UNITED STATESSECURITIES AND EXCHANGE COMMISSION
FORM 10-Q
OR
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No ___
Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Securities Exchange Act of 1934).
This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, Savannah Electric and Power Company and Southern Power Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies.
2
INDEX TO QUARTERLY REPORT ON FORM 10-QJune 30, 2004
3
4
DEFINITIONS
5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning the strategic goals for Southern Company’s wholesale business, estimated construction and other expenditures. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or “continue” or the negative of these terms or other comparable terminology. The registrants caution that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
6
THE SOUTHERN COMPANYAND SUBSIDIARY COMPANIES
7
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIESCONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
The accompanying notes as they relate to Southern Company are an integral partof these condensed financial statements.
8
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIESCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
9
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIESCONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
10
11
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIESCONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
12
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIESMANAGEMENT’S DISCUSSION AND ANALYSIS OFRESULTS OF OPERATIONS AND FINANCIAL CONDITION SECOND QUARTER 2004 vs. SECOND QUARTER 2003ANDYEAR-TO-DATE 2004 vs. YEAR-TO-DATE 2003
OVERVIEW
Discussion of the results of operations is focused on Southern Company’s primary business of electricity sales in the Southeast by the retail operating companies – Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Savannah Electric – and Southern Power. Southern Power is an electric wholesale generation subsidiary with market-based rate authority. Southern Company’s other business activities include investments in synthetic fuels and leveraged lease projects, telecommunications, energy-related services and natural gas marketing. For additional information on these businesses, see BUSINESS — The SOUTHERN System — “Retail Operating Companies,” “Southern Power” and “Other Business” in Item 1 of the Form 10-K.
RESULTS OF OPERATIONS
Earnings
Southern Company’s second quarter and year-to-date 2004 earnings were $352 million ($0.48 per share) and $683 million ($0.93 per share), respectively, compared with $432 million ($0.60 per share) and $730 million ($1.01 per share) in the second quarter and year-to-date 2003. The decreases in second quarter and year-to-date 2004 results are attributed to a one-time after-tax gain of $88 million included in the second quarter 2003 from termination of capacity sales contracts with Dynegy. See Note 3 to the financial statements of Southern Company under “Uncontracted Generating Capacity” in Item 8 of the Form 10-K for additional information on these contract terminations. Earnings in the second quarter and year-to-date 2004 when compared to the same periods in 2003, excluding the Dynegy contract termination, increased due to a number of positive factors including growth in customers, increased consumption of electricity by existing customers in the Southern Company service area, and generally more favorable weather conditions, as well as new generating capacity available for sale in wholesale markets. This new capacity led to increases in wholesale revenues from new contracts and sales of uncontracted capacity in those wholesale markets. These positive factors were partially offset by higher operations and maintenance cost in the second quarter as some maintenance projects not completed in 2003 and earlier this year were undertaken in the second quarter of 2004.
Significant income statement items appropriate for discussion include the following:
13
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIESMANAGEMENT’S DISCUSSION AND ANALYSIS OFRESULTS OF OPERATIONS AND FINANCIAL CONDITION
Retail sales. Excluding fuel revenues, which generally do not affect net income, retail base revenues increased by $109 million, or 7.1%, in the second quarter 2004, and increased by $181 million, or 6.2%, year-to-date 2004 when compared to the same periods in 2003. In the second quarter and year-to-date 2004, retail kilowatt-hour energy sales increased by 5.3% and 4.9%, respectively, over the same periods a year ago, primarily due to customer and demand growth and the still improving economy evidenced by increases in residential, commercial and industrial second quarter kilowatt-hour energy sales of 8.5%, 5.1% and 3.0%, respectively. Year-to-date residential, commercial and industrial kilowatt-hour energy sales increased by 6.9%, 4.3% and 3.9%, respectively, when compared to the same period in 2003. In the second quarter and year-to-date 2004, temperatures were slightly above normal, while mild weather in the same periods last year resulted in reduced demand by retail customers. The number of retail customers increased by 1.8%, and average consumption by residential customers increased by 5.2% for the year-to-date 2004 when compared to year-to-date 2003.
Sales for resale. Sales for resale revenues increased $20.8 million, or 6.4% and $37.0 million, or 5.6% for the second quarter and year-to-date 2004, respectively, when compared to the same periods in the prior year. The increase in revenues reflected new wholesale contracts and increases in fuel revenues. An additional 2,407 megawatts of generating capacity were added in June and October 2003 by Southern Power. A portion of this new capacity contributed to the increase in sales for resale revenues for the second quarter and year-to-date 2004 as a result of increased energy revenues from PPAs with neighboring utilities. These increases in sales for resale revenues more than offset the reduction in revenues resulting from the termination of contracts with subsidiaries of Dynegy in May 2003. See Note 3 to the financial statements of Southern Company under “Uncontracted Generating Capacity” in Item 8 of the Form 10-K for additional information on these contract terminations.
Other electric revenues. In the second quarter and year-to-date 2004, other electric revenues decreased $133.9 million, or 58.7% and $132.3 million or 41.4%, respectively, because of the $142 million in contract termination revenues from Dynegy recorded in May 2003. See “Earnings” discussion above for additional information on these contract terminations. Excluding these contract termination revenues, other electric revenues increased $8.3 million or 9.6% and $9.8 million or 5.5% for the second quarter and year-to-date 2004, respectively, when compared to the same periods in 2003 primarily as a result of increased cogeneration sales and transmission revenue.
Fuel expense. During the second quarter and year-to-date periods of 2004, fuel expense was higher due to an increase in the average unit cost of fuel, as well as increased generating capacity at Southern Power. Total fuel generation remained flat for the second quarter and increased 2.3% for the year-to-date 2004, when compared to the same periods in the prior year. For the second quarter and year-to-date periods in 2004, the average unit cost of fuel per kilowatt-hour generated increased 13.2% and 12.9%, respectively, when compared to the same periods in the prior year. Increases in fuel expense at the retail operating companies are generally offset by fuel revenues and do not affect net income. See “Future Earnings Potential – FERC and State PSC Matters – Retail Fuel Cost Recovery” herein for additional information. Southern Power’s PPAs generally provide that the purchasers are responsible for substantially all of the costs of fuel.
Purchased power. The increases in purchased power for the second quarter and year-to-date 2004 when compared with the same periods last year were primarily due to increased demand for energy by retail customers and to purchase energy used to meet off-system sales commitments. Also, at times additional power was available for purchase from external parties at prices lower than Southern Company’s own system generation costs. These expenses do not have a significant impact on earnings since energy expenses are generally offset by energy revenues.
14
Other operations and maintenance expenses. The increases in other operations and maintenance expenses in the second quarter and year-to-date 2004 are mainly attributable to increases in administrative and general, transmission and distribution maintenance and other production expenses. Administrative and general expenses increased $14.7 million, or 6.5% and $40.5 million, or 9.5%, for the second quarter and year-to-date 2004, respectively, primarily as a result of payroll and employee benefits costs. Transmission and distribution expenses increased $18.6 million or 13.7% and $30.3 million or 11.9% for the second quarter and year-to-date 2004, respectively, as a result of completing work delayed from 2003. Other production expenses were up $7.1 million or 2.2% and $14.5 million, or 2.3% for the second quarter and year-to-date 2004, respectively, due to increased expenses primarily resulting from the operation of Southern Power’s new generating facilities.
Depreciation and amortization. The second quarter and year-to-date 2004 decreases of $24.8 million and $29.2 million, respectively, in depreciation and amortization expense when compared to the same periods in 2003 are primarily the result of increased amortization of regulatory liabilities at Georgia Power and Mississippi Power. The decreases in Georgia Power’s depreciation and amortization expenses ($17 million and $35 million for the second quarter and year-to-date 2004, respectively) were caused primarily by lower regulatory charges needed to levelize purchased power capacity costs under the terms of the retail rate order effective January 1, 2002. See Note 1 to the financial statements of Southern Company under “Depreciation and Amortization” in Item 8 of the Form 10-K for additional information. The decreases in Mississippi Power’s second quarter and year-to-date 2004 depreciation and amortization expenses ($8 million and $7 million for the second quarter and year-to-date 2004, respectively) are primarily the result of the amortization of a regulatory liability as approved by the Mississippi PSC. The Mississippi PSC issued an interim accounting order in December 2003 directing Mississippi Power to expense and record in 2003 a regulatory liability in the amount of approximately $60 million. Based on the final Mississippi PSC order issued May 25, 2004 that approved this treatment, Mississippi Power recorded a credit to amortization of the regulatory liability of $8.3 million during the second quarter of 2004. The year-to-date decreases are partially offset by increases in depreciable plant in service, primarily as a result of Southern Power’s Stanton Unit A, which was placed in service in October 2003. Reference is made to Note 3 to the financial statements of Southern Company under “Mississippi Power Regulatory Filing” in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements and “FERC and State PSC Matters” herein for additional information.
Taxes other than income taxes. The second quarter and year-to-date 2004 increases in taxes other than income taxes over the comparable periods last year are primarily a result of increases in payroll taxes, property taxes on new facilities and higher tax assessments on property. Also, franchise and gross receipts taxes increased for the respective periods due to the increase in revenues from energy sales.
Interest income. The second quarter and year-to-date 2004 decreases in interest income when compared to the same periods in the prior year resulted from $15.6 million of interest received from a federal income tax settlement in the second quarter of 2003.
Other income (expense), net. The second quarter and year-to-date 2004 decreases in other income (expense), net reflect decreased rental income at Georgia Power of $4.0 million and $2.5 million, respectively, as well as the impact of the ESOP contribution in June 2004 of $6.2 million when compared to the same periods in 2003. The year-to-date 2004 decrease in other income (expense), net also reflects a $5.0 million decrease related to the 2003 favorable resolution of a loss contingency by Georgia Power.
15
Future Earnings Potential
The results of operations discussed above are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors. These factors include the retail operating companies’ ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs and to recover costs related to growing demand and increasingly stricter environmental standards. Another major factor is the profitability of the competitive market-based wholesale generating business and federal regulatory policy, which may impact Southern Company’s level of participation in this market. Future earnings for the electricity business in the near term will depend, in part, upon growth in energy sales, which is subject to a number of factors, including weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand and the rate of economic growth in the service area. For additional information relating to these issues, see BUSINESS — The SOUTHERN System — “Risk Factors” in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential” of Southern Company in Item 7 of the Form 10-K.
Environmental Matters
New Source Review Actions and Plant Wansley Environmental Litigation
Compliance costs related to the Clean Air Act and other environmental regulations could affect earnings if such costs cannot be recovered. For additional information, including information on certain environmental litigation, see MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential — Environmental Matters” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “New Source Review Actions” and “Plant Wansley Environmental Litigation” in Item 8 of the Form 10-K. As of March 15, 2004, civil penalties under the Clean Air Act were increased prospectively to a maximum of $32,500 per day, per violation. To the extent alleged violations under either the New Source Review litigation or Plant Wansley environmental litigation are deemed to be continuing, this increased civil penalty amount could apply to such violations found to continue after that date.
