company's obligations under the Registration Rights Agreement may be limited by bankruptcy, insolvency, reorganization, moratorium and other similar laws relating to or affecting creditors' rights generally and by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law) and except to the extent indemnification or contribution provisions thereunder may be limited under applicable law; the Registration Rights Agreement conforms in all material respects to all statements relating thereto in the Offering Memorandum. 7. Assuming (a) the accuracy of the representations and warranties of the Company set forth in Section 1 of the Purchase Agreement and of the Initial Purchasers set forth in Section 2 of the Purchase Agreement, (b) the due performance by the Company of the covenants and agreements set forth in Section 3 of the Purchase Agreement and the due performance by the Initial Purchasers of the covenants and agreements set forth in Section 2 of the Purchase Agreement, (c) compliance by the Initial Purchasers with the offering and transfer procedures and restrictions described in the Offering Memorandum and (d) the accuracy of the representations and warranties made in accordance with the Offering Memorandum by purchasers to whom the Initial Purchasers initially resells the Notes, the offer, sale and delivery of the Notes to the Initial Purchasers in the manner contemplated by the Purchase Agreement and the Offering Memorandum and the initial resale of the Notes by the Initial Purchasers in the manner contemplated in the Offering Memorandum and the Purchase Agreement do not require registration of the Notes under the Securities Act (it being understood that we express no opinion as to any subsequent resale of any Notes) and the Indenture is not required to be qualified under the Trust Indenture Act. We have not independently verified the accuracy, completeness or fairness of the statements made or included in the Offering Memorandum and take no responsibility therefor, except as and to the extent set forth in paragraphs 4, 5 and 6 above. In the course of the preparation by the Company of the Offering Memorandum, we participated in conferences with certain officers and employees of the Company, with representatives of Deloitte & Touche LLP and with your counsel. Based upon our examination of the Offering Memorandum, our investigations made in connection with the preparation of the Offering Memorandum and our participation in the conferences referred to above, nothing came to our attention which gives us reason to believe that the Offering Memorandum, as of its date, contained, or on the date hereof contains, any untrue statement of a material fact or omitted as of its date or omits as of the date hereof to state any material fact required to be stated therein or necessary in order to make the statements therein not misleading, except that in each case we express no opinion or belief with respect to (i) the financial statements or other financial or statistical data contained in the Offering Memorandum or (ii) the Independent Engineer's Report or the Independent Market Expert's Report attached as Annex A and Annex B, respectively, to the Offering Memorandum. We are members of the State Bar of New York and we do not express any opinion herein concerning any law other than the law of the State of New York and the federal law of the United States and the general corporation law of the State of Delaware. This opinion is rendered solely to you in connection with the above matter. This opinion may not be relied upon by you for any other purpose or relied upon by or furnished to any other person without our prior written consent except that Balch & Bingham LLP may rely on this opinion in giving their opinions (i) pursuant to Section 5 of the Purchase Agreement, insofar as such opinions relate to matters of New York law, and (ii) pursuant to Sections 102, 302 and 904 of the Indenture, insofar as such opinion relates to matters of New York law. Very truly yours, DEWEY BALLANTINE LLP EX-4.2 4 x4_2.txt Exhibit 4.2 SOUTHERN POWER COMPANY 4.875% Senior Notes, Series C due July 15, 2015 REGISTRATION RIGHTS AGREEMENT New York, New York July 8, 2003 Citigroup Global Markets Inc. 388 Greenwich Street New York, New York 10013 Lehman Brothers Inc. 745 Seventh Avenue New York, New York 10019 As Representatives of the Initial Purchasers Ladies and Gentlemen: Southern Power Company, a corporation organized under the laws of the State of Delaware (the "Company"), proposes to issue and sell, severally and not jointly, to Citigroup Global Markets Inc., Lehman Brothers Inc., Mizuho International plc, Tokyo-Mitsubishi International plc, Barclays Capital Inc., Commerzbank Capital Markets Corp., ING Financial Markets LLC and Scotia Capital (USA) Inc. (the "Initial Purchasers"), upon the terms set forth in a purchase agreement, dated July 1, 2003 (the "Purchase Agreement"), $575,000,000 aggregate principal amount of its 4.875% Senior Notes, Series C due 2015 (the "Securities"), relating to the initial placement of the Securities (the "Initial Placement"). To induce the Initial Purchasers to enter into the Purchase Agreement and to satisfy a condition of your obligations thereunder, the Company agrees with you for your benefit and the benefit of the holders from time to time of the Securities (including the Initial Purchasers) (each a "Holder" and, together, the "Holders"), as follows: 1. Definitions. Each of the capitalized terms used herein without definition shall have the meaning set forth in the Purchase Agreement. As used in this Agreement, the following capitalized defined terms shall have the following meanings: "Act" shall mean the Securities Act of 1933, as amended, and the rules and regulations of the Commission promulgated thereunder. "Affiliate" of any specified Person shall mean any other Person that, directly or indirectly, is in control of, is controlled by, or is under common control with, such specified Person. For purposes of this definition, control of a Person shall mean the power, direct or indirect, to direct or cause the direction of the management and policies of such Person whether by contract or otherwise; and the terms "controlling" and "controlled" shall have meanings correlative to the foregoing. "Broker-Dealer" shall mean any broker or dealer registered as such under the Exchange Act. "Business Day" shall mean any day other than a Saturday, a Sunday or a legal holiday or a day on which banking institutions or trust companies are authorized or obligated by law to close in New York City. "Commission" shall mean the Securities and Exchange Commission. "Exchange Act" shall mean the Securities Exchange Act of 1934, as amended, and the rules and regulations of the Commission promulgated thereunder. "Exchange Offer Registration Period" shall mean the 270-day period following the consummation of the Registered Exchange Offer, exclusive of any period during which any stop order shall be in effect suspending the effectiveness of the Exchange Offer Registration Statement. "Exchange Offer Registration Statement" shall mean a registration statement of the Company on an appropriate form under the Act with respect to the Registered Exchange Offer, all amendments and supplements to such registration statement, including post-effective amendments thereto, in each case including the Prospectus contained therein, all exhibits thereto and any material incorporated by reference therein. "Exchanging Dealer" shall mean any Holder (which may include any Initial Purchaser) that is a Broker-Dealer and elects to exchange for New Securities any Securities that it acquired for its own account as a result of market-making activities or other trading activities (but not directly from the Company or any Affiliate of the Company) for New Securities. "Holder" shall have the meaning set forth in the preamble hereto. "Indenture" shall mean the Indenture dated as of June 1, 2002, between the Company and The Bank of New York, as trustee, as the same may be amended or supplemented from time to time in accordance with the terms thereof. "Initial Placement" shall have the meaning set forth in the preamble hereto. "Initial Purchasers" shall have the meaning set forth in the preamble hereto. "Majority Holders" shall mean the Holders of a majority of the aggregate principal amount of Securities registered under a Registration Statement. "Managing Underwriters" shall mean the investment banker or investment bankers and manager or managers that shall administer an underwritten offering of the Securities offered pursuant to a Shelf Registration Statement. "New Securities" shall mean debt securities of the Company issued under the Indenture that are registered under the Act and are identical in all material respects to each series of the Securities (except that the interest rate step-up provisions and the transfer restrictions shall be modified or eliminated, as appropriate). "Offering Memorandum" shall have the meaning set forth in the Purchase Agreement. "Prospectus" shall mean the prospectus included in any Registration Statement (including, without limitation, a prospectus that discloses information previously omitted from a prospectus filed as part of an effective registration statement in reliance upon Rule 430A under the Act), as amended or supplemented by any prospectus supplement, with respect to the terms of the offering of any portion of the Securities or the New Securities covered by such Registration Statement, and all amendments and supplements thereto and any material incorporated by reference therein. "Purchase Agreement" shall have the meaning set forth in the preamble hereto. "Registered Exchange Offer" shall mean the proposed offer of the Company to issue and deliver to the Holders of the Securities that are not prohibited by any law or policy of the Commission from participating in such offer, in exchange for the Securities, a like aggregate principal amount of the New Securities. "Registration Statement" shall mean any Exchange Offer Registration Statement or Shelf Registration Statement that covers any of the Securities or the New Securities pursuant to the provisions of this Agreement, any amendments and supplements to such registration statement, including post-effective amendments (in each case including the Prospectus contained therein), all exhibits thereto and any material incorporated by reference therein. "Securities" shall have the meaning set forth in the preamble hereto. "Shelf Registration" shall mean a registration effected pursuant to Section 3 hereof. "Shelf Registration Period" has the meaning set forth in Section 3(b) hereof. "Shelf Registration Statement" shall mean a "shelf" registration statement of the Company pursuant to the provisions of Section 3 hereof which covers some or all of the Securities or New Securities, as applicable, on an appropriate form under Rule 415 under the Act, or any similar rule that may be adopted by the Commission, amendments and supplements to such registration statement, including post-effective amendments, in each case including the Prospectus contained therein, all exhibits thereto and any material incorporated by reference therein. "Transfer Restricted Security" means each Security until: (i) the date on which that Security has been exchanged by a person other than a broker-dealer for a freely transferable New Security in the Registered Exchange Offer; (ii) following the exchange by a Broker-Dealer in the Registered Exchange Offer of a Security for a New Security, the date on which that New Security is sold to a purchaser who receives from that Broker-Dealer on or prior to the date of that sale a copy of the Prospectus constituting part of the Exchange Offer Registration Statement; (iii) the date on which that Security has been effectively registered under the Act and disposed of in accordance with the Shelf Registration Statement; or (iv) the date on which that Security is distributed to the public pursuant to Rule 144 under the Act or becomes freely tradeable pursuant to Rule 144(k) under the Act. "Trustee" shall mean the trustee with respect to the Securities under the Indenture. 2. Registered Exchange Offer. (a) To the extent not prohibited by any applicable law or applicable interpretation of the Commission, the Company shall use its best efforts to consummate the Registered Exchange Offer within 270 days of the date of the original issuance of the Securities (or if such 270th day is not a Business Day, the next succeeding Business Day). (b) Upon the effectiveness of the Exchange Offer Registration Statement, the Company shall promptly commence the Registered Exchange Offer, it being the objective of such Registered Exchange Offer to enable each Holder of Transfer Restricted Securities electing to exchange those Transfer Restricted Securities for New Securities (assuming that such Holder is not an Affiliate of the Company, acquires the New Securities in the ordinary course of such Holder's business, has no arrangements with any Person to participate in the distribution of the New Securities and is not prohibited by any law or policy of the Commission from participating in the Registered Exchange Offer ) to trade such New Securities from and after their receipt without any limitations or restrictions under the Act and without material restrictions under the securities laws of a substantial proportion of the several states of the United States. (c) In connection with the Registered Exchange Offer, the Company shall: (i) mail to each Holder a copy of the Prospectus forming part of the Exchange Offer Registration Statement, together with an appropriate letter of transmittal and related documents; (ii) keep the Registered Exchange Offer open for not less than 20 Business Days and not more than 30 Business Days after the date notice thereof is mailed to the Holders (or, in each case, longer if required by applicable law); (iii) use its best efforts to keep the Exchange Offer Registration Statement continuously effective under the Act, supplemented and amended as required, under the Act to ensure that it is available for sales of New Securities by Exchanging Dealers during the Exchange Offer Registration Period; (iv) utilize the services of a depositary for the Registered Exchange Offer with an address in the Borough of Manhattan in New York City, which may be the Trustee or an Affiliate of the Trustee; (v) permit Holders to withdraw tendered Securities at any time prior to the close of business, New York time, on the last Business Day on which the Registered Exchange Offer is open; (vi) prior to effectiveness of the Exchange Offer Registration Statement, provide a supplemental letter to the Commission (A) stating that the Company is conducting the Registered Exchange Offer in reliance on the position of the Commission in Exxon Capital Holdings Corporation (pub. avail. May 13, 1988) and Morgan Stanley and Co., Inc. (pub. avail. June 5, 1991); and (B) including a representation that the Company has not entered into any arrangement or understanding with any Person to distribute the New Securities to be received in the Registered Exchange Offer and that, to the best of the Company's information and belief, each Holder participating in the Registered Exchange Offer is acquiring the New Securities in the ordinary course of business and has no arrangement or understanding with any Person to participate in the distribution of the New Securities; and (vii) comply in all material respects with all applicable laws. (d) As soon as practicable after the close of the Registered Exchange Offer, the Company shall: (i) accept for exchange all Securities tendered and not validly withdrawn pursuant to the Registered Exchange Offer; (ii) deliver to the Trustee for cancellation in accordance with Section 4(q) herein all Securities so accepted for exchange; and (iii) cause the Trustee promptly to authenticate and deliver to each Holder of Securities a principal amount of New Securities equal to the principal amount of the Securities of such Holder so accepted for exchange. (e) Each Holder hereby acknowledges and agrees that any Broker-Dealer and any such Holder using the Registered Exchange Offer to participate in a distribution of the New Securities (x) could not under Commission policy as in effect on the date of this Agreement rely on the position of the Commission in Morgan Stanley and Co., Inc. (pub. avail. June 5, 1991) and Exxon Capital Holdings Corporation (pub. avail. May 13, 1988), as interpreted in the Commission's letter to Shearman & Sterling dated July 2, 1993 and similar no-action letters; and (y) must comply with the registration and prospectus delivery requirements of the Act in connection with any secondary resale transaction and must be covered by an effective registration statement containing the selling security holder information required by Item 507 or 508, as applicable, of Regulation S-K under the Act if the resales are of New Securities obtained by such Holder in exchange for Securities acquired by such Holder directly from the Company or one of its Affiliates. Accordingly, each Holder participating in the Registered Exchange Offer shall be required to represent to the Company that, at the time of the consummation of the Registered Exchange Offer: (i) any New Securities received by such Holder will be acquired in the ordinary course of business; (ii) such Holder will have no arrangement or understanding with any Person to participate in the distribution of the Securities or the New Securities within the meaning of the Act; (iii) such Holder is not an Affiliate of the Company; (iv) if that Holder is not a Broker-Dealer, that it is not engaged in, and does not intend to engage in, any distribution of the New Securities; and (v) if that Holder is a Broker-Dealer, that it will receive New Securities for its own account in exchange for Securities that were acquired as a result of market-making activities or other trading activities and that it will deliver a Prospectus in connection with any resale of those New Securities. (f) Notwithstanding any other provisions hereof, the Company will ensure that (i) any Exchange Offer Registration Statement and any amendment thereto and any Prospectus forming a part thereof and any supplement thereto complies in all material respects with the Act and the rules and regulations thereunder, (ii) any Exchange Offer Registration Statement and any amendment thereto does not, when it becomes effective, contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading and (iii) any Prospectus forming part of any Exchange Offer Registration Statement, and any supplement to such Prospectus, does not include an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading. (g) If following the date hereof there has been announced a change in Commission policy with respect to exchange offers that in the reasonable opinion of counsel to the Company raises a substantial question as to whether the Registered Exchange Offer is permitted by applicable federal law, the Company will seek a no-action letter or other favorable decision from the Commission allowing the Company to consummate the Registered Exchange Offer. The Company will pursue the issuance of such a decision to the Commission staff level. In connection with the foregoing, the Company will take all such other actions as may be requested by the Commission or otherwise required in connection with the issuance of such decision, including without limitation (i) participating in telephonic conferences with the Commission, (ii) delivering to the Commission staff an analysis prepared by counsel to the Company setting forth the legal bases, if any, upon which such counsel has concluded that the Registered Exchange Offer should be permitted and (iii) diligently pursuing a resolution (which need not be favorable) by the Commission staff. 