On May 3, 2004, the U.S. Supreme Court denied the EPA’s petition to review the Eleventh Circuit Court of Appeals’ decision in the EPA’s similar New Source Review enforcement action against the TVA. The cases against Alabama Power, Georgia Power and Savannah Electric have been effectively stayed pending final resolution of the TVA case. With the denial of the EPA’s petition for review, the Court of Appeals’ decision became final. Alabama Power and the EPA jointly notified the District Court for the Northern District of Alabama, where the case against Alabama Power is pending and requested that the stay be lifted. On June 16, 2004, the District Court lifted the stay, placing the case back onto the District Court’s active docket. At this time, no party to the case against Georgia Power and Savannah Electric has sought to reopen that case, which remains administratively closed in the District Court for the Northern District of Georgia. On June 10, 2004, the U.S. District Court for the Northern District of Georgia granted Georgia Power’s motion in the Plant Wansley environmental litigation for partial summary judgment regarding emissions offsets. The case has been removed from the court’s trial calendar due to pending motions for summary judgment, and a new trial date has not been scheduled. An adverse outcome in any one of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
16
Global Warming Litigation
On July 21, 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Plaintiffs seek relief under the federal common law or, in the alternative, under state law, of public nuisance. The environmental groups also seek relief under common law private nuisance theories. The plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining an ongoing public nuisance, global warming and (2) permanently enjoining each of the defendants to abate its contribution to the nuisance by capping its emissions of carbon dioxide and then reducing those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. Southern Company has not yet responded to the suits; however, it intends to vigorously defend against these claims. While the outcome cannot be determined at this time, an adverse judgment could result in substantial capital expenditures.
Other Environmental Matters
On March 12, 2004, the EPA redesignated the Birmingham, Alabama area from nonattainment to attainment under the one-hour ozone national ambient air quality standard. On April 30, 2004, the EPA published its eight-hour ozone nonattainment designations and a portion of the rules implementing the new eight-hour standard. Areas within the Southern Company’s service area that have been designated as nonattainment under the eight-hour ozone standard include Birmingham, Macon (Georgia), and a 20-county area within metropolitan Atlanta. Under the implementation provisions of the new rule, the EPA announced that the one-hour ozone standard will be revoked on June 15, 2005. Areas classified as “severe” nonattainment areas under the one-hour standard will not be required to impose emissions fees as a result of nonattainment. Georgia Power, therefore, will no longer be subject to imposition of emissions fees if the Atlanta area does not come into attainment with the one-hour standard. The impact of the eight-hour designations and the new standards will depend on the development and implementation of applicable state regulations and therefore cannot be determined at this time.
In June 2004, the EPA issued its recommendations for areas to be designated “nonattainment” for the fine particle national ambient air quality standard. Areas within Southern Company’s service area that were included in the EPA’s proposed fine particulate matter designations include 24 counties in the metro-Atlanta area; counties surrounding Macon, Athens, and Columbus, Georgia; counties surrounding Birmingham, Alabama; and counties in Alabama and Georgia near Chattanooga, Tennessee. Alabama Power, Georgia Power and Southern Power own several plants located within the counties proposed for the nonattainment designations. The EPA plans to make final nonattainment designations for fine particulate matter by the end of 2004.
On April 21, 2004, the EPA published the final regional nitrogen oxide reduction rules applicable to Georgia. These rules specify that the State of Georgia must submit a revised state implementation plan by April 2005, and affected sources must comply with the reduction requirements by May 1, 2007. The impact of these regulations will depend on the development and approval of Georgia’s state implementation plan and cannot be determined at this time.
17
Additionally, on May 5, 2004, the EPA published proposed amendments to its Regional Haze rules with respect to Best Available Retrofit Technology guidelines and requirements. The impact of these regulations will depend on the development and implementation of the final rules and implementation by the states, and therefore cannot be determined at this time.
FERC and State PSC Matters
Market-Based Rate Authority
See MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential — FERC Matters — Market-Based Rate Authority” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “FERC Matters” in Item 8 of the Form 10-K. On April 14, 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach includes a pivotal supplier analysis and a wholesale market share analysis, the results of which provide a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power. Southern Company, the retail operating companies and Southern Power believe that it may be difficult for a traditional utility company, or an affiliate thereof, with a significant load service obligation and generation to satisfy that obligation, and that is not a member of a large, FERC-approved RTO, to pass all aspects of the market power screens as currently designed. However, each of the companies believes that it has an appropriate basis to rebut the generation market power presumption.
On July 8, 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April. Southern Company will submit the required analyses by August 9, 2004. In the event that the FERC’s default mitigation measures are ultimately applied, Southern Power and the retail operating companies may be required to charge cost-based rates, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time.
Transmission
See MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential — FERC Matters — Transmission” of Southern Company in Item 7 of the Form 10-K for information on the FERC’s order related to RTOs and the FERC’s notice of proposed rulemaking regarding open access transmission service and standard electricity market design.
Plant McIntosh Construction Project
See Note 3 to the financial statements of Southern Company under “FERC Matters” in Item 8 of the Form 10-K for information regarding PPAs between Southern Power and Georgia Power and Savannah Electric for Plant McIntosh capacity. In April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund and ordered that hearings be held. To ensure the timely completion of construction on McIntosh units 10 and 11 and their availability in the summer of 2005 as supply side resources for the retail customers in the State of Georgia, on May 7, 2004, Savannah Electric and Georgia Power requested the Georgia PSC to direct them to acquire the McIntosh construction project. Savannah Electric and Georgia Power proposed to place the units in rate base at a cost
18
approved by the Georgia PSC and to recover the unit operation and maintenance costs as retail service expenses as may be approved by the Georgia PSC. The Georgia PSC issued such an order on May 18, 2004 and the transfer occurred on May 24, 2004. On May 20, 2004, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. On August 4, 2004, the FERC issued a notice that it allowed the request to withdraw the PPAs to be accepted and to become effective by operation of law on July 20, 2004. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. The ultimate outcome of this matter cannot now be determined.
The May 18, 2004 Georgia PSC order also directed Georgia Power and Savannah Electric to file an application within 10 days of completing such purchase to amend the resource certificate granted by the Georgia PSC in 2002 to describe the capacity resource as being the McIntosh units 10 and 11 (as opposed to the McIntosh PPAs), the approximate construction schedule (which is not expected to change) and the proposed rate base treatment. The application was filed on June 3, 2004 and the Georgia PSC will have 180 days to respond. The Georgia PSC is expected to review the application in accordance with its affiliate transaction guidelines, which require a lower of cost or market approach unless otherwise determined by the Georgia PSC. Georgia Power and Savannah Electric have submitted information showing that the book cost of the McIntosh construction project is lower than its market value. However, full recovery of the project costs depends on the outcome of the Georgia PSC’s review. In the event the Georgia PSC does not allow full recovery of the project costs, then part of such costs may have to be written off in accordance with FASB Statement No. 90, “Accounting for Abandonments and Disallowed Plant Costs.” At June 30, 2004, the investment in the McIntosh construction project totaled approximately $355.2 million and $69.7 million for Georgia Power and Savannah Electric, respectively. The ultimate outcome of the Georgia PSC’s review cannot now be determined.
Georgia Power Retail Rate Case
On July 1, 2004, Georgia Power filed a request with the Georgia PSC for an approximate 7 percent increase in retail revenues, effective January 1, 2005. The requested increase is based on a future test year ending July 31, 2005 and a proposed retail return on common equity of 12.5 percent. Georgia Power is currently operating under a three-year retail rate order that expires December 31, 2004. Under the terms of the existing order, earnings are evaluated annually against a retail return on common equity range of 10 percent to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return are applied to rate refunds, with the remaining one-third retained by Georgia Power. The order required Georgia Power to file a general rate case on July 1, 2004.
The increase in retail revenues is being requested to cover the higher costs of purchased power; operating and maintenance expenses; environmental compliance; and continued investment in new generation, transmission and distribution facilities to support growth and ensure reliability. Georgia Power expects the Georgia PSC to issue a final order in this matter during December 2004. The final outcome of this matter cannot now be determined. See MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential — Other Matters” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Georgia Power Retail Rate Orders” in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements herein for additional information.
Alabama Power Environmental Rate Filing
On August 2, 2004, Alabama Power made a filing with the Alabama PSC to establish a specific rate mechanism for the recovery of retail costs associated with environmental laws, regulations or other such mandates. If approved, the rate mechanism would begin operation in January 2005 and provide for the recovery of these costs pursuant to a factor that will be calculated annually. It is anticipated that for the first two years of the increase, retail rates would increase under the proposed mechanism by approximately 1% ($33 million) in 2005 and approximately an additional 1% ($30 million) in 2006. Such environmental cost recovery would include operations and maintenance expense, depreciation and a return on invested capital. The outcome of this matter cannot now be determined.
19
Mississippi Power Retail Rate Filing
On December 5, 2003, Mississippi Power filed a request with the Mississippi PSC to include 266 megawatts of Plant Daniel Units 3 and 4 generating capacity not included in jurisdictional cost of service. As part of Mississippi Power’s proposal to include the additional Plant Daniel capacity in retail rates, the Mississippi PSC, at the time of such filing, issued an interim accounting order in December 2003 directing Mississippi Power to expense and record in 2003 a regulatory liability in the amount of approximately $60 million while the Mississippi PSC fully considered the entire request. On May 25, 2004, the Mississippi PSC issued an order related to this matter. The Mississippi PSC approved Mississippi Power’s request to reclassify the 266 megawatts of Plant Daniel Unit 3 and 4 capacity to jurisdictional cost of service effective January 1, 2004 and authorized Mississippi Power to include the related costs and revenue credits in jurisdictional rate base, cost of service and revenue requirement calculations for purposes of retail rate recovery. Mississippi Power will amortize the regulatory liability established pursuant to the Mississippi PSC’s interim order in December 2003 as an increase to earnings as follows: $16.5 million in 2004, $25.1 million in 2005, $13.0 million in 2006 and $5.7 million in 2007.
In addition, the Mississippi PSC also approved Mississippi Power’s requested changes to PEP, including the use of a forward-looking test year, with appropriate oversight; annual, rather than semi-annual, filings; and certain changes to the performance indicator mechanisms. Rate changes will be limited to 4% of retail revenues annually under the revised PEP. The Mississippi PSC will review all aspects of PEP in 2007. See Note 3 to the financial statements of Southern Company under “Mississippi Power Regulatory Filing” in Item 8 of the Form 10-K for additional information.
Retail Fuel Cost Recovery
The retail operating companies each have established fuel cost recovery rates approved by their respective state PSCs. In recent months, the companies have experienced higher than expected fuel costs for coal and gas. Those higher fuel costs have increased the under recovered fuel costs included in the Condensed Balance Sheets herein. The companies will continue to monitor the under recovered fuel cost balance in light of these higher fuel costs.
Mirant Related Matters
See Note 3 to the financial statements of Southern Company under “Mirant Related Matters” in Item 8 and MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential — Other Matters” of Southern Company in Item 7 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under “Mirant Related Matters”. In July 2003, Mirant filed for voluntary reorganization under Chapter 11 of the Federal Bankruptcy Code. Southern Company has various contingent liabilities associated with Mirant, including guarantees of contractual commitments, litigation and joint and several liabilities in connection with the consolidated federal income tax return. The ultimate outcome of such contingent liabilities cannot now be determined.
Income Tax Matters
See MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential — Income Tax Matters” of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under “Income Tax Issues” in Item 8 of the Form 10-K for information regarding IRS and other challenges to Southern Company’s transactions related to synthetic fuel tax credits and international
20
leveraged leases. See Note (B) to the Condensed Financial Statements herein under “Income Tax Matters” for information on potential additional challenges related to the international leveraged leases that could have material impacts on Southern Company’s financial statements. The ultimate outcome of these matters cannot now be determined.
Other Matters
Southern Power is completing limited construction activities on Plant Franklin Unit 3 to preserve the long-term viability of the project but has deferred final completion until the 2008-2011 period. See Note 3 to the financial statements of Southern Company under “Uncontracted Generating Capacity” in Item 8 of the Form 10-K for additional information. The final outcome of these matters cannot now be determined.
See MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential — Other Matters” of Southern Company in Item 7 of the Form 10-K for information on nuclear security measures. Implementation plans for the measures ordered by the NRC to be in effect by October 29, 2004 have been finalized based on current interpretations of the requirements. Alabama Power and Georgia Power — based on its ownership interest — currently estimate their respective expenditures related to these security measures to total $9.6 million and $9.3 million, of which $9.3 million and $1.3 million will be capitalized. These estimates are subject to change in the event additional NRC guidance is provided.