3. Shelf Registration. (a) If (i) due to any change in law or applicable interpretations thereof by the Commission's staff, the Company determines upon the advice of its outside counsel that it is not permitted to effect the Registered Exchange Offer as contemplated by Section 2 hereof; (ii) for any other reason the Registered Exchange Offer is not consummated within 270 days of the date hereof; (iii) any Initial Purchaser so requests with respect to Securities that are not eligible to be exchanged for New Securities in the Registered Exchange Offer and that are held by it following consummation of the Registered Exchange Offer; (iv) any Holder (other than an Exchanging Dealer) is not eligible to participate in the Registered Exchange Offer under applicable law or applicable policies of the Commission; or (v) any Holder (other than an Exchanging Dealer) that participates in the Registered Exchange Offer does not receive freely tradeable New Securities on the date of the exchange for validly tendered (and not withdrawn) Transfer Restricted Securities, the Company shall effect a Shelf Registration Statement in accordance with subsection (b) below (the date on which any of the conditions described in the foregoing clauses (i) through (v) occur, including in the case of clauses (iii), (iv) and (v) the receipt of the required notice, being a "Trigger Date"): (b) (i) To the extent not prohibited by any applicable law or applicable interpretation of the staff of the Commission, the Company shall as promptly as practicable (but in no event more than 50 days after the Trigger Date), prepare and file with the Commission and thereafter shall use its best efforts to cause to be declared effective under the Act a Shelf Registration Statement relating to the offer and sale of the Transfer Restricted Securities or the New Securities, as applicable, by the Holders thereof from time to time in accordance with the methods of distribution elected by such Holders and set forth in such Shelf Registration Statement; provided, however, that no Holder (other than an Initial Purchaser) shall be entitled to have the Transfer Restricted Securities held by it covered by such Shelf Registration Statement unless such Holder agrees in writing to be bound by all of the provisions of this Agreement applicable to such Holder; and provided further, that with respect to New Securities received by an Initial Purchaser in exchange for Securities constituting any portion of an unsold allotment, the Company may, if permitted by current interpretations by the Commission's staff, file a post-effective amendment to the Exchange Offer Registration Statement containing the information required by Item 507 or 508 of Regulation S-K, as applicable, in satisfaction of its obligations under this subsection with respect thereto, and any such Exchange Offer Registration Statement, as so amended, shall be referred to herein as, and governed by the provisions herein applicable to, a Shelf Registration Statement. (ii) The Company shall use its best efforts to keep the Shelf Registration Statement continuously effective, supplemented and amended as required by the Act, in order to permit the Prospectus forming a part thereof to be usable by Holders for a period of two years from the date the Shelf Registration Statement is declared effective by the Commission (or for such longer period if extended pursuant to Section 4(j)) or such shorter period that will terminate when all the Securities or New Securities, as applicable, covered by the Shelf Registration Statement have been sold pursuant to the Shelf Registration Statement (in any such case, such period being called the "Shelf Registration Period"). The Company shall be deemed not to have used its best efforts to keep the Shelf Registration Statement effective during the requisite period if it voluntarily takes any action that would result in Holders of Securities covered thereby not being able to offer and sell such Securities during that period, unless such action is required by applicable law. (iii) Notwithstanding any other provisions of this Agreement to the contrary, the Company shall cause the Shelf Registration Statement and the related Prospectus and any amendment or supplement thereto, as of the effective date of the Shelf Registration Statement, amendment or supplement, (i) to comply in all material respects with the applicable requirements of the Act and the rules and regulations of the Commission and (ii) not to contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading. 4. Additional Registration Procedures. In connection with any Shelf Registration Statement and, to the extent applicable, any Exchange Offer Registration Statement, the following provisions shall apply. (a) The Company shall: (i) furnish to you, not less than five Business Days prior to the filing thereof with the Commission, a copy of any Exchange Offer Registration Statement and any Shelf Registration Statement, and each amendment thereof and each amendment or supplement, if any, to the Prospectus included therein and shall not file any such Registration Statement or amendment thereto or any Prospectus or any supplement thereto (including any documents incorporated by reference therein after the initial filing) to which the Initial Purchasers shall reasonably object in writing, except for any Registration Statement or amendment thereto or Prospectus or supplement thereto (a copy of which has been previously furnished to the Initial Purchasers and their counsel (and, in the case of a Shelf Registration Statement, the Holders and their counsel)) which counsel to the Company has advised the Company in writing is required to be filed, notwithstanding any such objection, in order to comply with applicable law; (ii) include the information set forth in Annex A hereto on the facing page of the Exchange Offer Registration Statement, in Annex B hereto in the forepart of the Exchange Offer Registration Statement in a section setting forth details of the Exchange Offer, in Annex C hereto in the underwriting or plan of distribution section of the Prospectus contained in the Exchange Offer Registration Statement, and in Annex D hereto in the letter of transmittal delivered pursuant to the Registered Exchange Offer; (iii) if requested by an Initial Purchaser, include the information required by Item 507 or 508 of Regulation S-K, as applicable, in the Prospectus contained in the Exchange Offer Registration Statement; and (iv) in the case of a Shelf Registration Statement, include the names of the Holders that propose to sell Securities pursuant to the Shelf Registration Statement as selling security holders. (b) The Company shall advise you, the Holders of Securities covered by any Shelf Registration Statement and any Exchanging Dealer under any Exchange Offer Registration Statement that has provided in writing to the Company a telephone or facsimile number and address for notices, and, if requested by you or any such Holder or Exchanging Dealer, shall confirm such advice in writing (which notice pursuant to clauses (ii)-(v) hereof shall be accompanied by an instruction to suspend the use of the Prospectus until the Company shall have remedied the basis for such suspension): (i) when a Registration Statement and any amendment thereto has been filed with the Commission and when the Registration Statement or any post-effective amendment thereto has become effective; (ii) of any request by the Commission for any amendment or supplement to the Registration Statement or the Prospectus or for additional information; (iii) of the issuance by the Commission of any stop order suspending the effectiveness of the Registration Statement or the initiation of any proceedings for that purpose; (iv) of the receipt by the Company of any notification with respect to the suspension of the qualification of the securities included therein for sale in any jurisdiction or the initiation of any proceeding for such purpose; and (v) of the happening of any event that requires any change in the Registration Statement or the Prospectus so that, as of such date, the statements therein are not misleading and do not omit to state a material fact required to be stated therein or necessary to make the statements therein (in the case of the Prospectus, in the light of the circumstances under which they were made) not misleading. (c) The Company shall use its best efforts to obtain the withdrawal of any order suspending the effectiveness of any Registration Statement or the qualification of the securities therein for sale in any jurisdiction at the earliest possible time. (d) The Company shall furnish to each Holder of Securities covered by any Shelf Registration Statement, without charge, at least one copy of such Shelf Registration Statement and any post-effective amendment thereto, including any material incorporated therein by reference, and, if the Holder so requests in writing, all exhibits thereto (including exhibits incorporated by reference therein). (e) The Company shall, during the Shelf Registration Period, deliver to each Holder of Securities covered by any Shelf Registration Statement, without charge, as many copies of the Prospectus (including each preliminary Prospectus) included in such Shelf Registration Statement and any amendment or supplement thereto as such Holder may reasonably request. The Company consents to the use of the Prospectus or any amendment or supplement thereto by each of the selling Holders of securities in connection with the offering and sale of the securities covered by the Prospectus, or any amendment or supplement thereto, included in the Shelf Registration Statement. (f) The Company shall furnish to each Exchanging Dealer which so requests, without charge, at least one copy of the Exchange Offer Registration Statement and any post-effective amendment thereto, including any material incorporated by reference therein, and, if the Exchanging Dealer so requests in writing, all exhibits thereto (including exhibits incorporated by reference therein). (g) The Company shall promptly deliver to each Initial Purchaser, each Exchanging Dealer and each other Person required to deliver a Prospectus during the Exchange Offer Registration Period, without charge, as many copies of the Prospectus included in such Exchange Offer Registration Statement and any amendment or supplement thereto as any such Person may reasonably request. The Company consents to the use of the Prospectus or any amendment or supplement thereto by any Initial Purchaser, any Exchanging Dealer and any such other Person that may be required to deliver a Prospectus following the Registered Exchange Offer in connection with the offering and sale of the New Securities covered by the Prospectus, or any amendment or supplement thereto, included in the Exchange Offer Registration Statement. (h) Prior to the Registered Exchange Offer or any other offering of Securities pursuant to any Registration Statement, the Company shall arrange, if necessary, for the qualification of the Securities or the New Securities for sale under the laws of such jurisdictions as any Holder shall reasonably request and will maintain such qualification in effect so long as required; provided that in no event shall the Company be obligated to qualify to do business in any jurisdiction where it is not then so qualified or to take any action that would subject it to service of process in suits, other than those arising out of the Initial Placement, the Registered Exchange Offer or any offering pursuant to a Shelf Registration Statement, in any such jurisdiction where it is not then so subject. (i) The Company shall cooperate with the Holders of Securities to facilitate the timely preparation and delivery of certificates representing New Securities or Securities to be issued or sold pursuant to any Registration Statement free of any restrictive legends and in such denominations and registered in such names as Holders may request. (j) Upon the occurrence of any event contemplated by paragraphs (ii) through (v) of Section 4(b) above during the period in which the Company is required to maintain an effective Registration Statement, the Company shall promptly prepare and file a post-effective amendment to the applicable Registration Statement or an amendment or supplement to the related Prospectus or any other required document so that, as thereafter delivered to the Holders or purchasers of the Securities, the Prospectus will not include an untrue statement of a material fact or omit to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading. In such circumstances, the period of effectiveness of the Exchange Offer Registration Statement provided for in Section 2 and the Shelf Registration Statement provided for in Section 3(b) shall each be extended by the number of days from and including the date of the giving of a notice of suspension pursuant to Section 4(b) to and including the date when the Initial Purchasers, the Holders of the Securities and any known Exchanging Dealer shall have received such amended or supplemented Prospectus pursuant to this Section. (k) Not later than the effective date of any Registration Statement, the Company shall provide a CUSIP number for the Securities or the New Securities, as the case may be, registered under such Registration Statement and provide the Trustee with printed certificates for such Securities or New Securities, in a form eligible for deposit with The Depository Trust Company. (l) The Company will comply with all rules and regulations of the Commission to the extent and so long as they are applicable to the Registered Exchange Offer or the Shelf Registration and will make generally available to its security holders (or otherwise provide in accordance with Section 11(a) of the Act) an earnings statement satisfying the provisions of Section 11(a) of the Act, no later than 45 days after the end of a 12-month period (or 90 days, if such period is a fiscal year) beginning with the first month of the Company's first fiscal quarter commencing after the effective date of the Registration Statement, which statement shall cover such 12-month period. (m) The Company represents and warrants that the Indenture has been qualified under the Trust Indenture Act of 1939, as amended. (n) The Company may require each Holder of Securities to be sold pursuant to any Shelf Registration Statement to furnish to the Company such information regarding the Holder and the distribution of such Securities as the Company may from time to time reasonably require for inclusion in such Registration Statement. The Company may exclude from such Shelf Registration Statement the Securities of any Holder that unreasonably fails to furnish such information within a reasonable time after receiving such request and the Company shall be under no further obligations to such Holder to include such Holder in a Shelf Registration Statement. A Holder will not be permitted to sell Securities pursuant to the Shelf Registration Statement unless the Holder has returned to the Company a completed and signed notice electing to be included and furnishing the Holder's name and other information required to be included in the related Prospectus. The Company will send the form of notice and questionnaire to Holders at least 30 calendar days before the effectiveness of the Shelf Registration Statement and Holders will have 28 calendar days to return it. (o) In the case of any Shelf Registration Statement, the Company shall enter into such and take all other appropriate actions (including if requested an underwriting agreement in customary form) in order to expedite or facilitate the registration or the disposition of the Securities, and in connection therewith, if an underwriting agreement is entered into, cause the same to contain indemnification provisions and procedures no less favorable than those set forth in Section 6 (or such other provisions and procedures acceptable to the Majority Holders and the Managing Underwriters, if any, with respect to all parties to be indemnified pursuant to Section 6). (p) In the case of any Shelf Registration Statement, the Company shall: (i) make reasonably available for inspection by the Holders of Securities to be registered thereunder, any underwriter participating in any disposition pursuant to such Registration Statement, and any attorney, accountant or other agent retained by the Holders or any such underwriter all relevant financial and other records, pertinent corporate documents and properties of the Company and its subsidiaries; provided, however, that any information that is designated in writing by the Company, in good faith, as confidential at the time of delivery of such information shall be kept confidential by the Holders or any such underwriter, attorney, accountant or agent, unless such disclosure is made in connection with a court proceeding or required by law (including, without limitation, pursuant to the Act), or such information becomes available to the public generally or through a third party without an accompanying obligation of confidentiality; (ii) cause the Company's officers, directors and employees to supply all relevant information reasonably requested by the Holders or any such underwriter, attorney, accountant or agent in connection with any such Registration Statement as is customary for similar due diligence examinations; provided, however, that any information that is designated in writing by the Company, in good faith, as confidential at the time of delivery of such information shall be kept confidential by the Holders or any such underwriter, attorney, accountant or agent, unless such disclosure is made in connection with a court proceeding or required by law (including, without limitation, pursuant to the Act), or such information becomes available to the public generally or through a third party without an accompanying obligation of confidentiality; (iii) make such representations and warranties to the Holders of Securities registered thereunder and the underwriters, if any, in form, substance and scope as are customarily made by issuers to underwriters in underwritten offerings and covering matters including, but not limited to, those set forth in the Purchase Agreement; (iv) obtain opinions of counsel to the Company and updates thereof (which counsel and opinions (in form, scope and substance) shall be reasonably satisfactory to the Managing Underwriters, if any) addressed to each selling Holder and the underwriters, if any, covering such matters as are customarily covered in opinions requested in underwritten offerings and such other matters as may be reasonably requested by such Holders and underwriters; (v) obtain "cold comfort" letters and updates thereof from the independent certified public accountants of the Company (and, if necessary, any other independent certified public accountants of any subsidiary of the Company or of any business acquired by the Company for which financial statements and financial data are, or are required to be, included in the Registration Statement), addressed to each selling Holder of Securities registered thereunder and the underwriters, if any, in customary form and covering matters of the type customarily covered in "cold comfort" letters in connection with primary underwritten offerings; and (vi) deliver such documents and certificates as may be reasonably requested by the Majority Holders and the Managing Underwriters, if any, including those to evidence compliance with Section 4(k) and with any customary conditions contained in the underwriting agreement or other agreement entered into by the Company. The actions set forth in clauses (i) through (vi) of this paragraph (p) shall be performed at each closing under any underwriting or similar agreement as and to the extent required thereunder. (q) If a Registered Exchange Offer is to be consummated: (i) upon delivery of the Securities by Holders to the Company (or to such other Person as directed by the Company) in exchange for the New Securities, the Company shall mark, or cause to be marked, on the Securities so exchanged that such Securities are being canceled in exchange for the New Securities (in no event shall the Securities be marked as paid or otherwise satisfied); and (ii) if requested by any Initial Purchaser or any known Exchanging Dealer, the Company shall cause (A) its counsel to deliver to such Initial Purchaser or such Exchanging Dealer a signed opinion in the form set forth in Section 5 of the Purchase Agreement with such changes as are customary in connection with the preparation of a Registration Statement and (B) its independent public accountants to deliver to such Initial Purchaser or such Exchanging Dealer a comfort letter, in customary form, meeting the requirements as to the substance thereof as set forth in Section 5 of the Purchase Agreement, with appropriate date changes. (r) The Company will use its best efforts (i) if the Securities have been rated prior to the initial sale of such Securities pursuant to the Purchase Agreement, to confirm such ratings will apply to the Securities or the New Securities, as the case may be, covered by a Registration Statement; or (ii) if the Securities were not previously rated, to cause the Securities covered by a Registration Statement to be rated with at least one nationally recognized statistical rating agency, if so requested by Majority Holders with respect to the related Registration Statement or by any Managing Underwriters. (s) In the event that any Broker-Dealer shall underwrite any Securities or participate as a member of an underwriting syndicate or selling group or "assist in the distribution" (within the meaning of the Rules of Fair Practice and the By-Laws of the National Association of Securities Dealers, Inc.) thereof, whether as a Holder of such Securities or as an underwriter, a placement or sales agent or a broker or dealer in respect thereof, or otherwise, the Company will assist such Broker-Dealer in complying with the requirements of such Rules and By-Laws, including, without limitation, by: (i) if such Rules or By-Laws shall so require, engaging a "qualified independent underwriter" (as defined in such Rules) to participate in the preparation of the Registration Statement, to exercise usual standards of due diligence with respect thereto and, if any portion of the offering contemplated by such Registration Statement is an underwritten offering or is made through a placement or sales agent, to recommend the yield of such Securities; (ii) indemnifying any such qualified independent underwriter to the extent of the indemnification of underwriters provided in Section 6 hereof; and (iii) providing such information to such Broker-Dealer as may be required in order for such Broker-Dealer to comply with the requirements of such Rules. (t) The Company shall use its best efforts to take all other steps necessary to effect the registration of the Securities or the New Securities, as the case may be, covered by a Registration Statement. 5. Registration Expenses. The Company shall bear all expenses incurred in connection with the performance of its obligations under Sections 2, 3 and 4 hereof and, in the event of any Shelf Registration Statement, will reimburse the Holders for the reasonable fees and disbursements of one firm or counsel designated by the Majority Holders to act as counsel for the Holders in connection therewith, and, in the case of any Exchange Offer Registration Statement, will reimburse the Initial Purchasers for the reasonable fees and disbursements of their counsel incurred in connection with their review of the Exchange Offer Registration Statement. 6. Indemnification. (a) The Company agrees to indemnify and hold harmless each Holder, any Exchanging Dealer and each person, if any, who controls any such Holder or Exchanging Dealer within the meaning of Section 15 of the Act or Section 20(a) of the Exchange Act, against any and all losses, claims, damages or liabilities, joint or several, to which they or any of them may become subject under the Act, Exchange Act or otherwise, and to reimburse such Holder, such Exchanging Dealer and such controlling person or persons, if any, for any legal or other expenses incurred by them in connection with defending any actions, insofar as such losses, claims, damages, liabilities or actions arise out of or are based upon any untrue statement or alleged untrue statement of a material fact contained in any Registration Statement or Prospectus (as amended or supplemented if the Company shall have furnished any amendment or supplement thereto), or arise out of or are based upon any omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading, except insofar as such losses, claims, damages, liabilities or actions arise out of or are based upon any such untrue statement or alleged untrue statement or omission or alleged omission which was made in any Registration Statement or Prospectus in reliance upon and in conformity with information furnished in writing to the Company by the Holders or Exchanging Dealers for use therein and except that this indemnity with respect to any Prospectus, shall not inure to the benefit of any Holder or Exchanging Dealer (or of any person controlling such Holder or Exchanging Dealer) on account of any losses, claims, damages, liabilities or actions arising from the sale of the Securities or the New Securities to any person if a copy of the Prospectus, as the same may then be amended or supplemented, shall not have been sent or given by or on behalf of such Holder or Exchanging Dealer to such person with or prior to the written confirmation of the sale involved and the untrue statement or alleged untrue statement or omission or alleged omission was corrected in the Prospectus as supplemented or amended at the time of such confirmation. Each Holder and Exchanging Dealer agrees, within ten days after the receipt by it of notice of the commencement of any action in respect of which indemnity may be sought by it, or by any person controlling it, from the Company on account of its agreement contained in this Section 6, to notify the Company in writing of the commencement thereof but the omission of such Holder or Exchanging Dealer so to notify the Company of any such action shall not release the Company from any liability which it may have to such Holder or Exchanging Dealer or to such controlling person otherwise than on account of the indemnity agreement contained in this Section 6. In case any such action shall be brought against a Holder or Exchanging Dealer or any such person controlling such Holder or Exchanging Dealer and such Holder or Exchanging Dealer shall notify the Company of the commencement thereof as above provided, the Company shall be entitled to participate in (and, to the extent that it shall wish, including the selection of counsel, to direct) the defense thereof, at its own expense. In case the Company elects to direct such defense and select such counsel, any Holder or Exchanging Dealer or controlling person shall have the right to employ its own counsel, but, in any such case, the fees and expenses of such counsel shall be at the expense of such Holder or Exchanging Dealer or such controlling person unless the employment of such counsel has been authorized in writing by the Company in connection with defending such action. No indemnifying party shall, without the written consent of the indemnified party, effect the settlement or compromise of, or consent to the entry of any judgment with respect to, any pending or threatened action or claim in respect of which indemnification may be sought hereunder (whether or not the indemnified party is an actual or potential party to such action or claim) unless such settlement, compromise or judgment (i) includes an unconditional release of the indemnified party from all liability arising out of such action or claim and (ii) does not include any statement as to, or an admission of, fault, culpability or a failure to act, by or on behalf of any indemnified party. In no event shall any indemnifying party have any liability or responsibility in respect of the settlement or compromise of, or consent to the entry of any judgment with respect to, any pending or threatened action or claim effected without its prior written consent. (b) Each Holder and Exchanging Dealer agrees severally and not jointly, to indemnify and hold harmless the Company and each of the Company's directors and officers and each person, if any, who controls the Company within the meaning of Section 15 of the Act or Section 20(a) of the Exchange Act to the same extent and upon the same terms as the indemnity agreement of the Company set forth in Section 6(a) hereof, but only with respect to alleged untrue statements or omissions made in any Registration Statement or Prospectus in reliance upon and in conformity with information furnished in writing to the Company by such Holder or Exchanging Dealer for use therein. (c) The agreements contained in this Section 6 shall survive the sale of the Securities or New Securities pursuant to a Registration Statement and shall remain in full force and effect, regardless of any termination or cancellation of this Agreement or any investigation made by or on behalf of any indemnified party. 7. Additional Interest Under Certain Circumstances. (a) Additional interest (the "Additional Interest") with respect to the Securities will be assessed as follows if any of the following events occurs (each event identified in clauses (i) through (v) below, an "Additional Interest Event"): (i) If all Transfer Restricted Securities properly tendered to the Company have not been exchanged for New Securities on or prior to the 270th day following the date of the original issuance of the Securities; or (ii) If the Shelf Registration Statement has not been declared effective on or prior to the 270th day following the date of the original issuance of the Securities; or (iii)If, after the Exchange Offer Registration Statement is declared effective, such Exchange Offer Registration Statement thereafter ceases to be effective or usable at any time during the required period specified within this Agreement; or (iv) Whether or not the Registered Exchange Offer is consummated, any required Shelf Registration Statement is not filed as promptly as practicable, and in any event within 50 days, following the Trigger Event giving rise to the requirement to file a Shelf Registration Statement in accordance with this Agreement; or (v) If, after any Shelf Registration Statement is declared effective, (A) such Shelf Registration Statement thereafter ceases to be effective during the Shelf Registration Period; or (B) such Shelf Registration Statement or the related Prospectus ceases to be usable in connection with resales of Transfer Restricted Securities during the Shelf Registration Period (except as permitted in paragraph (b) of this Section 7) because either (1) any event occurs as a result of which the related Prospectus forming part of such Shelf Registration Statement would include any untrue statement of a material fact or omit to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were made not misleading, or (2) it shall be necessary to amend such Shelf Registration Statement, or supplement the related Prospectus, to comply with the Act or the Exchange Act or the respective rules thereunder. Additional Interest shall accrue on the Transfer Restricted Securities over and above the interest set forth in the title of the Securities at a rate of 0.50% per annum from and including the date on which any such Additional Interest Event shall occur to, but excluding, the date on which all such Additional Interest Events have been cured or, if earlier, the date on which the Securities may first be resold in reliance on Rule 144(k). Such Additional Interest shall be payable in accordance with Section 7(c). In the event that more than one of the aforementioned Additional Interest Event occurs at the same time, the maximum increase in the interest rate applicable to the Securities shall be 0.50% per annum. (b) An Additional Interest Event referred to in Section 7(a)(v) is deemed not to be continuing in relation to a Shelf Registration Statement or the related Prospectus if (i) that Additional Interest Event has occurred solely as a result of (x) the filing of a post-effective amendment to such Shelf Registration Statement to incorporate annual audited financial information with respect to the Company, when such post-effective amendment is not yet effective and needs to be declared effective to permit Holders to use the related Prospectus or (y) the occurrence of other material events or developments with respect to the Company or its Affiliates that would need to be described in such Shelf Registration Statement or the related Prospectus, and (ii) in the case of clause (y), the Company is proceeding promptly and in good faith to amend or supplement such Shelf Registration Statement and related Prospectus to describe those events or, in the case of material developments that the Company determines in good faith must remain confidential for business reasons, the Company is proceeding promptly and in good faith to take such steps as are necessary so that those developments need no longer remain confidential, but in any case, if any Additional Interest Event (including any referred to in clause (x) or (y), above) continues for a period in excess of 45 days, Additional Interest will be payable in accordance with the above paragraph from the day following the last day of that 45-day period until the date on which that Additional Interest Event is cured or, if earlier, the date on which the Securities may first be resold in reliance on Rule 144(k). (c) Any Additional Interest payable will be payable on the regular interest payment dates with respect to the Securities, in the same manner as the manner in which regular interest is payable. The amount of Additional Interest for any period will be determined by multiplying the applicable Additional Interest rate by the principal amount of the Securities, multiplied by a fraction, the numerator of which is the number of days that Additional Interest rate was applicable during that period (determined on the basis of a 360-day year comprised of twelve 30-day months), and the denominator of which is 360. 8. Rules 144 and 144A. The Company shall use its best efforts to file the reports required to be filed by it under the Act and the Exchange Act in a timely manner. If at any time the Company is not required to file those reports, it will, upon the request of any Holder of Transfer Restricted Securities, make publicly available other information so long as is necessary to permit sales of Securities pursuant to Rules 144 and 144A and otherwise as required by the Indenture. The Company covenants that it will take such further action as any Holder of Transfer Restricted Securities may reasonably request, all to the extent required from time to time to enable that Holder to sell Transfer Restricted Securities without registration under the Securities Act within the limitation of the exemptions provided by Rules 144 and 144A (including the requirements of Rule 144A(d)(4)). Upon request by an Initial Purchaser, the Company will provide a copy of this Agreement to prospective purchasers of Securities identified in writing to the Company by that Initial Purchaser. Upon the request of any Holder of Transfer Restricted Securities, the Company shall deliver to that Holder a written statement as to whether it has complied with these requirements. Notwithstanding the foregoing, nothing in this Section 8 requires the Company to register any of its securities under the Exchange Act. 9. Underwritten Registrations. (a) If any of the Transfer Restricted Securities covered by any Shelf Registration Statement are to be sold in an underwritten offering, the Managing Underwriters shall be selected by the Majority Holders. (b) No Person may participate in any underwritten offering pursuant to any Shelf Registration Statement, unless such Person (i) agrees to sell such Person's Transfer Restricted Securities, as the case may be, on the basis reasonably provided in any underwriting arrangements approved by the Persons entitled hereunder to approve such arrangements; and (ii) completes and executes all questionnaires, powers of attorney, indemnities, underwriting agreements and other documents reasonably required under the terms of such underwriting arrangements. 10. No Inconsistent Agreements. The Company has not, as of the date hereof, entered into, nor shall it, on or after the date hereof, enter into, any agreement with respect to its securities that is inconsistent with the rights granted to the Holders herein or otherwise conflicts with the provisions hereof. 11. Amendments and Waivers. The provisions of this Agreement, including the provisions of this Section 9, may not be amended, qualified, modified or supplemented, and waivers or consents to departures from the provisions hereof may not be given, unless the Company has obtained the written consent of the Majority Holders (or, after the consummation of any Registered Exchange Offer in accordance with Section 2 hereof, of New Securities); provided that, with respect to any matter that directly or indirectly affects the rights of any Initial Purchaser hereunder, the Company shall obtain the written consent of each such Initial Purchaser against which such amendment, qualification, supplement, waiver or consent is to be effective. Notwithstanding the foregoing (except the foregoing proviso), a waiver or consent to departure from the provisions hereof with respect to a matter that relates exclusively to the rights of Holders whose Securities or New Securities, as the case may be, are being sold pursuant to a Registration Statement and that does not directly or indirectly affect the rights of other Holders may be given by the Majority Holders, determined on the basis of Securities or New Securities, as the case may be, being sold rather than registered under such Registration Statement. 