Southern Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Southern Company’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Company’s financial statements.
See the Notes to the Condensed Financial Statements herein for discussion of various contingencies and other matters which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS — ACCOUNTING POLICIES — “Application of Critical Accounting Policies and Estimates” of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, and Plant Daniel Capacity. Also see Note (K) to the Condensed Financial Statements herein for additional information related to Mississippi Power’s request to include the Plant Daniel capacity in jurisdictional cost of service and the related Mississippi PSC order.
21
New Accounting Standards
On March 31, 2004, Southern Company prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of FASB Interpretation No. 46R had no impact on Southern Company’s net income. However, as a result of the adoption, Southern Company and the retail operating companies deconsolidated certain wholly-owned trusts established to issue preferred securities since Southern Company and the retail operating companies do not meet the definition of primary beneficiary established by FASB Interpretation No. 46R. In addition, Southern Company consolidated its 85% limited partnership investment in an energy/telecom venture capital fund that was previously accounted for under the equity method. See Note (D) to the Condensed Financial Statements herein for additional information related to the adoption of FASB Interpretation No. 46R.
In May 2004, the FASB approved Staff Position (FSP) No. 106-2, “Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “Medicare Act”).” FSP No. 106-2 requires recognition of the impacts of the Medicare Act in the accumulated post-retirement benefit obligation and future cost of service for post-retirement medical plans and may be applied retroactively to the enactment of the Medicare Act in December 2003 or prospectively effective for the third quarter 2004. Southern Company has elected to apply this treatment prospectively. Pending the finalization of federal regulations governing the subsidy effected in the Medicare Act, Southern Company does not anticipate a material impact on its financial statements from the adoption of FSP No. 106-2.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Major changes in Southern Company’s financial condition during the first six months of 2004 included $1.0 billion used for gross property additions to utility plant. The funds for these additions and other capital requirements were primarily obtained from net proceeds from short- and long-term security issuances of approximately $685 million and operating activities. See Southern Company’s Condensed Consolidated Statements of Cash Flows and “Financing Activities” herein for further details.
Capital Requirements and Contractual Obligations
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Southern Company in Item 7 of the Form 10-K for a description of Southern Company’s capital requirements for its construction program and other funding requirements associated with scheduled maturities of long-term debt, as well as the related interest, preferred stock dividends, leases, trust funding requirements and other purchase commitments. Approximately $924 million will be required by June 30, 2005 for redemptions and maturities of long-term debt.
Sources of Capital
Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. The amounts and timing of additional equity capital to be raised will be contingent on Southern Company’s investment opportunities. The retail operating companies and Southern Power plan to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, security issuances and term loan and short-term borrowings. However, the amount, type and timing of any financings, if needed, will depend upon market conditions and regulatory approval. See BUSINESS — “Financing Programs” in Item 1 and MANAGEMENT’S DISCUSSION AND
22
ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Sources of Capital” of Southern Company in Item 7 of the Form 10-K for additional information.
Southern Company’s current liabilities exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs, as well as scheduled maturities of long-term debt. To meet short term cash needs and contingencies, the Southern Company system had at June 30, 2004 approximately $191 million of cash and cash equivalents and approximately $3.5 billion of unused credit arrangements with banks, of which $251 million expire in 2004, $1.5 billion expire in 2005 and $1.7 billion expire in 2006 and beyond. Of the facilities maturing in 2004 and 2005, $1.22 billion contain provisions allowing two-year term loans executable at the expiration date and $215 million contain provisions allowing one-year term loans executable at the expiration date. These unused credit arrangements also provide liquidity support to variable rate pollution control bonds and commercial paper programs. Southern Company expects to renew its credit facilities, as needed, prior to expiration. The retail operating companies may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of each of the retail operating companies. At June 30, 2004, the Southern Company system had outstanding commercial paper of $727 million and extendible commercial notes of $10.9 million.
Management believes that the need for working capital can be adequately met by utilizing commercial paper programs and lines of credit without maintaining large cash balances.
Off-Balance Sheet Financing Arrangements
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Off-Balance Sheet Financing Arrangements” of Southern Company in Item 7 and Note 7 to the financial statements of Southern Company under “Operating Leases” in Item 8 of the Form 10-K for information related to Mississippi Power’s lease of a combined cycle generating facility at Plant Daniel.
Credit Rating Risk
Southern Company and its subsidiaries do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral — but not accelerated payment — in the event of a credit rating change to below investment grade. These contracts are primarily for physical electricity purchases and sales, fixed-price physical gas purchases and agreements covering interest rate swaps. At June 30, 2004, the maximum potential collateral requirements were approximately $429.8 million. Generally, collateral may be provided for by a Southern Company guaranty, letter of credit or cash.
Market Price Risk
Southern Company’s market risk exposures relative to interest rate changes have not changed materially compared with the December 31, 2003 reporting period. In addition, Southern Company is not aware of any facts or circumstances that would significantly affect such exposures in the near term.
Due to cost-based rate regulations, the retail operating companies have limited exposure to market volatility in interest rates, commodity fuel prices and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the retail operating companies and Southern Power enter into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, similar contracts for gas purchases. Also, the retail operating companies have each implemented fuel-hedging
23
programs at the instruction of their respective PSCs. The fair value of derivative energy contracts at June 30, 2004 was as follows:
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Southern Company in Item 7 and Notes 1 and 6 to the financial statements of Southern Company under “Financial Instruments” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein.
Financing Activities
In the first six months of 2004, Southern Company subsidiaries issued $775 million of senior notes, $265 million of other long-term debt, $175 million of preferred stock and $62 million of common stock through employee and director stock plans. The issuances were primarily used to refund senior notes and other long-term debt and to fund ongoing construction projects. The remainder was used to repay short-term debt. See Southern Company’s Condensed Consolidated Statements of Cash Flows herein for further details on financing activities during the first six months of 2004.
In January 2004, Georgia Power issued $100 million of Series S 4.00% Senior Notes due January 15, 2011 and $100 million of Series T 5.75% Senior Public Income Notes due January 15, 2044. The proceeds from these sales were used in March 2004 to redeem all of its outstanding Series H 6.70% Senior Insured Quarterly Notes due March 1, 2011 and Series D 6 5/8% Senior Notes due March 31, 2039.
Further in January 2004, Georgia Power Capital Trust VII, a statutory trust, sold $200 million of its 5 7/8% Trust Preferred Securities, which are guaranteed by Georgia Power. The net proceeds from this issuance were used to redeem 6.85% Trust Preferred Securities of Georgia Power Capital Trust IV. In connection with this transaction, Georgia Power issued $206 million of its junior subordinated debentures to Georgia Power Capital Trust VII.
24
In February 2004, Alabama Power issued 4,000,000 shares ($100 million aggregate stated capital) of 5.30% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share) and $200 million of Series Z 5.125% Senior Notes due February 15, 2019. The proceeds from these sales were used to repay a portion of Alabama Power’s outstanding short-term indebtedness and for other general corporate purposes, including Alabama Power’s continuous construction program.
Also in February 2004, Georgia Power issued $150 million of Series U Floating Rate Senior Notes due February 17, 2009. The proceeds of this sale were used for general corporate purposes.
In March 2004, Mississippi Power issued $40 million of Series F Floating Rate Senior Notes due March 9, 2009. The proceeds from this sale, along with other monies of Mississippi Power were used to repay $80 million aggregate principal amount of Mississippi Power’s Series D Floating Rate Senior Notes due March 12, 2004.
Additionally, in April 2004, Alabama Power issued $150 million of Series AA 5 5/8% Senior Notes due April 15, 2034 and terminated $150 million of swaps at a gain of $6 million. The proceeds from the sale were used together with other funds to redeem, in May 2004, $200 million in aggregate principal amount of the Series J 6.75% Senior Notes due June 30, 2039. The gain from the terminated swaps was deferred in Other Comprehensive Income and will be amortized to income over the life of the Series AA Senior Notes.
Also in April 2004, Gulf Power issued $35 million of Series J 5.875% Senior Notes due April 1, 2044. The proceeds from this issue were used for general corporate purposes, including Gulf Power’s continuous construction program.
Also, in April 2004, Mississippi Power issued 1,200,000 Depositary Shares ($30 million aggregate stated capital) each representing one-fourth of a share of 5.25% Series Preferred Stock, cumulative, par value $100 per share. The proceeds from this sale were primarily used to redeem various issues of preferred stock and the remainder was used for general corporate purposes.
Further, in June, 2004, Savannah Electric issued 1,800,000 shares ($45 million aggregate par value) of 6.00% Series Preferred Stock, non-cumulative, par value $25 per share. The proceeds from this sale were used to repay a portion of its outstanding short-term indebtedness that had been incurred primarily to finance the purchase of its share of Units 10 and 11 of Plant McIntosh.
Subsequent to June 30, 2004, Alabama Power has entered into interest rate hedging transactions related to the anticipated issuance of senior notes totaling approximately $125 million. The notes are expected to be issued in 2005.
Southern Company and its subsidiaries plan to continue, to the extent possible, a program to retire higher-cost debt and replace these securities with lower-cost capital.
The market price of Southern Company’s common stock at June 30, 2004 was $29.15 per share and the book value was $13.43 per share, representing a market-to-book ratio of 217%, compared to $30.25, $13.13 and 230%, respectively, at the end of 2003. The dividend for the second quarter 2004 was $0.35 per share compared to $0.3425 per share in the second quarter 2003.
25
PART I
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” herein for each registrant and Notes 1 and 6 to the financial statements of each registrant under “Financial Instruments” in Item 8 of the Form 10-K. Also, see Note (F) to the Condensed Financial Statements herein for information relating to derivative instruments.
(a) Evaluation of disclosure controls and procedures.
As of the end of the period covered by this quarterly report, Southern Company, the retail operating companies and Southern Power conducted separate evaluations under the supervision and with the participation of each company’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based upon those evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective in alerting them in a timely manner to material information relating to each company (including its consolidated subsidiaries) required to be included in periodic filings with the SEC.
(b) Changes in internal controls.
There have been no changes in Southern Company’s, the retail operating companies’ or Southern Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the second quarter of 2004 that have materially affected or are reasonably likely to materially affect, Southern Company’s, the retail operating companies’ or Southern Power’s internal control over financial reporting.
26
ALABAMA POWER COMPANY
27
ALABAMA POWER COMPANYCONDENSED STATEMENTS OF INCOME (UNAUDITED)
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
28
ALABAMA POWER COMPANYCONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
29
ALABAMA POWER COMPANYCONDENSED BALANCE SHEETS (UNAUDITED)
30
31
ALABAMA POWER COMPANYMANAGEMENT’S DISCUSSION AND ANALYSIS OFRESULTS OF OPERATIONS AND FINANCIAL CONDITION
SECOND QUARTER 2004 vs. SECOND QUARTER 2003ANDYEAR-TO-DATE 2004 vs. YEAR-TO-DATE 2003
Alabama Power’s net income after dividends on preferred stock for the second quarter and year-to-date 2004 was $104.3 million and $195.0 million, respectively, compared to $106.6 million and $198.4 million, respectively, for the corresponding periods of 2003. Earnings in the second quarter of 2004 decreased by $2.3 million, or 2.2%, primarily due to higher maintenance expenses and income and other taxes, partially offset by an increase in retail base-rate revenues and a decrease in interest expense. Earnings year-to-date 2004 decreased by $3.4 million, or 1.7%, principally due to higher maintenance expense, depreciation expense, and income and other taxes. These increases were partially offset by an increase in base rate revenues and a decrease in interest expense.