12. Notices. All notices and other communications provided for or permitted hereunder shall be made in writing by hand-delivery, first-class mail, telex, telecopier or air courier guaranteeing overnight delivery: (a) if to a Holder, at the most current address given by such holder to the Company in accordance with the provisions of this Section, which address initially is, with respect to each Holder, the address of such Holder maintained by the Registrar under the Indenture, with a copy in like manner to: (i) Lehman Brothers Inc., 745 Seventh Avenue, New York, New York 10019, Attention: John Veech; (ii) Citigroup Global Markets Inc., 388 Greenwich Street, New York, New York 10013, Attention: Barry P. Gold and (iii) Dewey Ballantine LLP, 1301 Avenue of the Americas, New York, New York 10019, Attention: Peter K. O'Brien; (b) if to you, initially at the respective addresses set forth in the Purchase Agreement; and (c) if to the Company, initially at its address set forth in the Purchase Agreement. All such notices and communications shall be deemed to have been duly given when received. The Initial Purchasers or the Company by notice to the other parties may designate additional or different addresses for subsequent notices or communications. 13. Successors. This Agreement shall inure to the benefit of and be binding upon the successors and assigns of each of the parties, including, without the need for an express assignment or any consent by the Company thereto, subsequent Holders of Securities and the New Securities. The Company hereby agrees to extend the benefits of this Agreement to any Holder of Securities and the New Securities, and any such Holder may specifically enforce the provisions of this Agreement as if an original party hereto. 14. Counterparts. This agreement may be in signed counterparts, each of which shall be an original and all of which together shall constitute one and the same agreement. 15. Headings. The headings used herein are for convenience only and shall not affect the construction hereof. 16. Applicable Law. This Agreement shall be governed by and construed in accordance with the laws of the State of New York applicable to contracts made and to be performed in the State of New York. 17. Severability. In the event that any one or more of the provisions contained herein, or the application thereof in any circumstances, is held invalid, illegal or unenforceable in any respect for any reason, the validity, legality and enforceability of any such provision in every other respect and of the remaining provisions hereof shall not be in any way impaired or affected thereby, it being intended that all of the rights and privileges of the parties shall be enforceable to the fullest extent permitted by law. 18. Securities Held by the Company, etc. Whenever the consent or approval of Holders of a specified percentage of principal amount of Securities or New Securities is required hereunder, Securities or New Securities, as applicable, held by the Company or its Affiliates (other than subsequent Holders of Securities or New Securities if such subsequent Holders are deemed to be Affiliates solely by reason of their holdings of such Securities or New Securities) shall not be counted in determining whether such consent or approval was given by the Holders of such required percentage. 19. Specific Performance. Without limiting the remedies available to the Holders, the Company acknowledges that any failure by it to comply with its obligations under Sections 2 or 3 hereof may result in material irreparable injury to the Holders for which there is no adequate remedy at law, that it would not be possible to measure damages for such failure precisely and that, in the event of any such failure, any Holder may obtain such relief as is necessary to enforce specifically the obligations of the Company. [signature page follows] If the foregoing is in accordance with your understanding of our agreement, please sign and return to us the enclosed duplicate hereof, whereupon this letter and your acceptance shall represent a binding agreement among the Company and the several Initial Purchasers. Very truly yours, SOUTHERN POWER COMPANY By: __________________________ Name: Title: The foregoing Agreement is hereby confirmed and accepted as of the date first above written. CITIGROUP GLOBAL MARKETS INC. By: __________________________ Name: Title: LEHMAN BROTHERS INC. By: __________________________ Name: Title: For themselves and the other several Initial Purchasers named in Schedule I to the Purchase Agreement. ANNEX A Each Broker-Dealer that receives New Securities for its own account pursuant to the Exchange Offer must acknowledge that it will deliver a prospectus in connection with any resale of such New Securities. 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 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 New Securities received in exchange for Securities where such Securities were acquired by such Broker-Dealer as a result of market-making activities or other trading activities. The Company has agreed that, during the Exchange Offer Registration Period, it will make this Prospectus available to any Broker-Dealer for use in connection with any such resale. See "Plan of Distribution". ANNEX B Each Broker-Dealer that receives New Securities for its own account in exchange for Securities, where such Securities 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 New Securities. See "Plan of Distribution". ANNEX C PLAN OF DISTRIBUTION Each Broker-Dealer that receives New Securities for its own account pursuant to the Exchange Offer must acknowledge that it will deliver a prospectus in connection with any resale of such New Securities. 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 New Securities received in exchange for Securities where such Securities were acquired as a result of market-making activities or other trading activities. The Company has agreed that, during the Exchange Offer Registration Period, it will make this Prospectus, as amended or supplemented, available to any Broker-Dealer for use in connection with any such resale. In addition, until __________, 20___, all dealers effecting transactions in the New Securities may be required to deliver a prospectus.1 The Company will not receive any proceeds from any sale of New Securities by Broker-Dealers. New Securities received by Broker-Dealers for their own accounts pursuant to 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 New Securities or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such 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 and/or the purchasers of any such New Securities. Any Broker-Dealer that resells New Securities 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 New Securities may be deemed to be an "underwriter" within the meaning of the Act and any profit on any such resale of New Securities and any commissions or concessions received by any such Person may be deemed to be underwriting compensation under the 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 Act. During the Exchange Offer Registration Period, the Company 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. The Company has agreed to pay all expenses incident to the Exchange Offer (including the expenses of one counsel for the holder of the Securities) other than commissions or concessions of any broker or dealer and will indemnify the holders of the Securities (including any Broker-Dealers) against certain liabilities, including liabilities under the Act. - -------- 1 In addition, the legend required by Item 502(b) of Regulation S-K will appear on the back cover page of the Exchange Offer Prospectus. ANNEX D Rider A CHECK HERE IF YOU ARE A BROKER-DEALER AND WISH TO RECEIVE 10 ADDITIONAL COPIES OF THE PROSPECTUS AND 10 COPIES OF ANY AMENDMENTS OR SUPPLEMENTS THERETO. Name: -------------------------------------------- Address: -------------------------------------------- Rider B If the undersigned is not a Broker-Dealer, the undersigned represents that it acquired the New Securities in the ordinary course of its business, it is not engaged in, and does not intend to engage in, a distribution of New Securities and it has no arrangements or understandings with any Person to participate in a distribution of the New Securities. If the undersigned is a Broker-Dealer that will receive New Securities for its own account in exchange for Securities, it represents that the Securities to be exchanged for New Securities were acquired by it as a result of market-making activities or other trading activities and acknowledges that it will deliver a Prospectus in connection with any resale of such New Securities; however, by so acknowledging and by delivering a Prospectus, the undersigned will not be deemed to admit that it is an "underwriter" within the meaning of the Act. EX-5.1 5 x5_1.txt Exhibit 5.1 Balch & Bingham LLP Birmingham, Alabama November 14, 2003 Southern Power Company 270 Peachtree Street, N.W. Atlanta, Georgia 30303 Re: Southern Power Company Registration Statement on Form S-4 Ladies and Gentlemen: We have acted as counsel to Southern Power Company, a Delaware corporation (the "Company") in connection with the preparation of the above-referenced Registration Statement on Form S-4 (the "Registration Statement") filed with the Securities and Exchange Commission under the Securities Act of 1933, as amended (the "Securities Act") relating to the proposed exchange of up to $575,000,000 in aggregate principal amount of the Company's 4.875% Senior Notes, Series D due July 15, 2015 (collectively, the "Exchange Senior Notes") for a like principal amount of the Company's issued and outstanding 4.875% Senior Notes, Series C due July 15, 2015 (collectively, the "Original Senior Notes") pursuant to the Indenture, dated as of June 1, 2002 (the "Indenture") and as supplemented and amended by the First Supplemental Indenture dated as of June 18, 2002 and the Second Supplemental Indenture dated as of July 8, 2003 (the "Second Supplemental Indenture"), between the Company and The Bank of New York, as trustee, and as contemplated by the Registration Rights Agreement, dated as of July 8, 2003, by and among the Company and the signatories thereto. We have been requested to furnish our opinion about certain matters regarding the securities being registered by the Registration Statement. In connection therewith, we have examined originals, or copies certified or otherwise identified to our satisfaction, of the Registration Statement, the Indenture, the Second Supplemental Indenture and the form of the Exchange Senior Notes included as Exhibit A to the Second Supplemental Indenture (collectively, the "Documents"). We also have reviewed such matters of law and examined such corporate records and other certificates, agreements and documents as we have deemed relevant and necessary as a basis for the opinions expressed below. In our examination of the documents listed above, we have assumed, without independent investigation, the genuineness of all signatures, the enforceability of the Documents against all parties thereto (other than the Company in the case of the Indenture, the Second Supplemental Indenture and the Exchange Senior Notes), the authenticity of all documents submitted to us as originals, the conformity to the original documents of all documents submitted to us as certified, photostatic, reproduced or conformed copies of valid existing agreements and other documents, the authenticity of all such latter documents and the legal capacity of all individuals who have executed any of the documents. In expressing the opinions set forth below, we have relied upon the factual matters contained in the representations and warranties of the Company made in any of the Documents and upon certificates of public officials and officers of the Company. We also have assumed that the Exchange Senior Notes will be in the form of Exhibit A to the Second Supplemental Indenture. Based upon the foregoing, and subject to the assumptions, exceptions and qualifications set forth in this letter, we are of the opinion that the Exchange Senior Notes to be issued under the Indenture and the Second Supplemental Indenture have been duly authorized by the Company and, when issued, authenticated and delivered as provided in the Indenture and the Second Supplemental Indenture and as contemplated by the Registration Statement, will constitute valid and binding obligations of the Company, enforceable against the Company in accordance with their terms, except as enforceability of such obligations may be subject to (i) bankruptcy, insolvency, reorganization, fraudulent conveyance or transfer, moratorium or other similar laws now or hereafter in effect affecting creditors' rights generally and (ii) general principles of equity (regardless of whether enforceability is considered in a proceeding at law or in equity). In rendering the foregoing opinions, with respect to matters of New York law, we have relied on the opinion of Dewey Ballantine LLP attached hereto as Annex I. This opinion is limited to the matters stated herein and no opinion is implied or may be inferred beyond the matters expressly stated herein. We hereby consent to the filing of this opinion as an exhibit to the Registration Statement and to the reference to us under the caption "Legal Matters" in the prospectus that is included in the Registration Statement. In giving this consent, we do not admit that we come within the category of persons whose consent is required under Section 7 of the Securities Act or the rules and regulations thereunder. Very truly yours, /s/Balch & Bingham LLP BALCH & BINGHAM LLP Dewey Ballantine LLP New York, New York Annex I November 14, 2003 Balch & Bingham LLP 1901 Sixth Avenue North Birmingham, Alabama 35203 Re: Registration Statement on Form S-4 Ladies and Gentlemen: We have acted as counsel to the initial purchasers in the private offering by Southern Power Company, a Delaware corporation (the "Company"), of $575,000,000 aggregate principal amount of its 4.875% Senior Notes, Series C due July 15, 2015 (the "Series C Notes"). In connection with the Company's Registration Statement on Form S-4 (the "Registration Statement") relating to an offer to exchange (the "Exchange Offer") up to $575,000,000 aggregate principal amount of the Company's 4.875% Senior Notes, Series D due July 15, 2015 (the "Series D Notes"), which are being registered under the Securities Act of 1933, as amended (the "Securities Act"), for an equivalent aggregate principal amount of Series C Notes, we have examined (i) the Registration Statement, (ii) the Series C Notes, (iii) the Series D Notes and (iv) the Indenture dated as of June 1, 2002 among the Company, and The Bank of New York, as trustee (the "Trustee"), as heretofore supplemented and amended (the "Indenture") pursuant to which the Series C Notes have been, and the Series D Notes will be, issued. The terms of the Series D Notes will be substantially identical to the Series C Notes, except for certain transfer restrictions and registration rights relating to the Series C Notes. We have also examined the originals, or duplicates or certified or conformed copies, of such records, agreements, instruments and other documents and have made such other and further investigations as we have deemed relevant and necessary in connection with the opinions expressed herein. As to questions of fact material to this opinion, we have relied upon certificates of public officials and of officers and representatives of the Company and its subsidiaries. In rendering the opinions set forth below, we have assumed the genuineness of all signatures, the legal capacity of natural persons, the authenticity of all documents submitted to us as originals, the conformity to original documents of all documents submitted to us as duplicates or certified or conformed copies, and the authenticity of the originals of such latter documents. We also have assumed that the documents we have examined have been duly authorized, executed and delivered by each party thereto, that each party to such documents is validly existing and in good standing under the laws of all jurisdictions where it is conducting business or otherwise is required to be so qualified, and has full power and authority and all necessary consents and approvals to execute, deliver and perform its obligations under such documents. We further have assumed that the Indenture is the valid and binding obligation of the Trustee. Based upon the foregoing, and subject to the qualifications and limitations stated herein, we are of the opinion that, when the Series D Notes are issued, executed, authenticated and delivered in accordance with the terms of the Exchange Offer and the Indenture, the Series D Notes will be valid and binding obligations of the Company enforceable in accordance with their terms, subject to bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium and similar laws relating to or affecting the enforcement of creditors' rights generally and to general equity principles (regardless of whether enforcement is sought in law or equity). We are members of the State Bar of New York and we do not express any opinion concerning any law other than the law of the State of New York. This opinion is furnished for your benefit in connection with your rendering an opinion to the Company to be filed as Exhibit 5.1 to the Registration Statement and we hereby consent to your attaching this opinion as an annex to such opinion. In giving our consent to your attaching this opinion to the opinion being rendered by you, we do not thereby admit that we came within the category of persons whose consent is required under Section 7 of the Securities Act or the rules and regulations thereunder. Very truly yours, /s/Dewey Ballantine LLP DEWEY BALLANTINE LLP EX-12.1 6 x12_1.txt Exhibit 12.1 10/23/2003 SOUTHERN POWER COMPANY Computation of ratio of earnings to fixed charges for the the two years ended December 31, 2002 and the nine months ended September 2003
Nine Months Ended September ------------------- ------------ 2001 2002 2003 ---- ---- ---- EARNINGS AS DEFINED IN ITEM 503 OF REGULATION S-K: Earnings Before Income Taxes $10,718 $82,727 $219,554 Interest expense, net of amounts capitalized 427 8,886 17,930 Distributions on preferred securities of subsidiary 0 0 0 AFUDC - Debt funds 0 0 0 -------- -------- --------- Earnings as defined $11,145 $91,613 $237,484 ======== ======== ========= FIXED CHARGES AS DEFINED IN ITEM 503 OF REGULATION S-K: Interest on long-term debt $ 1,565 $37,085 $ 41,918 Interest on affiliated loans 1,753 7,065 2,770 Interest on interim obligations 0 0 3,134 Amort of debt disc, premium and expense, net 0 47 92 Other interest charges 0 0 31 Distributions on preferred securities of subsidiary 0 0 0 -------- -------- --------- Fixed charges as defined $ 3,318 $44,197 $ 47,945 ======== ======== ========= RATIO OF EARNINGS TO FIXED CHARGES 3.36 2.07 4.95 ===== ===== ====
EX-23.1 7 x23_1.txt Exhibit 23.1 We consent to the incorporation by reference in this Registration Statement of Southern Power Company on Form S-4 of our reports dated February 17, 2003 appearing in the Annual Report on Form 10-K of Southern Power Company for the year ended December 31, 2002 and to the reference to us under the heading "Experts" in the Prospectus, which is part of this Registration Statement. /s/Deloitte & Touche LLP Atlanta, Georgia November 14, 2003 EX-23.3 8 x23_3.txt Exhibit 23.3 R.W. BECK Framingham, MA November 14, 2003 Southern Power Company 270 Peachtree Street Suite 2000 Atlanta, Georgia 30303 Subject: Southern Power Company Registration Statement on Form S-4 Ladies and Gentlemen: This letter is furnished relating to the exchange of unregistered 4.875% Senior Notes, Series C due July 15, 2015 in the aggregate amount of $575,000,000 (the "Original Senior Notes") for registered 4.875% Senior Notes, Series D due July 15, 2015 in the aggregate amount of $575,000,000 (the "Exchange Senior Notes"), as more fully described in the Registration Statement on Form S-4 filed by Southern Power Company ("Southern Power") on November 14, 2003 (the "Registration Statement"), and prepared in connection with the issuance of the Exchange Senior Notes. R.W. Beck, Inc. ("Beck") was retained by Southern Power to act as the Independent Engineer in connection with the issuance of the Original Senior Notes and it prepared its Independent Engineer's Report dated July 1, 2003 (the "Report"), which is included as Annex A to the Registration Statement. Consent is given to the inclusion of the Report in the Registration Statement and to the references to Beck in the Registration Statement. Changed conditions occurring or becoming known after July 1, 2003 could affect the information presented in the Report to the extent of such changes. This letter is not to be used, circulated, quoted or otherwise referred to within or without Southern Power for any purposes other than as specified herein in connection with the Registration Statement, including, but not limited to, the purchase or sale of the Exchange Senior Notes, nor is this letter to be referred to in whole or in part in the Registration Statement or any other document. Very truly yours, R.W. BECK, INC. /s/Kenneth V. Marino Kenneth V. Marino Principal EX-23.4 9 x23_4.txt Exhibit 23.4 PA CONSULTING Broomfield, CO November 14, 2003 Southern Power Company 270 Peachtree Street, N.W. Atlanta, Georgia 30303 Re: Southern Power Company Registration Statement on Form S-4 Ladies and Gentlemen: PA Consulting Group Inc. ("PA Consulting") hereby consents to the inclusion of its Independent Market Expert Report (the "Report") dated May 28, 2003 for the assets of Southern Power Company (the "Company") in the Company's Registration Statement on Form S-4 (the "Registration Statement") filed on November 14, 2003 relating to the Company's offer to exchange an aggregate principal amount of up to $575,000,000 4.875% Senior Notes, Series D due July 15, 2015, which have been registered under the Securities Act of 1933, as amended, for an equal principal amount of the outstanding 4.875% Senior Notes, Series C due July 15, 2015. The Report is included as Appendix B to the Registration Statement. In addition, PA Consulting consents to the inclusion of the summary of the Report contained in the Registration Statement. PA Consulting also hereby consents to all references to it in the Registration Statement. PA Consulting's consent with regard to the foregoing matters is also granted with respect to such matters as they apply in any amendment to the Registration Statement, including any post-effective amendments thereto. PA Consulting's consent to all matters set out in this letter is conditional upon: o in the case of the inclusion of the Report in Appendix B of the Registration Statement, the Report is to be included in its entirety including the disclaimer contained on page i; and o in the case of the inclusion of the summary of the Report in the Registration Statement, such summary shall include, in its entirety, the disclaimer contained on page i. In all other respects, the position as previously agreed shall remain and the conditions set out in the certificate dated July 8, 2003 and our contract of January 20, 2003 shall continue to govern our relationship and your use of our Report. PA CONSULTING GROUP, INC. /s/Todd W. Filsinger By: Todd W. Filsinger Member of PA's Management Group EX-24.1 10 x24_1.txt Exhibit 24.1 November 4, 2003 Thomas A. Fanning and Wayne Boston Dear Sirs: Southern Power Company proposes to file with the Securities and Exchange Commission a Registration Statement on Form S-4 filed with the Securities and Exchange Commission under the Securities Act of 1933, as amended, relating to the proposed exchange of up to $575,000,000 in aggregate principal amount of the Company's 4.875% Senior Notes, Series D due July 15, 2015 for a like principal amount of the Company's issued and outstanding 4.875% Senior Notes, Series C due July 15, 2015. Southern Power Company and the undersigned directors and officers of Southern Power Company, individually as a director and/or as an officer of Southern Power Company, hereby make, constitute and appoint each of you our true and lawful Attorney for each of us and in each of our names, places and steads to sign and cause to be filed with the Securities and Exchange Commission in connection with the foregoing such Registration Statement and appropriate amendment or amendments (including post-effective amendments) thereto. Yours very truly, SOUTHERN POWER COMPANY By /s/W. Paul Bowers W. Paul Bowers President and Chief Executive Officer /s/W. Paul Bowers /s/David M. Ratcliffe W. Paul Bowers David M. Ratcliffe /s/Thomas A. Fanning /s/Cliff S. Thrasher Thomas A. Fanning Cliff S. Thrasher /s/H. Allen Franklin /s/Tommy Chisholm H. Allen Franklin Tommy Chisholm /s/Charles D. McCrary Charles D. McCrary Extract from unanimous written consent of the board of directors of Southern Power Company. - - - - - - - - - - FURTHER RESOLVED, That each officer or director of the Corporation who may be required to execute the Exchange Registration Statement or Shelf Registration Statement or any amendment or amendments thereto to be filed with the Commission, is hereby authorized and empowered, in the name and on behalf of the Corporation, to execute a power of attorney appointing Thomas A. Fanning and E. Wayne Boston his or her true and lawful attorney or attorney-in-fact and agent with the power to act, with or without the other, with full power of substitution and resubstitution, for him or her and in his or her name, place or stead, in his or her capacity as a director or officer or both, as the case may be, of the Corporation, to sign the Exchange Registration Statement or Shelf Registration Statement and any and all amendments thereto and all documents or instruments necessary, appropriate or desirable to enable the Corporation to comply with the Securities Act, other federal and state securities laws and other applicable United States and other laws in connection with the Exchange Offering, and to file the same with the Commission with full power and authority of said attorney-in-fact to do and to perform, in the name and on behalf of each such officer or director, or both, as the case may be, every act whatsoever necessary or appropriate, as fully and for all intents and purposes as such officer or director, or both, as the case may be, might or could do in person; - - - - - - - - - - The undersigned officer of Southern Power Company does hereby certify that the foregoing is a true and correct copy of a resolution duly and regularly adopted at a meeting of the board of directors of Southern Power Company, duly held on May 7, 2003, at which a quorum was in attendance and voting throughout and that said resolution has not since been rescinded but is still in full force and effect. Dated November 14, 2003 SOUTHERN POWER COMPANY By /s/Wayne Boston Wayne Boston Assistant Secretary \ EX-25.1 11 x25_1.txt Exhibit 25.1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ------------------ FORM T-1 STATEMENT OF ELIGIBILITY UNDER THE TRUST INDENTURE ACT OF 1939 OF A CORPORATION DESIGNATED TO ACT AS TRUSTEE ------------------ CHECK IF AN APPLICATION TO DETERMINE ELIGIBILITY OF A TRUSTEE PURSUANT TO SECTION 305(b)(2) ------------------ THE BANK OF NEW YORK (Exact name of trustee as specified in its charter) NEW YORK (State of incorporation if not a U.S. national bank) 13-5160382 (I.R.S. employer identification no.) One Wall Street, New York, New York 10286 (Address of principal executive offices) (Zip Code) ------------------- The Bank of New York 100 Ashford Center North; Suite 520 Atlanta, Georgia 30338 Attn: Ms. Elizabeth Wagner (770) 698-5188 (Name, address and telephone number of agent for service) -------------------- Southern Power Company (Exact name of obligor as specified in its charter) DELAWARE 58-2598670 (State or other jurisdiction of (IRS employer incorporation or organization) identification no.) 270 PEACHTREE STREET, NW ATLANTA, GEORGIA 30303 (404) 506-5000 (Address, zip code and telephone number of principal executive offices) -------------------- 4.875% Senior Notes, Series D due July 15, 2015 (Title of the indenture securities) 1. General Information. Furnish the following information as to the trustee-- (a) Name and address of each examining or supervising authority to which it is subject. Superintendent of Banks of the State of New York 2 Rector Street New York, N.Y. 10006, and Albany, N.Y. 12203 Federal Reserve Bank of New York 33 Liberty Plaza New York, N.Y. 10045 Federal Deposit Insurance Corporation Washington, D.C. 20429 New York Clearing House Association New York, N.Y. 10005 (b) Whether it is authorized to exercise corporate trust powers. Yes. 2. Affiliations with Obligor. If the obligor is an affiliate of the trustee, describe each such affiliation. None. 3-15 Not Applicable 16. List of Exhibits. Exhibits identified in parentheses below, on file with the Commission, are incorporated herein by reference as an exhibit hereto, pursuant to Rule 7a-29 under the Trust Indenture Act of 1939 (the "Act") and 17 C.F.R. 229.10(d). (1) A copy of the Organization Certificate of The Bank of New York (formerly Irving Trust Company) as now in effect, which contains the authority to commence business and a grant of powers to exercise corporate trust powers. (Exhibit 1 to Amendment 1 to Form T-1 filed with Registration Statement No. 33-6215, Exhibits 1a and 1b to Form T-1 filed with Registration Statement No. 33-21672 and Exhibit 1 to Form T-1 filed with Registration Statement No. 33-29637.) (4) A copy of the existing By-laws of the Trustee. (Exhibit 4 to Form T-1 filed with Registration Statement No. 33-31019.) (6) The consent of the Trustee required by Section 321(b) of the Act. (Exhibit 6 to Form T-1 filed with Registration No. 33-44051.) (7) A copy of the latest report of condition of the Trustee published pursuant to law or the requirements of its supervising or examining authority. SIGNATURE Pursuant to the requirements of the Act, the Trustee, The Bank of New York, a corporation organized and existing under the laws of the State of New York, has duly caused this statement of eligibility to be signed on its behalf by the undersigned, thereunto duly authorized, all in the City of Atlanta and the State of Georgia, on the 14th day of November, 2003. THE BANK OF NEW YORK By: /s/Elizabeth T. Wagner Elizabeth T. Wagner, Agent EXHIBIT 6 TO FORM T-1 CONSENT OF TRUSTEE Pursuant to the requirements of Section 321(b) of the Trust Indenture Act of 1939, in connection with the proposed issuance of Southern Power Company Senior Notes, The Bank of New York hereby consents that reports of examinations by Federal, State, Territorial or District Authorities may be furnished by such authorities to the Securities and Exchange Commission upon request therefor. THE BANK OF NEW YORK By: Elizabeth T. Wagner Elizabeth T. Wagner, Agent EXHIBIT 7 TO FORM T-1 Consolidated Report of Condition of THE BANK OF NEW YORK of One Wall Street, New York, N.Y. 10286 And Foreign and Domestic Subsidiaries, a member of the Federal Reserve System, at the close of business June 30, 2003, published in accordance with a call made by the Federal Reserve Bank of this District pursuant to the provisions of the Federal Reserve Act. Dollar Amounts in Thousands ASSETS Cash and balances due from depository institutions: Noninterest-bearing balances and currency and coin............................. $ 4,257,371 Interest-bearing balances........................... 6,048,782 Securities: Held-to-maturity securities......................... 373,479 Available-for-sale securities....................... 18,918,169 Federal funds sold and securities purchased under agreements to resell: Federal funds sold in domestic offices.............. 6,689,000 Securities purchased under agreements to resell..... 5,293,789 Loans and lease financing receivables: Loans and leases held for sale...................... 616,186 Loans and leases, net of unearned income. . . . . 38,342,282 LESS: Allowance for loan and lease losses. . . . . . . . . . 819,982 Loans and leases, net of unearned income and allowance and reserve.................. 37,522,300 Trading assets............................................... 5,741,193 Premises and fixed assets (including capitalized leases)................................. 958,273 Other real estate owned...................................... 441 Investments in unconsolidated subsidiaries and associated companies........................................... 257,626 Customers' liability to this bank on acceptances outstanding.......................... 159,995 Intangible assets Goodwill ............................................ 2,554,921 Other Intangible Assets ............................... 805,938 Other assets................................................. 6,285,971 ----------- Total assets................................................. $96,483,434 =========== LIABILITIES Deposits: In domestic offices................................. $37,264,787 Noninterest-bearing . . . . . . . 15,357,289 Interest-bearing. . . . . . . . . 21,907,498 In foreign offices, Edge and Agreement subsidiaries, and IBFs.................. 28,018,241 Noninterest-bearing . . . . . . . 1,026,601 Interest-bearing. . . . . . . . . 26,991,640 Federal funds purchased and securities sold under agreements to repurchased: Federal funds purchased in domestic offices......... 739,736 Securities sold under agreements to repurchase...... 465,594 Trading liabilities........................................... 2,456,565 Other borrowed money: (includes mortgage indebtedness and obligations under capitalized leases)............................................. 8,994,708 Bank's liability on acceptances executed and outstanding.......................... 163,277 Subordinated notes and debentures............................ 2,400,000 Other liabilities............................................ 7,446,726 ----------- Total liabilities............................................ $87,949,634 =========== Minority interest in consolidated subsidiaries............... 519,472 EQUITY CAPITAL Common stock................................................. 1,135,284 Surplus...................................................... 2,056,273 Retained earnings............................................ 4,694,161 Accumulated other comprehensive income.............................................. 128,610 Other equity capital components.............................. 0 ----------- Total equity capital......................................... 8,014,328 ----------- Total liabilities and equity capital......................... $96,483,434 =========== I, Thomas J. Mastro, Senior Vice President and Comptroller of the above-named bank do hereby declare that this Report of Condition has been prepared in conformance with the instructions issued by the Board of Governors of the Federal Reserve System and is true to the best of my knowledge and belief. Thomas J. Mastro Senior Vice President and Comptroller We, the undersigned directors, attest to the correctness of this Report of Condition and declare that it has been examined by us and to the best of our knowledge and belief has been prepared in conformance with the instructions issued by the Board of Governors of the Federal Reserve System and is true and correct. Thomas A. Renyi ) Gerald L. Hassell ) Directors Alan R. Griffith ) EX-99.1 12 x99_1.txt Exhibit 99.1 LETTER OF TRANSMITTAL SOUTHERN POWER COMPANY OFFER TO EXCHANGE ALL OUTSTANDING 4.875% SENIOR NOTES, SERIES C DUE JULY 15, 2015 FOR 4.875% SENIOR NOTES, SERIES D DUE JULY 15, 2015 WHICH HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933 - -------------------------------------------------------------------------------- THE EXCHANGE OFFER WILL EXPIRE AT 5:00 P.M. NEW YORK CITY TIME ON ____________ ___, 200__, UNLESS EXTENDED (THE "EXPIRATION DATE"). TENDERS MAY BE WITHDRAWN PRIOR TO 5:00 P.M. NEW YORK CITY TIME ON THE EXPIRATION DATE. - -------------------------------------------------------------------------------- The Exchange Agent for the Exchange Offer is: THE BANK OF NEW YORK 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 Attention: Mr. Bernard Arsenec By facsimile: (212) 298-1915 For information or confirmation by telephone: (212) 815-5098 Delivery of this Letter of Transmittal to an address other than as set forth above or transmission via a facsimile number other than the one listed above will not constitute a valid delivery. The undersigned acknowledges receipt of the Prospectus dated _________ ___, 200__ (the "Prospectus") of Southern Power Company, a Delaware corporation (the "Company"), and this Letter of Transmittal (the "Letter of Transmittal"), which together describe the Company's offer (the "Exchange Offer") to exchange $1,000 in principal amount of its 4.875% Senior Notes, Series D due July 15, 2015 (the "Exchange Senior Notes"), which have been registered under the Securities Act of 1933, as amended (the "Securities Act"), for each $1,000 in principal amount of the Company's issued and outstanding 4.875% Senior Notes, Series C due July 15, 2015 (the "Original Senior Notes") from the holders thereof. Capitalized terms used but not defined herein have the meanings given to them in the Prospectus. This Letter of Transmittal is to be used by Holders of Original Senior Notes (i) if certificates representing the Original Senior Notes are to be physically delivered herewith; or (ii) if a tender of Original Senior Notes is to be made by book-entry transfer into the Exchange Agent's account at The Depository Trust Company (the "Book-Entry Transfer Facility") pursuant to the procedure described in the Prospectus unless a Holder uses DTC's Automated Tender Offer Program System as described in Instruction 1; or (iii) if tender of Original Senior Notes is to be made according to the guaranteed delivery procedures described in the Prospectus. The term "Holder" with respect to the Exchange Offer means any person in whose name Original Senior Notes are registered on the books of the Company or any other person who has obtained a properly completed bond power from the registered holder. The undersigned has checked the appropriate boxes below and signed this Letter of Transmittal to indicate the action the undersigned desires to take with respect to the Exchange Offer. Holders who wish to tender their Original Senior Notes must complete this Letter of Transmittal in its entirety. Please read the entire Letter of Transmittal and the Prospectus carefully before checking any box below. Your bank or broker can assist you in completing this form. The instructions included with this Letter of Transmittal must be followed. Questions and requests for assistance or for additional copies of the Prospectus and this Letter of Transmittal may be directed to the Exchange Agent. List below the Original Senior Notes to which this Letter of Transmittal relates. If the space provided below is inadequate, the certificate numbers and principal amounts should be listed on a separate signed schedule affixed to this Letter of Transmittal. The minimum permitted tender is $1,000 in principal amount. All tenders must be in integral multiples of $1,000. - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- DESCRIPTION OF ORIGINAL SENIOR NOTES