Retail sales. Excluding energy cost recovery revenues and revenues associated with PPAs certificated by the Alabama PSC, which generally do not affect net income, retail sales revenues increased by $25.5 million, or 4.6%, for the second quarter 2004 and $47.1 million, or 4.5%, year-to-date 2004 when compared to the corresponding periods in 2003. See Note 3 to the financial statements of Alabama Power under “Retail Rate Adjustment Procedures” in Item 8 of the Form 10-K for additional information. Kilowatt-hour energy sales to residential, commercial, and industrial customers increased 7.1%, 4.2%, and 3.0%, respectively, for the second quarter 2004 and increased 5.7%, 3.4% and 5.8%, respectively, year-to-date 2004 when compared to the corresponding periods of 2003 primarily due to more favorable weather conditions and improved industrial sales mainly in the coal mining, primary metal and automotive sectors.
32
Other revenues. The increases in other revenues for the second quarter and year-to-date 2004 are attributed to a $3.4 million increase in revenues from cogeneration steam facilities due to increased fuel revenue resulting from higher gas prices, a $1.6 million increase in rent from pole attachments and a $1.0 million increase in transmission revenues when compared to the same periods in 2003. Since cogeneration steam fuel revenues are generally offset by fuel expense, these revenues do not have a significant impact on earnings.
Fuel expense. Fuel expense was higher in the second quarter 2004 when compared to the corresponding period in 2003 mainly due to a 35.7% increase in natural gas prices and a 10.8% increase in generation from natural gas-fired generating facilities. The year-to-date 2004 increase in fuel expense when compared to the same period in 2003 is mainly due to a 30.6% increase in natural gas prices and a 24.0% increase in generation from gas-fired generating facilities. These increases in generation from gas-fired facilities in the second quarter and year-to-date 2004 when compared to the corresponding periods in 2003 are mainly due to an increased energy demand coupled with a 68.4% decrease and a 48.4% decrease, respectively, in generation from Alabama Power’s hydroelectric facilities. Since energy expenses are generally offset by energy revenues, these expenses do not have a significant impact on earnings. See “Future Earnings Potential – FERC and Alabama PSC Matters – Retail Fuel Cost Recovery” herein for additional information.
Purchased power – non-affiliates. In the second quarter and year-to-date 2004, purchased power from non-affiliates increased when compared to the same periods in 2003 primarily due to a 99.5% increase in energy purchased during the second quarter 2004 even though purchased power prices decreased by 31.0% during the second quarter 2004. Increased purchases were used to help meet the increased energy demand for retail sales. These transactions did not have a significant impact on earnings since energy purchases are generally offset by energy revenues through Alabama Power’s energy cost recovery clause.
Purchased power — affiliates. Purchased power from affiliates increased in the second quarter and year-to-date 2004 over the same periods in 2003 due to a PPA between Alabama Power and Southern Power that began in June 2003. The capacity component of these transactions was $13.0 million in the second quarter 2004 and $22.4 million year-to-date 2004. Purchases of energy will vary depending on demand and the availability and cost of generating resources at each company. These transactions did not have a significant impact on earnings since energy purchases are generally offset by energy revenues through Alabama Power’s energy cost recovery clause. See Note 3 to the financial statements of Alabama Power under “Retail Rate Adjustment Procedures” in Item 8 of the Form 10-K for additional information on base rate adjustments for certificated PPA expenses.
Maintenance expense. The increase in maintenance expense for the second quarter 2004 when compared to the same period in 2003 is attributed to a $3.3 million increase in distribution expense, a $2.1 million increase in Washington County combined cycle turbine expense primarily due to caustic water damage and a $1.9 million increase in transmission expense. The year-to-date 2004 increase in maintenance expense is mainly due to a $6.6 million increase in distribution expense and a $3.7 million increase in transmission expense. These increases in transmission and distribution are mainly related to scheduled work performed on overhead lines.
Depreciation and amortization expense. The increases in depreciation and amortization expense for the second quarter and year-to-date 2004 are attributed to an increase in utility plant in service when compared to the same periods in 2003. See Note 7 to the financial statements of Alabama Power under “Construction Program” in Item 8 of the Form 10-K for additional information.
Taxes other than income taxes. The second quarter 2004 increase in taxes other than income taxes is mainly due to a $1.3 million increase in property tax expense as a result of a higher assessed property values when compared to the corresponding period in 2003. The year-to-date 2004 increase in taxes other than income
33
taxes when compared to the same period in 2003 is primarily due to a $2.7 million increase in payroll taxes, a $2.7 million increase in property tax expense and a $1.7 million increase in the state public utility license tax because of increased retail revenues.
Interest expense, net of amounts capitalized. The decrease in interest expense, net of amounts capitalized, during the second quarter and year-to-date 2004 when compared to the same periods in 2003 is the result of refinancing higher cost debt. For additional information, see FINANCIAL CONDITION AND LIQUIDITY – “Financing Activities” herein.
Income taxes. Income tax expense increased for the second quarter and year-to-date of 2004 due primarily to greater taxable income in the second quarter of 2004 compared to 2003, resulting in an additional $6.5 million tax expense. Income tax expense increased an additional $4.2 million in the second quarter of 2004 due to a state income tax actualization adjustment. Also, an income tax settlement which was recorded in 2003 resulted in a $4.7 million increase to net income in the second quarter of 2003.
Dividends on preferred stock. Dividends on preferred stock increased for the second quarter and year-to-date 2004 due to the issuance of 4,000,000 shares ($100 million aggregate stated capital) of 5.30% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share) in February 2004.
The results of operations discussed above are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors including Alabama Power’s ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs and to recover costs related to growing demand and increasingly stricter environmental standards. Growth in energy sales is subject to a number of factors. These factors include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand and the rate of economic growth in Alabama Power’s service area. For additional information relating to these issues, see BUSINESS – The SOUTHERN System — “Risk Factors” in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS — “Future Earnings Potential” of Alabama Power in Item 7 of the Form 10-K.
New Source Review Actions
Compliance costs related to the Clean Air Act and other environmental regulations could affect earnings if such costs cannot be recovered. For additional information about these issues, including the EPA litigation, see MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Future Earnings Potential – Environmental Matters” of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under “New Source Review Actions” in Item 8 of the Form 10-K. As of March 15, 2004, civil penalties under the Clean Air Act were increased prospectively to a maximum of $32,500 per day, per violation. To the extent alleged violations under the New Source Review litigation are deemed to be continuing, this increased civil penalty amount could apply to such violations found to continue after that date.
On May 3, 2004, the U.S. Supreme Court denied the EPA’s petition to review the Eleventh Circuit Court of Appeals’ decision in the EPA’s similar New Source Review enforcement action against the TVA. The case against Alabama Power had been effectively stayed pending final resolution of the TVA case. With the denial of the EPA’s petition for review, the Court of Appeals’ decision became final. Alabama Power and the EPA
34
jointly notified the District Court for the Northern District of Alabama, where the case against Alabama Power is pending and requested that the stay be lifted. On June 16, 2004, the District Court lifted the stay, placing the case back onto the District Court’s active docket. An adverse outcome in this case could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
On March 12, 2004, the EPA redesignated the Birmingham, Alabama area from nonattainment to attainment under the one-hour ozone national ambient air quality standard. On April 30, 2004, the EPA published its eight-hour ozone nonattainment designations and a portion of the rules implementing the new eight-hour standard. Within Alabama Power’s service area, Birmingham has been designated as nonattainment under the eight-hour ozone standard. Under the implementation provisions of the new rule, the EPA announced that the one-hour ozone standard will be revoked on June 15, 2005. The impact of the eight-hour designations and the new standards will depend on the development and implementation of applicable state regulations and therefore cannot be determined at this time.
In June 2004, the EPA issued its recommendations for areas to be designated “nonattainment” for the fine particle national ambient air quality standard. Areas within the Alabama Power’s service area that were included in the EPA’s proposed fine particulate matter designations include counties surrounding Birmingham, Alabama. Alabama Power owns several plants located within the counties proposed for the nonattainment designation. The EPA plans to make final nonattainment designations for fine particulate matter by the end of 2004.
35
FERC and Alabama PSC Matters
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Future Earnings Potential – FERC Matters – Market-Based Rate Authority” of Alabama Power in Item 7 of the Form 10-K and Note 3 to the financial statements of Alabama Power under “FERC Matters” in Item 8 of the Form 10-K. On April 14, 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach includes a pivotal supplier analysis and a wholesale market share analysis, the results of which provide a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power. Southern Company, the retail operating companies, including Alabama Power, and Southern Power believe that it may be difficult for a traditional utility company, or an affiliate thereof, with a significant load service obligation and generation to satisfy that obligation, and that is not a member of a large, FERC-approved RTO, to pass all aspects of the market power screens as currently designed. However, each of the companies believes that it has an appropriate basis to rebut the generation market power presumption.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Future Earnings Potential – FERC Matters — Transmission” of Alabama Power in Item 7 of the Form 10-K for information on the FERC’s order related to RTOs and the FERC’s notice of proposed rulemaking regarding open access transmission service and standard electricity market design.
Environmental Rate Filing
36
In March 2002, the Alabama PSC issued a consent order establishing the current customer fuel rates, which Alabama Power began collecting in April 2002. In recent months, Alabama Power has experienced higher than expected fuel costs for coal and gas. Those higher fuel costs have increased the under recovered fuel costs included in the Condensed Balance Sheets herein. Alabama Power will continue to monitor the under recovered fuel cost balance in light of these higher fuel costs. See Note 3 to the financial statements of Alabama Power under “Retail Rate Adjustment Procedures” in Item 8 of the Form 10-K for additional information.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Future Earnings Potential – Other Matters” of Alabama Power in Item 7 of the Form 10-K for information on nuclear security measures. Implementation plans for the measures ordered by the NRC to be in effect by October 29, 2004 have been finalized based on current interpretations of the requirements. Alabama Power currently estimates its expenditures related to these security measures to total $9.6 million, of which $9.3 million will be capitalized. These estimates are subject to change in the event additional NRC guidance is provided.
Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Alabama Power’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Alabama Power cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Alabama Power’s financial statements.
Alabama Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS - ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power’s critical accounting policies and estimates related to Electric Utility Regulation and Contingent Obligations.
37
On March 31, 2004, Alabama Power prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of FASB Interpretation No. 46R had no impact on Alabama Power’s net income. However, as a result of the adoption, Alabama Power deconsolidated certain wholly-owned trusts established to issue preferred securities since Alabama Power does not meet the definition of primary beneficiary established by FASB Interpretation No. 46R. See Note (D) to the Condensed Financial Statements herein for additional information related to the adoption of FASB Interpretation No. 46R.
In May 2004, the FASB approved Staff Position (FSP) No. 106-2, “Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “Medicare Act”).” FSP No. 106-2 requires recognition of the impacts of the Medicare Act in the accumulated post-retirement benefit obligation and future cost of service for post-retirement medical plans and may be applied retroactively to the enactment of the Medicare Act in December 2003 or prospectively effective for the third quarter 2004. Alabama Power has elected to apply this treatment prospectively. Pending the finalization of federal regulations governing the subsidy effected in the Medicare Act, Alabama Power does not anticipate a material impact on its financial statements from the adoption of FSP No. 106-2.
Major changes in Alabama Power’s financial condition during the first six months of 2004 included the addition of approximately $376 million to utility plant. The funds for these additions and other capital requirements were derived primarily from operating activities and net proceeds from security issuances of $269 million. See Alabama Power’s Condensed Statements of Cash Flows herein for further details.
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power’s capital requirements for its construction program, lease obligations, purchase commitments and trust funding requirements. Approximately $525 million will be required by June 30, 2005 for maturities of long-term debt.
In addition to the financing activities described below, Alabama Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past. The amount, type and timing of any financings — if needed — will depend upon maintenance of adequate earnings, regulatory approval, prevailing market conditions and other factors. See BUSINESS — “Financing Programs” in Item 1 of the Form 10-K for additional information.