- ----- ---------------- ---------------------------------- --------------------- Name(s) and Addresses of Registered Certificate Aggregate Principal Amount Principal Amount Holder(s) (Please fill in) Number(s)* Represented by Certificate(s) Tendered** - ---------------------------------------- -------------- ------------------------------ ------------------ ---------------------------------------------------------------- ---------------------------------------------------------------- ---------------------------------------------------------------- ---------------------------------------------------------------- ---------------------------------------------------------------- Total - ----------------------------------------------------------------------------------------------------------------------
* Need not be completed by book-entry Holders if being tendered by book-entry transfer. ** Unless otherwise indicated, the Holder will be deemed to have tendered the full aggregate principal amount represented by such Original Senior Notes. See Instruction 2. - -------------------------------------------------------------------------------- || Check here if tendered Original Senior Notes are being delivered by book-entry transfer made to an account maintained by the Exchange Agent with the Book-Entry Transfer Facility and complete the following: Name of Tendering Institution(s): -------------------------------------- The Depository Trust Company Account Number: --------------------------- Transaction Code Number: ---------------------------------------------- || Check here if tendered Original Senior Notes are being delivered pursuant to a Notice of Guaranteed Delivery previously sent to the Exchange Agent and complete the following: Name of Registered Holder(s): ------------------------------------------ Window Ticket Number (if any): ---------------------------------------- Date of Execution of Notice of Guaranteed Delivery: ------------------- Name of Institution that Guaranteed Delivery: ------------------------- If Delivered by Book-Entry Transfer: Account Number: Transaction Code Number: ------------------- --------- || Check here if you are a broker-dealer and wish to receive 10 additional copies of the Prospectus and 10 copies of any amendments or supplements thereto: Name: ----------------------------------------------------------------- Address: ----------------------------------------------------------------- PLEASE READ THE ACCOMPANYING INSTRUCTIONS CAREFULLY Ladies and Gentlemen: Subject to the terms and conditions of the Exchange Offer, the undersigned hereby tenders to the Company the principal amount of Original Senior Notes indicated above. Subject to, and effective upon, the acceptance for exchange of the principal amount of Original Senior Notes tendered in accordance with this Letter of Transmittal, the undersigned hereby exchanges, assigns and transfers to, or upon the order of, the Company all of its right, title and interest in and to the Original Senior Notes tendered hereby. The undersigned hereby irrevocably constitutes and appoints the Exchange Agent the undersigned's true and lawful agent and attorney-in-fact (with full knowledge that the Exchange Agent also acts as the agent of the Company) with respect to the tendered Original Senior Notes with full power of substitution to (i) deliver certificates for such Original Senior Notes to the Company and deliver all accompanying evidences of transfer and authenticity to, or upon the order of, the Company and (ii) present such Original Senior Notes for transfer on the books of the Company and receive all benefits and otherwise exercise all rights of beneficial ownership of such Original Senior Notes, all in accordance with the terms of the Exchange Offer. The power of attorney granted in this paragraph shall be deemed irrevocable and coupled with an interest. The undersigned hereby represents and warrants that the undersigned has full power and authority to tender, exchange, assign and transfer the Original Senior Notes tendered hereby and that the Company will acquire good, marketable and unencumbered title thereto, free and clear of all liens, restrictions, charges and encumbrances and not subject to any adverse claim, when the same are acquired by the Company. The undersigned also acknowledges that this Exchange Offer is being made in reliance on the interpretations of the staff of the Securities and Exchange Commission (the "Commission"), as contained in several no action letters issued to third parties. Based on such interpretations of the staff of the Commission set forth in such no-action letters, the Company believes that the Exchange Senior Notes issued pursuant to the Exchange Offer in exchange for the Original Senior Notes may be offered for resale, resold or otherwise transferred by a Holder thereof (other than any such Holder that is a broker-dealer or an "affiliate" of the 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) such Exchange Senior Notes are acquired in the ordinary course of such Holder's business, (ii) at the time of the commencement of the Exchange Offer such Holder has no arrangement with any person to participate in a distribution of the Exchange Senior Notes and (iii) such Holder is not engaged in, and does not intend to engage in, a distribution of the Exchange Senior Notes. By tendering Original Senior Notes in exchange for the Exchange Senior Notes or executing this Letter of Transmittal, the undersigned hereby further represents: (A) that any Exchange Senior Notes acquired in exchange for Original Senior Notes tendered hereby will have been acquired in the ordinary course of business of the person receiving such Exchange Senior Notes, whether or not such person is the Holder, (B) that neither the Holder nor any such other person is engaged in or intends to engage in or has an arrangement or understanding with any person to participate in the distribution of such Exchange Senior Notes within the meaning of the Securities Act and (C) that neither the Holder nor any such other person is an "affiliate," as defined under Rule 405 of the Securities Act, of the Company or any of its subsidiaries or, if the Holder or such other person is an affiliate, that such Holder or other person will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable. If the undersigned is not a broker-dealer, the undersigned represents that it is not engaged in, and does not intend to engage in, a distribution of Exchange Senior Notes. If the undersigned is a broker-dealer that will receive Exchange Senior Notes for its own account in exchange for Original Senior Notes that were acquired as a result of market-making activities or other trading activities, the undersigned acknowledges that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of such Exchange Senior Notes; however, by so acknowledging and by delivering a prospectus, the undersigned will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. If the undersigned is unable to make the foregoing representations, such person may not rely on the applicable interpretations of the staff of the Commission and must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any secondary resale transaction unless such sale is made pursuant to an exemption from such requirements. The undersigned will, upon request, execute and deliver any additional documents deemed by the Exchange Agent or the Company to be necessary or desirable to complete the assignment, transfer and purchase of the Original Senior Notes tendered hereby. All authority conferred or agreed to be conferred in this Letter of Transmittal and every obligation of the undersigned hereunder shall be binding upon the successors, assigns, heirs, executors, administrators, trustees in bankruptcy and legal representatives of the undersigned and shall not be affected by, and shall survive, the death, incapacity or dissolution of the undersigned. The undersigned understands that the valid tender of Original Senior Notes pursuant to the procedures described under the caption "THE EXCHANGE OFFER--Procedures for Tendering" in the Prospectus and in the instructions hereto will constitute a binding agreement between the undersigned and the Company upon the terms and subject to the conditions set forth in the Prospectus and in this Letter of Transmittal. This tender may be withdrawn only in accordance with the procedures set forth in the Prospectus under the caption "THE EXCHANGE OFFER--Withdrawal Rights." See Instruction 10. Unless otherwise indicated in the box entitled "Special Issuance Instructions" below, please issue the Exchange Senior Notes (and, if applicable, substitute certificates representing Original Senior Notes for any Original Senior Notes not exchanged) in the name of the undersigned or, in the case of a book-entry delivery of Original Senior Notes, please credit the account indicated above maintained at the Book-Entry Transfer Facility. Similarly, unless otherwise indicated under the box entitled "Special Delivery Instructions" below, please send the Exchange Senior Notes (and, if applicable, substitute certificates representing Original Senior Notes for any Original Senior Notes not exchanged) to the undersigned at the address shown above in the box entitled "Description of Original Senior Notes." The undersigned recognizes that the Company has no obligation pursuant to the "Special Issuance Instructions" and "Special Delivery Instructions" to transfer any Original Senior Notes from the name of the registered holder(s) thereof if the Company does not accept for exchange any of the Original Senior Notes so tendered. The undersigned acknowledges that the Exchange Offer is subject to the more detailed terms set forth in the Prospectus and, in case of any conflict between the terms of the Prospectus and this Letter of Transmittal, the terms of the Prospectus shall prevail. The undersigned, by completing the box entitled "Description of Original Senior Notes" above and signing this Letter of Transmittal, will be deemed to have tendered the Original Senior Notes as set forth in such box above. PLEASE SIGN HERE AND COMPLETE SUBSTITUTE FORM W-9 BELOW (TO BE COMPLETED BY ALL TENDERING HOLDERS) X , 200__ ------------------------------ -------------------------- X , 200__ ------------------------------- -------------------------- X , 200__ ------------------------------ -------------------------- Signature(s) of Owner(s)) (Date) If a holder is tendering any Original Senior Notes, this Letter of Transmittal must be signed by the registered holder(s) as the name(s) appear(s) on the certificate(s) for the Original Senior Notes or by any person(s) authorized to become registered holder(s) by endorsements and documents transmitted herewith. If signature is by a trustee, executor, administrator, guardian, officer or other person acting in a fiduciary or representative capacity, please set forth full title. See Instruction 3. Name(s): ---------------------------------------------------------------------- (Please Type or Print) Capacity: --------------------------------------------------------------------- Address: --------------------------------------------------------------------- (Including Zip Code) Employer Identification or Social Security Number: --------------------------- SIGNATURE GUARANTEE (IF REQUIRED BY INSTRUCTION 3) Signature(s) Guaranteed by an Eligible Institution: ----------------------------------------------------- (Authorized Signature) Name: ------------------------------------------------------------------------- (Please Type or Print) Title: ------------------------------------------------------------------------ Name of Firm: ----------------------------------------------------------------- Address: ---------------------------------------------------------------------- (Including Zip Code) Dated: , 2002 ----------------------------------- - -------------------------------------------------------------------------------- SPECIAL ISSUANCE INSTRUCTIONS (See Instructions 3 and 4) - -------------------------------------------------------------------------------- To be completed ONLY if certificates for Original Senior Notes not exchanged and/or Exchange Senior Notes are to be issued in the name of and sent to someone other than the person or persons whose signature(s) appear(s) on this Letter of Transmittal below, or if Original Senior Notes delivered by book-entry transfer which are not accepted for exchange are to be returned by credit to an account maintained at the Book-Entry Transfer Facility other than the account indicated above. Issue Exchange Senior Notes and/or Original Senior Notes to: Name(s): ----------------------------------------------------------- (Please Type or Print) Address: ----------------------------------------------------------- (Include Zip Code) PLEASE ALSO COMPLETE SUBSTITUTE FORM W-9 || Credit unexchanged Original Senior Notes delivered by book-entry transfer to the Book-Entry Transfer Facility Account set forth below. - -------------------------------------------------------------------------------- Book-Entry Transfer Facility Account Number (if applicable) - -------------------------------------------------------------------------------- SPECIAL DELIVERY INSTRUCTIONS (See Instructions 3 and 4) - -------------------------------------------------------------------------------- To be completed ONLY if certificates for Original Senior Notes not exchanged and/or Exchange Senior Notes are to be sent to someone other than the person or persons whose signature(s) appear(s) on this Letter of Transmittal below or to such person or persons at an address other than shown in the box entitled "Description of Original Senior Notes" on this Letter of Transmittal above. Mail Exchange Senior Notes and/or Original Senior Notes to: Name(s): ----------------------------------------------------------- (Please Type or Print) Address: ----------------------------------------------------------- (Include Zip Code) IMPORTANT: This Letter of Transmittal or a facsimile hereof (together with the certificates for Original Senior Notes or a book-entry confirmation and all other required documents or the Notice of Guaranteed Delivery) must be received by the Exchange Agent prior to 5:00 p.m., New York City time, on the Expiration Date. PLEASE READ THIS ENTIRE LETTER OF TRANSMITTAL CAREFULLY BEFORE COMPLETING ANY BOX ABOVE. INSTRUCTIONS FORMING PART OF THE TERMS AND CONDITIONS OF THE EXCHANGE OFFER 1. Delivery of this Letter of Transmittal and Original Senior Notes; Guaranteed Delivery Procedures. This Letter of Transmittal is to be completed by Holders of Original Senior Notes either if certificates are to be forwarded herewith or if tenders are to be made pursuant to the procedures for delivery by book-entry transfer set forth in the "THE EXCHANGE OFFER--Book-Entry Transfer" section of the Prospectus unless a Holder uses DTC's Automated Tender Offer Program System as described below. Certificates for all physically tendered Original Senior Notes, or a confirmation of book-entry transfer, as the case may be, as well as a properly completed and duly executed Letter of Transmittal (or manually signed facsimile thereof), with any required signature guarantees, and any other documents required by this Letter of Transmittal, must be received by the Exchange Agent at the address set forth herein on or prior to the Expiration Date, or the tendering Holder must comply with the guaranteed delivery procedures set forth below. Original Senior Notes tendered hereby must be in denominations or principal amount at maturity of $1,000 or any integral multiple thereof. Holders of Original Senior Notes may tender Original Senior Notes by book-entry transfer by crediting the Original Senior Notes to the Exchange Agent's account at DTC in accordance with DTC's Automated Tender Offer Program ("ATOP") and by complying with applicable ATOP procedures with respect to the Exchange Offer. DTC participants that are accepting the Exchange Offer should transmit their acceptance to DTC, which will edit and verify the acceptance and execute a book-entry delivery to the Exchange Agent's account at DTC. DTC will then send a computer-generated message (an "Agent's Message") to the Exchange Agent for its acceptance in which the holder of the Original Senior Notes acknowledges and agrees to be bound by the terms of, and makes the representations and warranties contained in, this Letter of Transmittal, the DTC participant confirms on behalf of itself and the beneficial owners of such Original Senior Notes all provisions of this Letter of Transmittal (including any representations and warranties) applicable to it and such beneficial owner as fully as if it had completed the information required herein and executed and transmitted this Letter of Transmittal to the Exchange Agent. The Exchange Agent must receive such confirmation on or prior to the Expiration Date. Delivery of the Agent's Message by DTC will satisfy the terms of the Exchange Offer as to execution and delivery of a Letter of Transmittal by the participant identified in the Agent's Message. DTC participants may also accept the Exchange Offer by submitting a Notice of Guaranteed Delivery through ATOP. Holders whose certificates for Original Senior Notes are not immediately available or who cannot deliver their certificates and any other required documents to the Exchange Agent on or prior to the Expiration Date, or who cannot complete the procedure for book-entry transfer on a timely basis, may tender their Original Senior Notes pursuant to the guaranteed delivery procedures set forth in "THE EXCHANGE OFFER--Procedures for Tendering--Guaranteed Delivery Procedures" section of the Prospectus. Pursuant to such procedures, (i) such tender must be made through an Eligible Institution (as defined below), (ii) prior to 5:00 p.m., New York City time, on the Expiration Date, the Exchange Agent must receive from such Eligible Institution a properly completed and duly executed Letter of Transmittal (or a facsimile thereof) and Notice of Guaranteed Delivery, substantially in the form provided by the Company (by facsimile transmission, mail or hand delivery), setting forth the name and address of the Holder of Original Senior Notes and the amount of Original Senior Notes tendered, stating that the tender is being made thereby and guaranteeing that within three New York Stock Exchange ("NYSE") trading days after the date of execution of the Notice of Guaranteed Delivery, the certificates for all physically tendered Original Senior Notes in proper form for transfer, or a book-entry confirmation, as the case may be, and any other documents required by this Letter of Transmittal will be deposited by the Eligible Institution with the Exchange Agent, and (iii) the certificates for all physically tendered Original Senior Notes, in proper form for transfer, or a book-entry confirmation, as the case may be, and all other documents required by this Letter of Transmittal, must be received by the Exchange Agent within three NYSE trading days after the date of execution of the Notice of Guaranteed Delivery. The method of delivery of this Letter of Transmittal, the Original Senior Notes and all other required documents is at the election and risk of the tendering Holders, but the delivery will be deemed made only when actually received or confirmed by the Exchange Agent. Instead of delivery by mail it is recommended that Holders use an overnight or hand delivery service. If delivery is by mail, it is suggested that registered mail with return receipt requested, properly insured, be used. In all cases, sufficient time should be allowed to assure delivery to the Exchange Agent prior to 5:00 p.m., New York City time, on the Expiration Date. No Letter of Transmittal or Original Senior Notes should be sent to the Company. See "THE EXCHANGE OFFER" section in the Prospectus. 