Alabama Power’s current liabilities exceed current assets primarily because of scheduled maturities of long-term debt. To meet short-term cash needs and contingencies, at June 30, 2004 Alabama Power had $28 million of cash and cash equivalents, unused committed lines of credit of approximately $808 million (including $504 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds) and an extendible commercial note program. These lines of credit will expire at various times during 2004 ($165 million), 2005 ($418 million) and 2007 ($225 million). Alabama Power
38
expects to renew its credit facilities, as needed, prior to expiration. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of Alabama Power and other Southern Company subsidiaries. Alabama Power has regulatory authority for up to $1 billion of short-term borrowings. At June 30, 2004, Alabama Power had $46 million of commercial paper outstanding. Management believes that the need for working capital can be adequately met by issuing commercial paper or utilizing lines of credit without maintaining large cash balances.
Alabama Power does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are contracts that could require collateral – but not accelerated payment – in the event of a credit rating change to below investment grade. These contracts are primarily for physical electricity purchases and sales, fixed price physical gas purchases and agreements covering interest rate swaps. At June 30, 2004, the maximum potential collateral requirements were approximately $27 million. Generally, collateral may be provided for by a Southern Company guaranty, letter of credit or cash.
Alabama Power’s market risk exposures relative to interest rate changes have not changed materially compared with the December 31, 2003 reporting period. In addition, Alabama Power is not aware of any facts or circumstances that would significantly affect such exposures in the near term.
Due to cost-based rate regulations, Alabama Power has limited exposure to market volatility in interest rates, commodity fuel prices and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Alabama Power enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, similar contracts for gas purchases. Alabama Power has also implemented a retail fuel hedging program at the instruction of the Alabama PSC. The fair value of derivative energy contracts at June 30, 2004 was as follows:
39
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Alabama Power in Item 7 of the Form 10-K and Notes 1 and 6 to the financial statements of Alabama Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein.
In April 2004, Alabama Power issued $150 million of Series AA 5 5/8% Senior Notes due April 15, 2034 and terminated $150 million of swaps at a gain of $6 million. The proceeds from the sale were used together with other funds to redeem, in May 2004, $200 million in aggregate principal amount of the Series J 6.75% Senior Notes due June 30, 2039. The gain from the terminated swaps was deferred in Other Comprehensive Income and will be amortized to income over the life of the Series AA Senior Notes.
Alabama Power plans to continue, when economically feasible, a program to retire higher-cost debt and replace these obligations with lower-cost capital if market conditions permit.
40
GEORGIA POWER COMPANY
41
GEORGIA POWER COMPANYCONDENSED STATEMENTS OF INCOME (UNAUDITED)
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
42
GEORGIA POWER COMPANYCONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
43
GEORGIA POWER COMPANYCONDENSED BALANCE SHEETS (UNAUDITED)
44
45
GEORGIA POWER COMPANYMANAGEMENT’S DISCUSSION AND ANALYSIS OFRESULTS OF OPERATIONS AND FINANCIAL CONDITION
Georgia Power’s net income after dividends on preferred stock for the second quarter and year-to-date 2004 was $155.7 million and $299.6 million, respectively, compared to $158.5 million and $291.8 million, respectively, for the corresponding periods in 2003. Earnings in the second quarter decreased by $2.8 million, or 1.8%, primarily due to higher non-fuel operating expenses partially offset by higher retail base revenues when compared to the same period in 2003. Earnings for year-to-date 2004 increased $7.8 million, or 2.7%, primarily due to higher retail base revenues partially offset by higher non-fuel operating expenses.
Retail sales. Excluding fuel revenues, which generally do not affect net income, retail sales revenue increased by $70.9 million, or 9.7%, in the second quarter 2004 compared to the corresponding period in 2003. In the second quarter 2004, kilowatt-hour energy sales to residential, commercial and industrial customers increased by 13.2%, 6.2% and 3.4%, respectively, when compared to the same period in 2003. Year-to-date 2004 base retail sales revenue increased by $102.8 million, or 7.3%, compared to the corresponding period in 2003. Year-to-date kilowatt-hour energy sales to residential, commercial and industrial customers increased by 9.1%, 5.1% and 2.8%, respectively, when compared to the same period in 2003. These increases in the retail sectors during the second quarter and year-to-date 2004 are mainly due to customer growth of 2%, more favorable weather, and an improving economy when compared to the same periods in 2003.
46
Fuel expense. During the second quarter and year-to-date 2004, fuel expense was higher due to increases of 14.0% and 14.1%, respectively, in the average cost of fuel and increases of 1.7% and 1.8%, respectively, in generation due to increased retail sales. These expenses do not have a significant impact on earnings since fuel expenses are generally offset by fuel revenues through Georgia Power’s fuel cost recovery clause. See “Future Earnings Potential – FERC and Georgia PSC Matters – Retail Fuel Cost Recovery” herein for additional information.
Purchased power — non-affiliates. The second quarter and year-to-date 2004 increases in purchased power from non-affiliates are primarily due to fluctuations in off-system energy purchases used to meet off-system sales commitments. These expenses do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Georgia Power’s fuel cost recovery clause.
Purchased power — affiliates. Purchased power from affiliates increased in the second quarter and year-to-date 2004 when compared to the corresponding periods in 2003 due to a PPA between Georgia Power and Southern Power that began in June 2003. The capacity component of these transactions increased $15.6 million and $25.8 million in the second quarter and year-to-date 2004, respectively, over the same periods in 2003. The energy component of power purchased from affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company and will have no significant impact on earnings since energy expenses are generally offset by energy revenues through Georgia Power’s fuel cost recovery clause.
Other operations expense. Other operations expense in the second quarter and year-to-date 2004 was higher when compared to the same periods in 2003 due to increased administrative and general expenses of $8.0 million and $13.8 million, respectively, related to increased employee benefit expenses and $3.2 million in workers compensation expenses for year-to-date 2004.
Maintenance expense. Maintenance expense was higher in the second quarter and year-to-date 2004 when compared to the same periods in 2003 due to the timing of scheduled generating plant maintenance of $8.7 million and $4.2 million, respectively, and scheduled transmission and distribution maintenance of $10.2 million and $13.2 million, respectively.
Depreciation and amortization. In the second quarter and year-to-date 2004, depreciation and amortization expense was lower compared to the corresponding periods in 2003. These decreases were caused primarily by lower regulatory charges needed to levelize purchased power capacity costs under the terms of the retail rate order effective January 1, 2002. These decreases were offset by increases in affiliated purchased power costs discussed above. See Note 1 to the financial statements of Georgia Power under “Depreciation and Amortization” in Item 8 of the Form 10-K for additional information.
Allowance for equity funds used during construction. The second quarter and year-to-date 2004 increases result primarily from the acquisition of the McIntosh combined cycle units 10 and 11 construction project from Southern Power. See “FERC Matters” herein and Note (J) to the Condensed Financial Statements herein for additional information.
Interest income. The second quarter and year-to-date 2004 decreases result from $14.5 million of interest on a favorable tax settlement received in the second quarter of 2003.
47
GEORGIA POWER COMPANYMANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OFOPERATIONS AND FINANCIAL CONDITION
Other income (expense), net. The second quarter and year-to-date 2004 decreases in other income (expense), net reflect decreased rental income of $4.0 million and $2.5 million, respectively, as well as the impact of the ESOP contribution in June 2004 of $3.4 million when compared to the same periods in 2003. The year-to-date 2004 decrease in other income (expense), net also reflects a $5.0 million decrease related to the 2003 favorable resolution of a loss contingency.
The results of operations discussed above are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors including Georgia Power’s ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs, and to recover costs related to growing demand and increasingly stricter environmental standards. Growth in energy sales is subject to a number of factors, which include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the service area. For additional information relating to these issues, see BUSINESS — The SOUTHERN System — “Risk Factors” in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS — “Future Earnings Potential” of Georgia Power in Item 7 of the Form 10-K.
Compliance costs related to the Clean Air Act and other environmental regulations could affect earnings if such costs cannot be recovered. For additional information, including information on certain environmental litigation, see MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS - “Future Earnings Potential — Environmental Matters” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “New Source Review Actions” and “Plant Wansley Environmental Litigation” in Item 8 of the Form 10-K. As of March 15, 2004, civil penalties under the Clean Air Act were increased prospectively to a maximum of $32,500 per day, per violation. To the extent alleged violations under either the New Source Review litigation or Plant Wansley environmental litigation are deemed to be continuing, this increased civil penalty amount could apply to such violations found to continue after that date.
On May 3, 2004, the U.S. Supreme Court denied the EPA’s petition to review the Eleventh Circuit Court of Appeals’ decision in the EPA’s similar New Source Review enforcement action against the TVA. The case against Georgia Power had been effectively stayed pending final resolution of the TVA case. With the denial of the EPA’s petition for review, the Court of Appeals’ decision became final. At this time, no party to the case against Georgia Power has sought to reopen the case, which remains administratively closed in the District Court for the Northern District of Georgia.
On June 10, 2004, the U.S. District Court for the Northern District of Georgia granted Georgia Power’s motion in the Plant Wansley environmental litigation for partial summary judgment regarding emissions offsets. The case has been removed from the court’s trial calendar due to pending motions for summary judgment, and a new trial date has not been scheduled. An adverse outcome in either of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows and possibly financial condition if such costs are not recovered through regulated rates.
48
On April 30, 2004, the EPA published its eight-hour ozone nonattainment designations and a portion of the rules implementing the new eight-hour standard. Areas within Georgia Power’s service area that have been designated as nonattainment under the eight-hour ozone standard include Macon (Georgia) and a 20-county area within metropolitan Atlanta. Under the implementation provisions of the new rule, the EPA announced that the one-hour ozone standard will be revoked on June 15, 2005. Areas classified as “severe” nonattainment areas under the one-hour standard will not be required to impose emissions fees as a result of nonattainment. Georgia Power, therefore, will no longer be subject to imposition of emissions fees if the Atlanta area does not come into attainment with the one-hour standard. The impact of the eight-hour designations and the new standards will depend on the development and implementation of applicable state regulations and therefore cannot be determined at this time.
In June 2004, the EPA issued its recommendations for areas to be designated “nonattainment” for the fine particle national ambient air quality standard. Areas within Georgia Power’s service area that were included in the EPA’s proposed fine particulate matter designations include 24 counties in the metro-Atlanta area; counties surrounding Macon, Athens and Columbus, Georgia; and counties in Georgia near Chattanooga, Tennessee. Georgia Power owns several plants located within the counties proposed for the nonattainment designations. The EPA plans to make final nonattainment designations for fine particulate matter by the end of 2004.
49
FERC and Georgia PSC Matters
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS — “Future Earnings Potential – FERC Matters – Market-Based Rate Authority” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “FERC Matters” in Item 8 of the Form 10-K. On April 14, 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach includes a pivotal supplier analysis and a wholesale market share analysis, the results of which provide a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power. Southern Company, the retail operating companies, including Georgia Power, and Southern Power believe that it may be difficult for a traditional utility company, or an affiliate thereof, with a significant load service obligation and generation to satisfy that obligation, and that is not a member of a large, FERC-approved RTO, to pass all aspects of the market power screens as currently designed. However, each of the companies believes that it has an appropriate basis to rebut the generation market power presumption.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS — “Future Earnings Potential — FERC Matters — Transmission” of Georgia Power in Item 7 of the Form 10-K for information on the FERC’s order related to RTOs and the FERC’s notice of proposed rulemaking regarding open access transmission service and standard electricity market design.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION — “Future Earnings Potential — FERC Matters” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “FERC Matters” in Item 8 of the Form 10-K for information regarding PPAs between Southern Power and Savannah Electric and Georgia Power for Plant McIntosh capacity. In April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund and ordered that hearings be held. To ensure the timely completion of
50
construction on McIntosh units 10 and 11 and their availability in the summer of 2005 as supply side resources for the retail customers in the State of Georgia, on May 7, 2004, Savannah Electric and Georgia Power requested the Georgia PSC to direct them to acquire the McIntosh construction project. Savannah Electric and Georgia Power proposed to place the units in rate base at a cost approved by the Georgia PSC and to recover the unit operation and maintenance costs as retail service expenses as may be approved by the Georgia PSC. The Georgia PSC issued such an order on May 18, 2004 and the transfer occurred on May 24, 2004. On May 20, 2004, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. On August 4, 2004, the FERC issued a notice that it allowed the request to withdraw the PPAs to be accepted and to become effective by operation of law on July 20, 2004. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. The ultimate outcome of this matter cannot now be determined.
The May 18, 2004 Georgia PSC order also directed Georgia Power and Savannah Electric to file an application within 10 days of completing such purchase to amend the resource certificate granted by the Georgia PSC in 2002 to describe the capacity resource as being the McIntosh units 10 and 11 (as opposed to the McIntosh PPAs), the approximate construction schedule (which is not expected to change) and the proposed rate base treatment. The application was filed on June 3, 2004 and the Georgia PSC will have 180 days to respond. The Georgia PSC is expected to review the application in accordance with its affiliate transaction guidelines, which require a lower of cost or market approach unless otherwise determined by the Georgia PSC. Georgia Power and Savannah Electric have submitted information showing that the book cost of the McIntosh construction project is lower than its market value. However, full recovery of the project costs depends on the outcome of the Georgia PSC’s review. In the event the Georgia PSC does not allow full recovery of the project costs, then part of such costs may have to be written off in accordance with FASB Statement No. 90, “Accounting for Abandonments and Disallowed Plant Costs.” At June 30, 2004, the investment in the McIntosh construction project totaled approximately $353.2 million for Georgia Power. The ultimate outcome of the Georgia PSC’s review cannot now be determined.
Retail Rate Case
On July 1, 2004, Georgia Power filed a request with the Georgia PSC for an approximate 7 percent increase in retail revenues, effective January 1, 2005. The requested increase is based on a future test year ending July 31, 2005 and a proposed retail return on common equity of 12.5 percent. Georgia Power is currently operating under a three-year retail rate order that expires December 31, 2004. Under the terms of the existing order, earnings are evaluated annually against a retail return on common equity range of 10 percent to 12.95 percent. Two-thirds of any earnings above the 12.95 percent return are applied to rate refunds, with the remaining one-third retained by Georgia Power. The order required Georgia Power to file a general rate case by July 1, 2004.
The increase in retail revenues is being requested to cover the higher costs of purchased power; operating and maintenance expenses; environmental compliance; and continued investment in new generation, transmission and distribution facilities to support growth and ensure reliability. Georgia Power expects the Georgia PSC to issue a final order in this matter during December 2004. The final outcome of this matter cannot now be determined. See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Future Earnings Potential – Other Matters” of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under “Retail Rate Orders” in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements herein for additional information.
51
In August 2003, the Georgia PSC issued an order allowing Georgia Power to increase customer fuel rates to collect existing under recovered fuel costs over the period October 1, 2003 through March 31, 2005. Georgia Power has experienced higher than expected fuel costs since the order was issued. Those higher fuel costs have increased the under recovered fuel costs included in the Condensed Balance Sheets herein. Georgia Power will continue to monitor the under recovered fuel cost balance in light of these higher fuel costs. See Note 3 to the financial statements of Georgia Power under “Fuel Cost Recovery” in Item 8 of the Form 10-K for additional information.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – “Future Earnings Potential – Other Matters” of Georgia Power in Item 7 of the Form 10-K for information on nuclear security measures. Implementation plans for the measures ordered by the NRC to be in effect by October 29, 2004 have been finalized based on current interpretations of the requirements. Georgia Power, based on its ownership interest, currently estimates its expenditures related to these security measures will total $9.3 million, of which 1.3 million will be capitalized. These estimates are subject to change in the event additional NRC guidance is provided.
Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Georgia Power’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Georgia Power cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Georgia Power’s financial statements.
Georgia Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power’s critical accounting policies and estimates related to Electric Utility Regulation and Contingent Obligations.
52
On March 31, 2004, Georgia Power prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of FASB Interpretation No. 46R had no impact on Georgia Power’s net income. However, as a result of the adoption, Georgia Power deconsolidated certain wholly-owned trusts established to issue preferred securities since Georgia Power does not meet the definition of primary beneficiary established by FASB Interpretation No. 46R. See Note (D) to the Condensed Financial Statements herein for additional information related to the adoption of FASB Interpretation No. 46R.
In May 2004, the FASB approved Staff Position (FSP) No. 106-2, “Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “Medicare Act”).” FSP No. 106-2 requires recognition of the impacts of the Medicare Act in the accumulated post-retirement benefit obligation and future cost of service for post-retirement medical plans and may be applied retroactively to the enactment of the Medicare Act in December 2003 or prospectively effective for the third quarter 2004. Georgia Power has elected to apply this treatment prospectively. Pending the finalization of federal regulations governing the subsidy effected in the Medicare Act, Georgia Power does not anticipate a material impact on its financial statements from the adoption of FSP No. 106-2.
Major changes in Georgia Power’s financial condition during the first six months of 2004 included the addition of approximately $672.4 million to utility plant. The funds for these additions and other capital requirements were derived primarily from operating activities, short-term borrowings and equity funds from Southern Company. See Georgia Power’s Condensed Statements of Cash Flows herein for further details.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power’s capital requirements for its construction program, lease obligations, purchase commitments and trust funding requirements. Approximately $302 million will be required by June 30, 2005 for redemptions and maturities of long-term debt. The purchase of the McIntosh construction project is expected to temporarily increase short-term borrowings under the commercial paper program. The temporary increase will be replaced with additional long-term debt. The projected construction program will increase by $437.8 million and $27.4 million in 2004 and 2005, respectively, for the Plant McIntosh combined cycle construction project and the projected purchased power commitments will decrease by $133.2 million in 2005-2006, $147.5 million in 2007-2008 and $885.2 million beyond 2008 as a result of the purchase of the construction project.
Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, including funds from operations and new security issuances. The amount, type and timing of additional security issuances — if needed — will depend upon maintenance of adequate earnings, regulatory approval, prevailing market conditions and other factors. See BUSINESS — “Financing Programs” in Item 1 of the Form 10-K for additional information.
53
Georgia Power’s current liabilities exceed current assets because of the continued use of short-term debt as a funding source to meet cash needs, which can fluctuate significantly due to the seasonality of the business. To meet short-term cash needs and contingencies, Georgia Power had at June 30, 2004 approximately $20.3 million of cash and cash equivalents and $773 million of unused credit arrangements with banks. Of these facilities, $423 million expire in 2005 and contain provisions allowing two-year term loans executable at expiration; with the remaining $350 million expiring in 2007. The credit arrangements provide liquidity support to Georgia Power’s obligations with respect to variable rate pollution control bonds and commercial paper. Georgia Power expects to renew its credit facilities, as needed, prior to expiration. Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of Georgia Power and other Southern Company subsidiaries. At June 30, 2004, Georgia Power had $372 million of commercial paper outstanding. Management believes that the need for working capital can be adequately met by utilizing commercial paper programs and lines of credit without maintaining large cash balances.
Georgia Power does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are contracts that could require collateral — but not accelerated payment — in the event of a credit rating change to below investment grade. These contracts are primarily for physical electricity purchases and sales, fixed-price physical gas purchases and agreements covering interest rate swaps. At June 30, 2004, the maximum potential collateral requirements were approximately $226 million. Generally, collateral may be provided for by a Southern Company guaranty, letter of credit or cash.
Georgia Power’s market risk exposures relative to interest rate changes have not changed materially compared with the December 31, 2003 reporting period. In addition, Georgia Power is not aware of any facts or circumstances that would significantly affect such exposures in the near term.
Due to cost-based rate regulations, Georgia Power has limited exposure to market volatility in interest rates, commodity fuel prices and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Georgia Power enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, similar contracts for gas purchases. Georgia Power has also implemented a retail fuel hedging program at the instruction of the Georgia PSC. The fair value of derivative energy contracts at June 30, 2004 was as follows:
54
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” of Georgia Power in Item 7 and Notes 1 and 6 to the financial statements of Georgia Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein.
In January 2004, Georgia Power issued $100 million of Series S 4.00% Senior Notes due January 15, 2011 and $100 million of Series T 5.75% Senior Public Income Notes due January 15, 2044. The proceeds from these sales were used in March 2004 to redeem all of its outstanding Series H 6.70% Senior Insured Quarterly Notes due March 1, 2011 and Series D 6 5/8% Senior Notes due March 31, 2039. In February 2004, Georgia Power issued $150 million of Series U Floating Rate Senior Notes due February 17, 2009. The proceeds of this sale were used for general corporate purposes.
Further in January 2004, Georgia Power Capital Trust VII, a statutory trust, sold $200 million of its 5 7/8% Trust Preferred Securities, which are guaranteed by Georgia Power. The net proceeds from this issuance were used to redeem the 6.85% Trust Preferred Securities of Georgia Power Capital Trust IV. In connection with this transaction, Georgia Power issued $206 million of its junior subordinated debentures to Georgia Power Capital Trust VII.
Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
55
GULF POWER COMPANY
56
GULF POWER COMPANYCONDENSED STATEMENTS OF INCOME (UNAUDITED)
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
57
GULF POWER COMPANYCONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
58
GULF POWER COMPANYCONDENSED BALANCE SHEETS (UNAUDITED)
59
60
GULF POWER COMPANYMANAGEMENT’S DISCUSSION AND ANALYSIS OFRESULTS OF OPERATIONS AND FINANCIAL CONDITION
Gulf Power’s net income after dividends on preferred stock for the second quarter and year-to-date 2004 was $19.0 million and $35.8 million, respectively, compared to $18.8 million and $32.8 million, respectively, for the corresponding periods in 2003. Earnings in the second quarter and year-to-date 2004 increased by $0.2 million, or 1.2%, and $3.1 million, or 9.4%, respectively, as a result of higher operating revenues that were only partially offset with higher operating expenses.
Retail sales. Excluding the recovery of fuel expense and certain other expenses that do not affect net income, retail sales increased by $0.8 million, or 0.8%, for the second quarter 2004 and by $4.9 million, or 2.5%, year-to-date 2004 when compared to the corresponding periods in 2003. For both of the reporting periods, retail sales revenues were higher than the corresponding periods in 2003 primarily due to an increase in the number of customers and more favorable weather. During the second quarter 2004, retail energy sales to residential and industrial customers decreased by 0.3% and 5.2%, respectively, while energy sales to commercial customers increased by 2.9% as compared to the same period in 2003. For year-to-date 2004 as compared to 2003, retail energy sales to residential and commercial customers increased by 2.3% and 3.2%, respectively, while energy sales to industrial customers decreased by 1.5%. The decreases in industrial sales for the second quarter and year-to-date 2004 are primarily the result of permanent load reductions and customer operational issues, which vary from period to period.
Sales for resale — affiliates and Purchased power — affiliates. Revenues from sales for resale to affiliates and purchases of energy from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Gulf Power’s fuel cost recovery mechanism. The increases in the second quarter and year-to-date 2004 sales for resale to affiliates are due to increased sales of available
61
generation to affiliate companies at a higher unit cost resulting from higher fuel prices. The increase in purchased power from affiliates in the second quarter 2004 is primarily due to higher priced peak hour energy purchases that resulted from increased fuel prices. The decrease in purchased power from affiliates for year-to-date 2004 is primarily due to an increase in Gulf Power generation to meet its load requirements.
Fuel expense. During the second quarter and year-to-date 2004, fuel expense increased from the corresponding periods in 2003 primarily due to a significant increase in the use of gas generation to meet additional demand for energy. Since energy expenses are generally offset by energy revenues through Gulf Power’s fuel cost recovery mechanism, these expenses do not have a material impact on net income.