2. Partial Tenders. If less than all of the Original Senior Notes evidenced by a submitted certificate are to be tendered, the tendering Holder(s) should fill in the aggregate principal amount at maturity of Original Senior Notes to be tendered in the box above entitled "Description of Original Senior Notes" under "Principal Amount Tendered." A new issued certificate representing the balance of nontendered Original Senior Notes of a tendering Holder who physically delivered Original Senior Notes will be sent to such tendering Holder, unless otherwise provided in the appropriate box on this Letter of Transmittal, promptly after the Expiration Date. All of the Original Senior Notes delivered to the Exchange Agent will be deemed to have been tendered unless otherwise indicated. 3. Signatures on this Letter of Transmittal; Bond Powers and Endorsements; Guarantee of Signatures. If this Letter of Transmittal is signed by the registered Holder of the Original Senior Notes tendered hereby, the signature must correspond exactly with the name as written on the face of the certificates without any change whatsoever. If any tendered Original Senior Notes are owned of record by two or more joint owners, all such owners must sign this Letter of Transmittal. If any tendered Original Senior Notes are registered in different names on several certificates, it will be necessary to complete, sign and submit as many separate copies of this Letter of Transmittal as there are different registrations of certificates. When this Letter of Transmittal is signed by the registered Holder or Holders of the Original Senior Notes specified herein and tendered hereby, no endorsements of certificates or separate bond powers are required. If, however, the Exchange Senior Notes are to be issued, or any untendered Original Senior Notes are to be reissued, to a person other than the registered Holder, then endorsements of any certificates transmitted hereby or separate bond powers are required. Signatures on such certificate(s) or bond powers must be guaranteed by an Eligible Institution. If this Letter of Transmittal is signed by a person other than the registered Holder or Holders of any certificate(s) specified herein, such certificates must be endorsed or accompanied by appropriate bond powers, in either case signed exactly as the name or names of the registered Holder or Holders appear(s) on the certificate(s) and signatures on such certificates(s) or bond powers must be guaranteed by an Eligible Institution. If this Letter of Transmittal or any certificates 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, such persons should so indicate when signing, and, unless waived by the Company, proper evidence satisfactory to the Company of their authority to so act must be submitted with this Letter of Transmittal. Endorsements on certificates for Original Senior Notes or signatures on bond powers required by this Instruction 3 must be guaranteed by a financial institution (including 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 (each an "Eligible Institution" and collectively, "Eligible Institutions"). Signatures on the Letter of Transmittal need not be guaranteed by an Eligible Institution if (A) the Original Senior Notes are tendered (i) by a registered Holder of Original Senior Notes who has not completed the box entitled "Special Issuance Instructions" or "Special Delivery Instructions" on this Letter of Transmittal, or (ii) for the account of an Eligible Institution and (B) the box entitled "Special Issuance Instructions" on this Letter of Transmittal has not been completed. 4. Special Issuance and Delivery Instructions. Tendering Holders of Original Senior Notes should indicate in the applicable box the name and address to which Exchange Senior Notes issued pursuant to the Exchange Offer and/or substitute certificates evidencing Original Senior Notes not exchanged are to be issued or sent, if different from the name or address of the person signing this Letter of Transmittal. In the case of issuance in a different name, the employer identification or social security number of the person named must also be indicated. Holders tendering Original Senior Notes by book-entry transfer may request that Original Senior Notes not exchanged be credited to such account maintained at the Book-Entry Transfer Facility as such noteholder may designate hereon. If no such instructions are given, such Original Senior Notes not exchanged will be returned to the name and address of the person signing this Letter of Transmittal. 5. Taxpayer Identification Number. Federal income tax law generally requires that a tendering Holder whose Original Senior Notes are accepted for exchange must provide the Company (as payor) with such Holder's correct Taxpayer Identification Number ("TIN") on Substitute Form W-9 below, which in the case of a tendering Holder who is an individual, is his or her social security number. If the Company is not provided with the current TIN or an adequate basis for an exemption from backup withholding, such tendering Holder may be subject to a $50 penalty imposed by the Internal Revenue Service. In addition, the Exchange Agent may be required to withhold 30% of the amount of any reportable payments made after the exchange to such tendering Holder of Exchange Notes. If withholding results in an overpayment of taxes, a refund may be obtained. Exempt Holders of Original Senior Notes (including, among others, all corporations and certain foreign individuals) are not subject to these backup withholding and reporting requirements. See the enclosed Guidelines of Certification of Taxpayer Identification Number on Substitute Form W-9 (the "W-9 Guidelines") for additional instructions. To prevent backup withholding, each tendering Holder of Original Senior Notes must provide its correct TIN by completing the Substitute Form W-9 set forth below, certifying, under penalties of perjury, that the TIN provided is correct (or that such Holder is awaiting a TIN) and that (i) the Holder is exempt from backup withholding, or (ii) the Holder has not been notified by the Internal Revenue Service that such Holder is subject to backup withholding as a result of a failure to report all interest or dividends or (iii) the Internal Revenue Service has notified the Holder that such Holder is no longer subject to backup withholding. If the tendering Holder of Original Senior Notes is a nonresident alien or foreign entity not subject to backup withholding, such Holder must give the Exchange Agent a completed Form W-8, Certificate of Foreign Status. These forms may be obtained from the Exchange Agent. If the Original Senior Notes are in more than one name or are not in the name of the actual owner, such Holder should consult the W-9 Guidelines for information on which TIN to report. If such Holder does not have a TIN, such Holder should consult the W-9 Guidelines for instructions on applying for a TIN, check the box in Part 2 of the Substitute Form W-9 and write "applied for" in lieu of its TIN. Note: Checking this box and writing "applied for" on the form means that such Holder has already applied for a TIN or that such Holder intends to apply for one in the near future. If the box in Part 2 of the Substitute Form W-9 is checked, the Exchange Agent will retain 30% of reportable payments made to a Holder during the sixty (60) day period following the date of the Substitute Form W-9. If the Holder furnishes the Exchange Agent with his or her TIN within sixty (60) days of the Substitute Form W-9, the Exchange Agent will remit such amounts retained during such sixty (60) day period to such Holder and no further amounts will be retained or withheld from payments made to the Holder thereafter. If, however, such Holder does not provide its TIN to the Exchange Agent within such sixty (60) day period, the Exchange Agent will remit such previously withheld amounts to the Internal Revenue Service as backup withholding and will withhold 30% of all reportable payments to the Holder thereafter until such Holder furnishes its TIN to the Exchange Agent. 6. Transfer Taxes. The Company will pay all transfer taxes, if any, applicable to the transfer of Original Senior Notes pursuant to the Exchange Offer. If, however, Exchange Senior Notes and/or substitute Original Senior Notes not exchanged are to be delivered to, or are to be registered or issued in the name of, any person other than the registered Holder of the Original Senior Notes tendered hereby, or if tendered Original Senior Notes are registered in the name of any person other than the person signing this Letter of Transmittal, or if a transfer tax is imposed for any reason other than the transfer of Original Senior Notes to the Company or its order pursuant to the Exchange Offer, the amount of any such transfer taxes (whether imposed on the registered 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 herewith, the amount of such transfer taxes will be billed directly to such tendering Holder. Except as provided in this Instruction 6, it will not be necessary for transfer tax stamps to be affixed to the Original Senior Notes specified in this Letter of Transmittal. 7. Waiver of Conditions. The Company reserves the absolute right to waive satisfaction of any or all conditions to the Exchange Offer enumerated in the Prospectus. 8. No Conditional Tenders. No alternative, conditional, irregular or contingent tenders will be accepted. All tendering Holders of Original Senior Notes, by execution of this Letter of Transmittal, shall waive any right to receive notice of the acceptance of their Original Senior Notes for exchange. Neither the Company, the Exchange Agent nor any other person is obligated to give notice of any defect or irregularity with respect to any tender of Original Senior Notes nor shall any of them incur any liability for failure to give any such notice. 9. Mutilated, Lost, Stolen or Destroyed Original Senior Notes. Any Holder whose Original Senior Notes have been mutilated, lost, stolen or destroyed should contact the Exchange Agent at the address indicated above for further instructions. 10. Withdrawal of Tenders. Tenders of Original Senior Notes may be withdrawn at any time prior to 5:00 p.m., New York City time, on the Expiration Date. For a withdrawal of a tender of Original Senior Notes to be effective, a written or facsimile transmission notice of withdrawal must be received by the Exchange Agent at its address set forth above prior to 5:00 p.m., New York City time, on the Expiration Date. Any such notice of withdrawal must (i) specify the name of the person having tendered the Original Senior Notes to be withdrawn (the "Depositor"), (ii) identify the Original Senior Notes to be withdrawn (including the certificate number or numbers, if any, and principal amount of such Original Senior Notes), (iii) contain a statement that such Holder is withdrawing his election to have such Original Senior Notes exchanged, (iv) be signed by the Holder in the same manner as the original signature on this Letter of Transmittal by which such Original Senior Notes were tendered (including any required signature guarantees) or be accompanied by documents of transfer sufficient to have the Exchange Agent register the transfer of such Original Senior Notes into the name of the person withdrawing the tender, and (v) specify the name in which any such Original Senior Notes are to be registered, if different from that of the Depositor. If Original Senior Notes have been tendered pursuant to the procedure for book-entry transfer set forth in "THE EXCHANGE OFFER--Book-Entry Transfer" section of the Prospectus, any notice of withdrawal must specify the name and number of the account at the Book-Entry Transfer Facility to be credited with the withdrawn Original Senior Notes and otherwise comply with the procedures of such facility. All questions as to the validity, form and eligibility (including time of receipt) of such notices will be determined by the Company in its sole discretion, which determination shall be final and binding on all parties. Any Original Senior Notes so properly 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 the Holder thereof without cost to such Holder (or, in the case of Original Senior Notes tendered by book-entry transfer into the Exchange Agent's account at the Book-Entry Transfer Facility pursuant to the book-entry transfer procedures set forth in "THE EXCHANGE OFFER--Book-Entry Transfer" section of the Prospectus, such Original Senior Notes will be credited to an account maintained with the Book-Entry Transfer Facility for the Original Senior Notes) 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 the procedures described above at any time on or prior to 5:00 p.m., New York City time, on the Expiration Date. 11. Requests for Assistance or Additional Copies. Questions relating to the procedure for tendering, as well as requests for additional copies of the Prospectus, this Letter of Transmittal and other related documents may be directed to the Exchange Agent, at the address and telephone number indicated above. 12. Irregularities. All questions as to validity, form, eligibility (including time of receipt), and acceptance of this Letter of Transmittal or Original Senior Notes will be resolved by the Company, in its sole discretion, whose determination will be final and binding. The Company reserves the absolute right to reject any or all Letters of Transmittal or tenders that are not in proper form or the acceptance of which would, in the opinion of the Company's counsel, be unlawful. The Company also reserves the right to waive any irregularities or conditions of tender as to the particular Original Senior Notes covered by any Letter of Transmittal or tendered pursuant to such letter. None of the Company, the Exchange Agent or any other person will be under any duty to give notification of any defects or irregularities in tenders or incur any liability for failure to give any such notification. The Company's interpretation of the terms and conditions of the Exchange Offer shall be final and binding. PLEASE COMPLETE SUBSTITUTE FORM W-9 BELOW - -------------------------------------------------------------------------------- PAYOR'S NAME: SOUTHERN POWER COMPANY - -------------------------------------------------------------------------------- SUBSTITUTE PART 1 - Please provide your TIN: FORM W-9 TIN in the box at Social Security Number or right and certify by Employer Identification Number Department of the Treasury signing and dating Internal Revenue Service below. ---------------------------------- ---------------------------------------- Payor's Request for Taxpayer PART 2 - TIN Applied For [ ] Identification Number("TIN") and Certification ------------------------------------------------------------------------------ PART 3 - CERTIFICATION. Under penalties of perjury, I certify that: (1) the number shown on this form is my correct taxpayer identification number (or I am waiting for a number to be issued to me) AND (2) I am not subject to backup withholding either because (a) I am exempt from backup withholding, or (b) I have not been notified by the Internal Revenue Service (the "IRS") that I am subject to backup withholding as a result of a failure to report all interest or dividends, or (c) the IRS has notified me that I am no longer subject to backup withholding. Signature Date -------------------------------------------
- ------------------------------------------------------------------------------- You must cross out Item (2) of the above certification if you have been notified by the IRS that you are subject to backup withholding because of underreporting of interest or dividends on your tax return and you have not been notified by the IRS that you are no longer subject to backup withholding. - ------------------------------------------------------------------------------- YOU MUST COMPLETE THE FOLLOWING CERTIFICATE IF YOU CHECKED THE BOX IN PART 2 OF SUBSTITUTE FORM W-9 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- CERTIFICATE OF AWAITING TAXPAYER IDENTIFICATION NUMBER I certify under penalties of perjury that a taxpayer identification number has not been issued to me, and either (a) I have mailed or delivered an application to receive a taxpayer identification number to the appropriate Internal Revenue Service Center or Social Security Administration Office or (b) I intend to mail or deliver an application in the near future. I understand that if I do not provide a taxpayer identification number by the time of the exchange, 30% of all reportable payments made to me thereafter will be withheld until I provide a number. Signature Date - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- GUIDELINES FOR CERTIFICATION OF TAXPAYER IDENTIFICATION NUMBER ON SUBSTITUTE FORM W-9 Guidelines for Determining the Proper Identification Number to Provide the Payor. Social Security numbers have nine digits separated by two hyphens: i.e. 000-00-0000. Employer identification numbers have nine digits separated by only one hyphen: i.e. 00-0000000. The table below will help determine the number that you should provide to the payor.
- ------------------------------------------------------- ----------------------------------------------------------- For this type of account: Give the Social Security Number of-- - ------------------------------------------------------- ----------------------------------------------------------- - ------------------------------------------------------- ----------------------------------------------------------- 1. An individual account The individual 2. Two or more individuals (joint account) The actual owner of the account or, if combined funds, the first individual on the account (1) 3. Custodian account of a minor The minor (2) (Uniform Gift to Minors Act) 4. (a) The usual revocable savings trust The grantor-trustee (1) account (grantor is also trustee) (b) So-called trust account that is The actual owner (1) or not a legal valid trust under state law 5. Sole proprietorship The owner (3) - ------------------------------------------------------- ----------------------------------------------------------- - ------------------------------------------------------- ----------------------------------------------------------- - ------------------------------------------------------- ----------------------------------------------------------- - ------------------------------------------------------- ----------------------------------------------------------- For this type of account: Give the Employer Identification Number of-- - ------------------------------------------------------- ----------------------------------------------------------- 6. Sole proprietorship The owner (3) 7. A valid trust, estate or pension trust Legal entity (4) 8. Corporate The corporation 9. Association, club, religious, charitable, The organization educational or other tax-exempt organization 10. Partnership The partnership 11. A broker or registered nominee The broker or nominee 12. Account with the Department of Agriculture The public entity the name in of a public entity (such as a state or local government, school district or prison) that receives agricultural program payments - ------------------------------------------------------- -----------------------------------------------------------
(1) List first and circle the name of the person whose number you furnish. (2) Circle the minor's name and furnish the minor's social security number. (3) Show the name of the individual. You may also enter the business name. (4) List first and circle the name of the legal trust, estate or pension trust. Note: If no name is circled when there is more than one name, the number will be considered to be that of the first name listed. EX-99.2 13 x99_2.txt Exhibit 99.2 NOTICE OF GUARANTEED DELIVERY FOR TENDER OF 4.875% SENIOR NOTES, SERIES C DUE JULY 15, 2015 FOR 4.875% SENIOR NOTES, SERIES D DUE JULY 15, 2015 WHICH HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933 OF SOUTHERN POWER COMPANY This form must be used to accept the Exchange Offer of Southern Power Company (the "Company") made pursuant to the Prospectus dated __________ ___, 200__ (the "Prospectus") if certificates for the 4.875% Senior Notes, Series C due July 15, 2015 (the "Original Senior Notes") of the Company are not immediately available, or if the procedure for book-entry transfer cannot be completed on a timely basis, or if the Original Senior Notes, the Letter of Transmittal or any other documents required thereby cannot be delivered to the Exchange Agent prior to 5:00 p.m., New York City time, on the Expiration Date (as defined in the Prospectus). This form may be delivered by hand or transmitted by facsimile transmission, overnight courier or mail to the Exchange Agent as set forth below. Capitalized terms used but not defined herein have the meaning given to them in the Prospectus. The Exchange Agent for the Exchange Offer is: THE BANK OF NEW YORK 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 Attention: Mr. Bernard Arsenec By facsimile: (212) 298-1915 For information or confirmation by telephone: (212) 815-5098 Delivery of this instrument to an address, or transmission of instructions via a facsimile, other than as set forth above, will not constitute a valid delivery. This form is not to be used to guarantee signatures. If a signature on the Letter of Transmittal to be used to tender Original Senior Notes is required to be guaranteed by an "Eligible Institution" under the instructions thereto, such signature guarantee must appear in the applicable space provided in the Letter of Transmittal. Ladies and Gentlemen: The undersigned hereby tenders to Southern Power Company, a Delaware corporation (the "Company"), upon the terms and subject to the conditions set forth in the Prospectus and the Letter of Transmittal (which together constitute the "Exchange Offer"), receipt of which is hereby acknowledged, the aggregate principal amount of Original Senior Notes set forth below pursuant to the guaranteed delivery procedures described in "THE EXCHANGE OFFER--Procedures for Tendering--Guaranteed Delivery Procedures" section of the Prospectus. All authority herein conferred or agreed to be conferred shall survive the death or incapacity of the undersigned and every obligation of the undersigned hereunder shall be binding upon the heirs, personal representatives, successors and assigns of the undersigned. NOTE: SIGNATURES MUST BE PROVIDED WHERE INDICATED BELOW. Principal Amount of Original Senior Notes Tendered Name(s) of Record Holder(s): (must be in an integral multiple of $1,000): $ Certificate No(s). for Original Senior Notes (if Address: available): If Original Senior Notes will be delivered Area Code and Tel. No.: by book-entry transfer to the Depository Trust Company, provide account number: Signature(s): Account Number: ---------------------------- Dated: This Notice of Guaranteed Delivery must be signed by the registered holder(s) of the Original Senior Notes exactly as its (their) name(s) appear(s) on certificates for Original Senior Notes or on a security position listing as the owner of Original Senior Notes, or by person(s) authorized to become registered holder(s) by endorsements and documents transmitted with this Notice of Guaranteed Delivery. If signature is by a trustee, executor, administrator, guardian, attorney-in-fact, officer, or other person acting in a fiduciary or representative capacity, such person must provide the following information: PLEASE PRINT NAME(S) AND ADDRESS(ES) Name(s): ------------------------------------------------------------- Capacity: ------------------------------------------------------------- Address(es): ------------------------------------------------------------- THE GUARANTEE ON THE FOLLOWING PAGE MUST BE COMPLETED GUARANTEE (NOT TO BE USED FOR SIGNATURE GUARANTEE) The undersigned, a financial institution that is a participant in the Securities Transfer Agents Medallion Program, the New York Stock Exchange Medallion Signature Program or the Stock Exchanges Medallion Program, hereby guarantees that the certificates representing the principal amount of Original Senior Notes tendered hereby in proper form for transfer, or timely confirmation of the book-entry transfer of such Original Senior Notes into the Exchange Agent's account at The Depository Trust Company pursuant to the procedures set forth in "THE EXCHANGE OFFER--Procedures for Tendering--Guaranteed Delivery Procedures" section of the Prospectus, together with one or more properly and duly executed Letters of Transmittal (or facsimile thereof) and any required signature guarantee and any other documents required by the Letter of Transmittal, will be received by the Exchange Agent at the address set forth above, no later than three New York Stock Exchange trading days after the date of execution of this Notice of Guaranteed Delivery. Name of Firm: ---------------------- (Authorized Signature) Address: Name: --------------------------- (Zip Code) (Please Type or Print) Title: Area Code and Telephone No.: Dated: --------------------- Note: Do not send the Original Senior Notes with this form. Original Senior Notes should be sent only with a copy of your Letter of Transmittal. EX-99.3 14 x99_3.txt Exhibit 99.3 SOUTHERN POWER COMPANY OFFER TO EXCHANGE ALL OUTSTANDING 4.875% SENIOR NOTES, SERIES C DUE JULY 15, 2015 FOR 4.875% SENIOR NOTES, SERIES D DUE JULY 15, 2015 WHICH HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933 To Our Clients: Enclosed for your consideration is a Prospectus, dated __________ ___, 200__ (the "Prospectus"), and the related Letter of Transmittal (the "Letter of Transmittal"), concerning the offer (the "Exchange Offer") of Southern Power Company (the "Company") to exchange its 4.875% Senior Notes, Series D due July 15, 2015, which have been registered under the Securities Act of 1933, as amended (the "Exchange Senior Notes"), for its outstanding 4.875% Senior Notes, Series C due July 15, 2015 (the "Original Senior Notes"), upon the terms and subject to the conditions described in the Prospectus and the Letter of Transmittal. The Exchange Offer is being made in order to satisfy certain obligations of the Company contained in the Registration Rights Agreement dated July 8, 2003, by and among the Company and the initial purchasers referred to therein. Original Senior Notes may be tendered in integral multiples of $1,000. This material is being forwarded to you as the beneficial owner of the Original Senior Notes held by us for your account or benefit but not registered in your name. A tender of such Original Senior Notes may only be made by us as the holder of record and pursuant to your instructions. Accordingly, we request instructions as to whether you wish us to tender on your behalf the Original Senior Notes held by us for your account, pursuant to the terms and conditions set forth in the enclosed Prospectus and Letter of Transmittal. We urge you to read carefully the Prospectus and the Letter of Transmittal before instructing us to exchange your Original Senior Notes. Your instructions should be forwarded to us as promptly as possible in order to permit us to tender the Original Senior Notes on your behalf in accordance with the provisions of the Exchange Offer. The Exchange Offer will expire at 5:00 p.m., New York City time, on __________ ___ 200__, unless extended by the Company (the "Expiration Date"). Any Original Senior Notes tendered pursuant to the Exchange Offer may be withdrawn at any time before the Expiration Date. Your attention is directed to the following: 1. The Exchange Offer is for any and all Original Senior Notes. 2. The terms of the Exchange Senior Notes are identical in all material respects to the terms of the Original Senior Notes, except that certain transfer restrictions and registration rights applicable to the Original Senior Notes are not applicable to the Exchange Senior Notes. 3. The Exchange Offer is subject to certain customary conditions set forth in the Prospectus in the section captioned "THE EXCHANGE OFFER--Conditions." 4. Any transfer taxes incident to the transfer of Original Senior Notes from the holder to the Company will be paid by the Company, except as otherwise provided in the instructions in the Letter of Transmittal. If you wish to have us tender your Original Senior Notes, please so instruct us by completing, executing and returning to us the instruction form attached to this letter. The Letter of Transmittal is furnished to you for information only and may not be used directly by you to tender Original Senior Notes. None of the Original Senior Notes held by us for your account or benefit will be tendered unless we receive written instructions from you to do so. The Exchange Offer is not being made to, nor will tenders be accepted from or on behalf of, holders of Original Senior Notes residing in any jurisdiction in which the making of the Exchange Offer or the acceptance thereof would not be in compliance with the laws of such jurisdiction. INSTRUCTIONS WITH RESPECT TO THE EXCHANGE OFFER The undersigned acknowledge(s) receipt of your letter and the enclosed material referred to therein relating to the Exchange Offer made by Southern Power Company with respect to its Original Senior Notes and confirms the representations and warranties that you will be making on behalf of the undersigned contained in the Letter of Transmittal. This will instruct you to tender the Original Senior Notes held by you for the account of the undersigned, upon and subject to the terms and conditions set forth in the Prospectus and the related Letter of Transmittal. The undersigned expressly agrees to be bound by the enclosed Letter of Transmittal and that such Letter of Transmittal may be enforced against the undersigned. Please tender the Original Senior Notes held by you for my account as indicated below: 4.875% Senior Notes, Series C due July 15, 2015: $ (Aggregate Principal Amount of Original Senior Notes) Please do not tender any Original Senior Notes held by you for my account. Dated: , 200__ -------------------- Signature(s): ---------------------------------------------------------------- Print Name(s): --------------------------------------------------------------- Print Address(es): ----------------------------------------------------------- Area Code and Telephone Number(s): ------------------------------------------- Tax Identification or Social Security Number(s): ----------------------------- None of the Original Senior Notes held by us for your account will be tendered unless we receive written instructions from you to do so. Unless a specific contrary instruction is given in the space provided, your signature(s) hereon shall constitute an instruction to us to tender all the Original Senior Notes held by us for your account. EX-99.4 15 x99_4.txt Exhibit 99.4 SOUTHERN POWER COMPANY OFFER TO EXCHANGE ALL OUTSTANDING 4.875% SENIOR NOTES, SERIES C DUE JULY 15, 2015 FOR 4.875% SENIOR NOTES, SERIES D DUE JULY 15, 2015 WHICH HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933 To: Brokers, Dealers, Commercial Banks, Trust Companies and Other Nominees: Southern Power Company (the "Company") is offering, upon and subject to the terms and conditions set forth in the Prospectus, dated __________ ___, 200__ (the "Prospectus"), and the enclosed Letter of Transmittal (the "Letter of Transmittal"), to exchange (the "Exchange Offer") its 4.875% Senior Notes, Series D due July 15, 2015, which have been registered under the Securities Act of 1933, as amended, for its outstanding 4.875% Senior Notes, Series C due July 15, 2015 (the "Original Senior Notes"). The Exchange Offer is being made in order to satisfy certain obligations of the Company contained in the Registration Rights Agreement dated July 8, 2003, by and among the Company and the initial purchasers referred to therein. We are requesting that you contact your clients for whom you hold Original Senior Notes regarding the Exchange Offer. For your information and for forwarding to your clients for whom you hold Original Senior Notes registered in your name or in the name of your nominee, or who hold Original Senior Notes registered in their own names, we are enclosing the following documents: 1. Prospectus dated __________ ___, 200__; 2. The Letter of Transmittal for your use and for the information of your clients; 3. A Notice of Guaranteed Delivery to be used to accept the Exchange Offer if certificates for Original Senior Notes are not immediately available or time will not permit all required documents to reach the Exchange Agent prior to the Expiration Date (as defined below) or if the procedure for book-entry transfer cannot be completed on a timely basis; 4. A form of letter which may be sent to your clients for whose account you hold Original Senior Notes registered in your name or the name of your nominee, with space provided for obtaining such clients' instructions with regard to the Exchange Offer; and 5. Return envelopes addressed to The Bank of New York, the Exchange Agent for the Exchange Offer. Your prompt action is requested. The Exchange Offer will expire at 5:00 p.m., New York City time, on __________ ___, 200__, unless extended by the Company (the "Expiration Date"). Original Senior Notes tendered pursuant to the Exchange Offer may be withdrawn at any time before the Expiration Date. To participate in the Exchange Offer, a duly executed and properly completed Letter of Transmittal (or facsimile thereof), with any required signature guarantees and any other required documents, should be sent to the Exchange Agent and certificates representing the Original Senior Notes should be delivered to the Exchange Agent, all in accordance with the instructions set forth in the Letter of Transmittal and the Prospectus. If a registered holder of Original Senior Notes desires to tender, but such Original Senior Notes are not immediately available, or time will not permit such holder's Original Senior Notes or other required documents to reach the Exchange Agent before the Expiration Date, or the procedure for book-entry transfer cannot be completed on a timely basis, a tender may be effected by following the guaranteed delivery procedures described in the Prospectus under the caption "THE EXCHANGE OFFER--Procedures for Tendering--Guaranteed Delivery Procedures." In all cases, exchanges of the Original Senior Notes accepted for exchange pursuant to the Exchange Offer will be made only after timely receipt by the Exchange Agent of (a) certificates representing such Original Senior Notes, or confirmation of book-entry transfer of such Original Senior Notes, as the case may be, (b) the Letter of Transmittal (or facsimile thereof), properly completed and duly executed, or an Agent's Message and (c) any other required documents. The Company will not pay any fees or commissions to brokers, dealers or other persons for soliciting exchanges of Notes pursuant to the Exchange Offer. The Company will, upon request, reimburse brokers, dealers, commercial banks and trust companies for reasonable and necessary costs and expenses incurred by them in forwarding the Prospectus and the related documents to the beneficial owners of Original Senior Notes held by them as nominee or in a fiduciary capacity. The Company will pay or cause to be paid all stock transfer taxes applicable to the exchange of Original Senior Notes pursuant to the Exchange Offer, except as set forth in Instruction 6 of the Letter of Transmittal. Any inquiries you may have with respect to the Exchange Offer, or requests for additional copies of the enclosed materials, should be directed to The Bank of New York, the Exchange Agent for the Exchange Offer, at its address and telephone number set forth on the front of the Letter of Transmittal. Very truly yours, SOUTHERN POWER COMPANY Nothing herein or in the enclosed documents shall constitute you or any person as an agent of the Company or the Exchange Agent, or authorize you or any other person to use any document or make any statements on behalf of either of them with respect to the Exchange Offer, except for the documents enclosed herewith and the statements expressly made in the Prospectus or the Letter of Transmittal. 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