Purchased power – non-affiliates. The increases for the second quarter and year-to-date 2004, when compared to the corresponding periods in 2003, are primarily attributed to Gulf Power’s increased purchase of off-system power from merchant generation resources in order to reduce total system energy production costs. Since energy expenses are generally offset by energy revenues, these expenses do not have a significant impact on net income.
Other operations expense. The increase in other operations expense during the second quarter 2004 is primarily due to a $2.0 million increase in employee benefit expenses and a $1.2 million increase in accrued expenses for uninsured litigation and workers compensation claims. The increase in other operations expense for year-to-date 2004 when compared to the corresponding period in 2003 is primarily due to a $3.4 million increase in employee benefit expenses, a $1.3 million increase in expenses related to marketing conservation programs and a $1.2 million increase in accrued expenses for uninsured litigation and workers compensation claims.
Taxes other than income taxes. The increases in taxes other than income taxes for the second quarter and year-to-date 2004 are primarily due to increased franchise fees and gross receipts taxes resulting from increased revenues.
Other income (expense), net. The increases in other income (expense), net for the second quarter and year-to-date 2004 when compared to the same periods in 2003 are primarily due to higher AFUDC related to the environmental controls project at Plant Crist.
The results of operations discussed above are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors, including Gulf Power’s ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs and to recover costs related to growing demand and increasingly stringent environmental standards. Growth in energy sales is subject to a number of factors, which include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth in the service area. For additional information relating to these issues, see BUSINESS — The SOUTHERN System — “Risk Factors” in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential” of Gulf Power in Item 7 of the Form 10-K.
62
Compliance costs related to the Clean Air Act and other environmental regulations could affect earnings if such costs are not fully recovered through Gulf Power’s Environmental Cost Recovery Clause. See MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential — Environmental Matters” in Item 7 of Gulf Power and Note 3 to the financial statements of Gulf Power under “New Source Review Actions” in Item 8 of the Form 10-K. As of March 15, 2004, civil penalties under the Clean Air Act were increased prospectively to a maximum of $32,500 per day, per violation. To the extent alleged violations under the New Source Review litigation are deemed to be continuing, this increased civil penalty amount could apply to such violations found to continue after that date.
On May 3, 2004, the U.S. Supreme Court denied the EPA’s petition to review the Eleventh Circuit Court of Appeals’ decision in the EPA’s similar New Source Review enforcement action against TVA. With the denial of the EPA’s petition for review, the Court of Appeals’ decision is now final. An adverse outcome in the New Source Review litigation described in Item 8 of the Form 10-K could require substantial capital expenditures and could possibly require substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
On May 5, 2004, the EPA published proposed amendments to its Regional Haze rules with respect to Best Available Retrofit Technology guidelines and requirements. The impact of these regulations will depend on the development and implementation of the final rules and implementation by the states, and therefore cannot be determined at this time.
FERC Matters
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS — “Future Earnings Potential — FERC Matters — Market Based Rate Authority” in Item 7 and Note 3 to the financial statements of Gulf Power under “FERC Matters” in Item 8 of the Form 10-K. On April 14, 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation
63
market power. This new interim approach includes a pivotal supplier analysis and a wholesale market share analysis, the results of which provide a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power. Southern Company, the retail operating companies, including Gulf Power, and Southern Power believe that it may be difficult for a traditional utility company, or an affiliate thereof, with a significant load service obligation and generation to satisfy that obligation, and that is not a member of a large, FERC-approved RTO, to pass all aspects of the market power screens as currently designed. However, each of the companies believes that it has an appropriate basis to rebut the generation market power presumption.
See MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential — FERC Matters — Transmission” of Gulf Power in Item 7 of the Form 10-K for information on the FERC’s order related to RTOs and notice of proposed rulemaking regarding open access transmission service and standard electricity market design.
Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Gulf Power’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Gulf Power cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Gulf Power’s financial statements.
64
Gulf Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Gulf Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS — ACCOUNTING POLICIES — “Application of Critical Accounting Policies and Estimates” of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power’s critical accounting policies and estimates related to Electric Utility Regulation and Contingent Obligations.
On March 31, 2004, Gulf Power prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of FASB Interpretation No. 46R had no impact on Gulf Power’s net income. However, as a result of the adoption, Gulf Power deconsolidated certain wholly-owned trusts established to issue preferred securities since Gulf Power does not meet the definition of primary beneficiary established by FASB Interpretation No. 46R. See Note (D) to the Condensed Financial Statements herein for additional information related to the adoption of FASB Interpretation No. 46R.
In May 2004, the FASB approved Staff Position (FSP) No. 106-2, “Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “Medicare Act”).” FSP No. 106-2 requires recognition of the impacts of the Medicare Act in the accumulated post-retirement benefit obligation and future cost of service for post-retirement medical plans and may be applied retroactively to the enactment of the Medicare Act in December 2003 or prospectively effective for the third quarter 2004. Gulf Power has elected to apply this treatment prospectively. Pending the finalization of federal regulations governing the subsidy effected in the Medicare Act, Gulf Power does not anticipate a material impact on its financial statements from the adoption of FSP No. 106-2.
Major changes in Gulf Power’s financial condition during the first six months of 2004 included the addition of approximately $70.2 million to utility plant. The funds for these additions and other capital requirements were derived primarily from operating activities. See Gulf Power’s Condensed Statements of Cash Flows herein for further details.
65
Reference is made to MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power’s capital requirements for its construction program, lease obligations, purchase commitments and trust funding requirements.
In addition to the financing activities described herein, Gulf Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past. These sources include cash flows from operating activities and issuances of unsecured debt, trust preferred securities, preferred stock and pollution control bonds issued for Gulf Power’s benefit by public authorities. The amount, type and timing of any future financings, if needed, will depend upon market conditions and regulatory approval. See BUSINESS — “Financing Programs” in Item 1 of the Form 10-K for additional information.
To meet short-term cash needs and contingencies, Gulf Power has various internal and external sources of liquidity. In addition, Gulf Power has substantial cash flow from operating activities. At June 30, 2004, Gulf Power had approximately $12.8 million of cash and cash equivalents and $56.3 million of unused committed lines of credit with banks. Of these facilities, $10 million expire in 2004 and the remaining $46.3 million expire in 2005. Gulf Power expects to renew its credit facilities, as needed, prior to expiration. The credit arrangements provide liquidity support to Gulf Power’s obligations with respect to variable rate pollution control bonds and commercial paper. Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of Gulf Power and other Southern Company subsidiaries. At June 30, 2004, Gulf Power had $5.0 million of commercial paper outstanding. Management believes that the need for working capital can be adequately met by utilizing lines of credit without maintaining large cash balances.
Gulf Power does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
Gulf Power’s market risk exposures relative to interest rate changes have not changed materially compared with the December 31, 2003 reporting period. In addition, Gulf Power is not aware of any facts or circumstances that would significantly affect such exposures in the near term.
66
Due to cost-based rate regulations, Gulf Power has limited exposure to market volatility in interest rates, commodity fuel prices and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Gulf Power enters into fixed price contracts for the purchase of coal supplies, the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, similar contracts for gas purchases. Gulf Power has received approval from the Florida PSC to recover prudently incurred costs related to its fuel hedging program through the fuel cost recovery mechanism. The fair value of derivative energy contracts at June 30, 2004 was as follows:
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” of Gulf Power in Item 7 of the Form 10-K and Notes 1 and 6 to the financial statements of Gulf Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein for further information.
In April 2004, Gulf Power issued $35 million of Series J 5.875% Senior Notes due April 1, 2044. The proceeds from this issue were used for general corporate purposes, including Gulf Power’s continuous construction program.
In addition to any financings that may be necessary to meet Gulf Power’s capital requirements and contractual obligations, Gulf Power plans to continue, when economically feasible, a program to retire higher-cost debt and replace these obligations with lower-cost capital if market conditions permit.
67
MISSISSIPPI POWER COMPANY
68
MISSISSIPPI POWER COMPANYCONDENSED STATEMENTS OF INCOME (UNAUDITED)
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
69
MISSISSIPPI POWER COMPANYCONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
The accompanying notes as they relate to Mississippi Power are an integral part of these condensedfinancial statements.
70
MISSISSIPPI POWER COMPANYCONDENSED BALANCE SHEETS (UNAUDITED)
71
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financialstatements.
72
MISSISSIPPI POWER COMPANYMANAGEMENT’S DISCUSSION AND ANALYSIS OFRESULTS OF OPERATIONS AND FINANCIAL CONDITION
Mississippi Power’s net income after dividends on preferred stock for the second quarter and year-to-date 2004 was $21. 9 million and $39.2 million, respectively, compared to $53.1 million and $74.5 million, respectively, for the corresponding periods of 2003. Earnings in the second quarter and year-to-date 2004 decreased by $31.2 million or 58.8%, and $35.3 million, or 47.4%, respectively, primarily as a result of the 2003 gain of $38 million after tax related to the termination of a PPA with Dynegy. This decrease was partially offset by the net impact of an $11 million decrease in other operations expense related to costs incurred in the second quarter of 2003 to restructure the lease agreement for the combined cycle generating units at Plant Daniel, and an increase of $11.8 million in pretax earnings in the second quarter of 2004 resulting from the impact of the Mississippi PSC’s order approving the inclusion of the Plant Daniel capacity in jurisdictional cost of service. See Note 3 to the financial statements of Mississippi Power under “Contract Termination” and “Retail Regulatory Filing” in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein for additional information.
Retail sales. Retail sales revenue increased $17.8 million, or 13.3%, in the second quarter 2004 and $32.4 million or 13.1% year-to-date 2004 when compared to the same periods in 2003. The increases in retail sales revenues are primarily as a result of an increase of $18.6 million in the second quarter 2004 and $32.2 million year-to-date 2004 in fuel revenues, which generally do not have an effect on income. Retail sales revenues, excluding fuel revenues, for the second quarter 2004 to residential, commercial and industrial customers decreased 2.4%, 1.3% and 0.4%, respectively, primarily as a result of mild weather when compared to the same period in 2003. Retail sales revenues, excluding fuel revenues, for year-to-date 2004 from residential, commercial and industrial customers remained mostly constant as compared to the same period in 2003.
73
Sales for resale — non-affiliates. The increase in sales for resale to non-affiliates in the second quarter 2004 as compared to the same period in 2003 is primarily due to the increased fuel revenue from wholesale territorial customers and increased energy sales to non-territorial customers.
Sales for resale — affiliates and Purchased power — affiliates. Revenues from sales for resale to affiliates, as well as purchases of energy from affiliates, will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These transactions do not have a significant impact on earnings since the energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Mississippi Power’s retail and wholesale fuel cost recovery clauses. The increase in sales for resale to affiliates is primarily a result of Mississippi Power’s more economical generating costs when compared to others. The increase in purchased power from affiliates is primarily due to the increase in the cost of fuel.
Fuel expense. In the second quarter and year-to-date 2004, fuel expense increased when compared to the same periods in 2003 as a result of 4.2% and 10.1% increases in generation, respectively, and a 42.5% and 50.6% increase in cost of oil and gas, respectively. Since energy expenses are generally offset by energy revenues through Mississippi Power’s retail and wholesale fuel cost recovery clauses, these expenses do not have a significant impact on earnings.
Purchased power – non-affiliates. The second quarter and year-to-date 2004 increases in purchased power from non-affiliates when compared to the same periods in 2003 are a result of increased purchased power demand as a result of planned outages at generating units for maintenance purposes in 2004.
Other operations expense. The second quarter and year-to-date 2004 decreases in other operation expense when compared to the same periods in 2003 are a result of approximately $11 million incurred during the second quarter 2003 to restructure the lease agreement for the combined cycle generating units at Plant Daniel. See Note 7 to the financial statements of Mississippi Power under “Operating Leases – Plant Daniel Combined Cycle Generating Units” in Item 8 of the Form 10-K for additional information.
Depreciation and amortization. The second quarter and year-to-date 2004 decreases in depreciation and amortization expense when compared to the same periods in 2003 are primarily the result of the amortization of a regulatory liability as approved by the Mississippi PSC. The Mississippi PSC issued an interim accounting order in December 2003 directing Mississippi Power to expense and record in 2003 a regulatory liability in the amount of approximately $60 million. Based on the final Mississippi PSC order issued May 25, 2004 that approved this treatment, Mississippi Power recorded during the second quarter a credit to expense in the amount of $8.3 million to amortize the regulatory liability retroactive to January 1, 2004. See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Filing” in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements and “Future Earnings Potential — FERC and Mississippi PSC Matters – Retail Rate Filing” herein for additional information.
Interest expense. The decreases in interest expense for the second quarter and year-to-date 2004 as compared to the same periods in 2003 are a result of lower interest rates. See MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY — “Financing Activities” of Mississippi Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY — “Financing Activities” herein for further information on efforts to reduce interest rates.
74
Income taxes. The second quarter and year-to-date decreases in income taxes of $18.1 million, or 54.6%, and $20.7 million, or 44.3%, respectively, are a result of the $47.3 million and $53.9 million, respectively, reduction in earnings before income taxes when compared to the same periods in 2003.
Dividends on preferred stock. The second quarter and year-to-date 2004 increases in dividends on preferred stock are the result of a $2.0 million loss on the redemption of preferred stock recognized in the second quarter of 2004.
The results of operations discussed above are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors including Mississippi Power’s ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs and to recover costs related to growing demand and increasingly stricter environmental standards. Growth in energy sales is subject to a number of factors, which include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand and the rate of economic growth in the service area. For additional information relating to these issues, see BUSINESS — The SOUTHERN System — “Risk Factors” in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS — “Future Earnings Potential” in Item 7 of Mississippi Power in the Form 10-K.
Mississippi Power’s 2004 ECO Plan filing was approved, as filed, by the Mississippi PSC on March 15, 2004, and resulted in a slight decrease in rates effective April 2004. Compliance costs related to the Clean Air Act and other environmental regulations could affect earnings if such costs cannot continue to be recovered. See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS — “Future Earnings Potential – Environmental Matters” in Item 7 and Note 3 to the financial statements of Mississippi Power under “New Source Review Actions” in Item 8 of the Form 10-K. As of March 15, 2004, civil penalties under the Clean Air Act were increased prospectively to a maximum of $32,500 per day, per violation. To the extent alleged violations under the New Source Review litigation are deemed to be continuing, this increased civil penalty amount could apply to such violations found to continue after that date.
On May 3, 2004, the U.S. Supreme Court denied the EPA’s petition to review the Eleventh Circuit Court of Appeals’ decision in the EPA’s similar New Source Review action against the TVA. With the denial of the EPA’s petition for review, the Court of Appeals’ decision is now final. An adverse outcome in the New Source Review litigation described in Item 8 of the Form 10-K could require substantial capital expenditures and could possibly require substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
On July 21, 2004, attorneys general from eight states, each outside of Southern Company’s service territory, and the corporation counsel for New York City filed a complaint in U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. A nearly identical complaint was filed by three environmental groups in the same court. The complaints allege that the companies’ emissions of carbon dioxide, a greenhouse gas, contribute to global warming, which the plaintiffs assert is a public nuisance. Plaintiffs seek relief under the federal common law or, in the alternative, under state law, of public nuisance. The environmental groups also seek relief under common law private nuisance theories. The plaintiffs seek a judicial order (1) holding each defendant jointly and severally liable for creating, contributing to, and/or maintaining an ongoing public nuisance, global warming and (2) permanently enjoining each of the
75
defendants to abate its contribution to the nuisance by capping its emissions of carbon dioxide and then reducing those emissions by a specified percentage each year for at least a decade. Plaintiffs have not, however, requested that damages be awarded in connection with their claims. Southern Company believes these claims are without merit and notes that the complaint cites no statutory or regulatory basis for the claims. Southern Company has not yet responded to the suits; however, it intends to vigorously defend against these claims. While the outcome cannot be determined at this time, an adverse judgment could result in substantial capital expenditures.
FERC and Mississippi PSC Matters
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS — “Future Earnings Potential — FERC Matters — Market-Based Rate Authority” of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under “FERC Matters” in Item 8 of the Form 10-K. On April 14, 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power. Southern Company, the retail operating companies, including Mississippi Power, and Southern Power believe that it may be difficult for a traditional utility company, or an affiliate thereof, with a significant load service obligation and generation to satisfy that obligation, and that is not a member of a large, FERC-approved RTO, to pass all aspects of the market power screens as currently designed. However, each of the companies believes that it has an appropriate basis to rebut the generation market power presumption.
On July 8, 2004, the FERC denied Southern Company’s request for rehearing, along with a number of others, and reaffirmed the interim tests that it adopted in April. Southern Company will submit the required analyses by August 9, 2004. In the event that the FERC’s default mitigation measures are ultimately applied, Southern Power and the retail operating companies may be required to charge cost-based rates, which may be lower than negotiated market-based rates. The final outcome of this matter will depend on the form in which the final methodology for assessing generation market power and mitigation rules may be ultimately adopted and cannot be determined at this time. See Note (B) to the Condensed Financial Statements under “FERC Matters” herein for additional information.
See MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential — FERC Matters” of Mississippi Power in Item 7 of the Form 10-K for information on the FERC’s order related to RTOs and the notice of proposed rulemaking regarding open access transmission service and standard electricity market design.
Retail Rate Filing
On December 5, 2003, Mississippi Power filed a request with the Mississippi PSC to reclassify 266 megawatts
76
of Plant Daniel Units 3 and 4 generating capacity not currently included in jurisdictional cost of service. As part of Mississippi Power’s proposal to include the additional Plant Daniel capacity in retail rates, the Mississippi PSC issued an interim accounting order in December 2003 directing Mississippi Power to expense and record in 2003 a regulatory liability in the amount of approximately $60 million while the Mississippi PSC fully considered the entire request. On May 25, 2004, the Mississippi PSC issued an order related to this matter. The Mississippi PSC approved Mississippi Power’s request to reclassify the 266 megawatts of Plant Daniel unit 3 and 4 capacity to jurisdictional cost of service effective January 1, 2004, and authorized Mississippi Power to include the related costs and revenue credits in jurisdictional rate base, cost of service and revenue requirement calculations for purposes of retail rate recovery. As directed by the Mississippi PSC, Mississippi Power will amortize the regulatory liability established pursuant to the Mississippi PSC’s interim order in December 2003 as an increase to earnings as follows: $16.5 million in 2004, $25.1 million in 2005, $13.0 million in 2006 and $5.7 million in 2007. The impact of the order on earnings for the period January 1, 2004 through June 30, 2004 is an increase of $7.3 million after tax and is reflected in the second quarter 2004 financial statements of Mississippi Power. See Note 3 to the financial statements of Mississippi Power under “Retail Regulatory Filing” in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein.
In addition, the Mississippi PSC also approved Mississippi Power’s requested changes to its PEP including the use of a forward-looking test year, with appropriate oversight; annual, rather than semi-annual, filings; and certain changes to the performance indicator mechanisms. Rate changes will be limited to 4% of retail revenues annually under the revised PEP. The Mississippi PSC will review all aspects of PEP in 2007.
Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Mississippi Power’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Mississippi Power cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from any such current proceedings would have a material adverse effect on Mississippi Power’s financial statements.
Mississippi Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS — ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Mississippi Power in Item 7 of the
77
Form 10-K for a complete discussion of Mississippi Power’s critical accounting policies and estimates related to Electric Utility Regulation, Contingent Obligations, Plant Daniel Capacity and Plant Daniel Operating Lease. Also see Note (K) to the Condensed Financial Statements herein for additional information related to Plant Daniel capacity.
On March 31, 2004, Mississippi Power prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. The adoption of FASB Interpretation No. 46R had no impact on Mississippi Power’s net income. However, as a result of the adoption, Mississippi Power deconsolidated certain wholly-owned trusts established to issue preferred securities since Mississippi Power does not meet the definition of primary beneficiary established by FASB Interpretation No. 46R. See Note (D) to the Condensed Financial Statements herein for additional information related to the adoption of FASB Interpretation No. 46R.
In May 2004, the FASB approved Staff Position (FSP) No. 106-2, “Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “Medicare Act”).” FSP No. 106-2 requires recognition of the impacts of the Medicare Act in the accumulated post-retirement benefit obligation and future cost of service for post-retirement medical plans and may be applied retroactively to the enactment of the Medicare Act in December 2003 or prospectively effective for the third quarter 2004. Mississippi Power has elected to apply this treatment prospectively. Pending the finalization of federal regulations governing the subsidy effected in the Medicare Act, Mississippi Power does not anticipate a material impact on its financial statements from the adoption of FSP No. 106-2.
Major changes in Mississippi Power’s financial condition during the first six months of 2004 included the addition of approximately $32 million to utility plant, a reduction in current liabilities of $93 million, an increase of $40 million in long-term debt and a decrease of $65 million in cash. See Mississippi Power’s Condensed Statements of Cash Flows and “Financing Activities” herein for further details.
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Mississippi Power in Item 7 in the Form 10-K for a description of Mississippi Power’s capital requirements for its construction program, lease obligations, purchase commitments and trust funding requirements.
In addition to the financing activities described herein, Mississippi Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past. The amount, type and timing of any financings — if needed — will depend upon maintenance of adequate earnings, regulatory approval, prevailing market conditions and other factors. See BUSINESS — “Financing Programs” in Item 1 of the Form 10-K for additional information.
78
To meet short-term cash needs and contingencies, Mississippi Power had at June 30, 2004, approximately $3.9 million of cash and cash equivalents and $100 million of unused committed credit arrangements with banks. Of these facilities, $35 million expire in 2004 and the remaining $65 million expire in 2005. Approximately $37.5 million of these credit arrangements contain provisions allowing two-year term loans executable at the expiration date. Mississippi Power expects to renew its credit facilities, as needed, prior to expiration. The credit arrangements provide liquidity support to Mississippi Power’s obligations with respect to variable rate pollution control bonds and commercial paper. Mississippi Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of Mississippi Power and other Southern Company subsidiaries. At June 30, 2004, Mississippi Power had $44.8 million in outstanding notes payable. Management believes that the need for working capital can be adequately met by utilizing lines of credit without maintaining large cash balances.
See MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Off-Balance Sheet Financing Arrangements” in Item 7 and Note 7 to the financial statements of Mississippi Power under “Operating Leases” in Item 8 of the Form 10-K for information related to Mississippi Power’s lease of a combined cycle generating facility at Plant Daniel.
Mississippi Power does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
Mississippi Power’s market risk exposures relative to interest rate changes have not changed materially compared with the December 31, 2003 reporting period. In addition, Mississippi Power is not aware of any facts or circumstances that would significantly affect such exposures in the near term.
Due to cost-based rate regulation, Mississippi Power has limited exposure to market volatility in interest rates, commodity fuel prices and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Mississippi Power enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market. Mississippi Power has also implemented retail fuel hedging programs at the instruction of the Mississippi PSC and wholesale fuel hedging programs under agreements with wholesale customers. The fair values of derivative, fuel and energy contracts at June 30, 2004 were as follows:
79
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS - FINANCIAL CONDITION AND LIQUIDITY – “Market Price Risk” of Mississippi Power in Item 7 and Notes 1 and 6 to the financial statements of Mississippi Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein.
In March 2004, Mississippi Power issued $40 million of Series F Floating Rate Senior Notes due March 9, 2009. The proceeds from this sale, along with other monies of Mississippi Power, were used to repay at maturity $80 million aggregate principal amount of Mississippi Power’s Series D Floating Rate Senior Notes due March 12, 2004.
In April 2004, Mississippi Power issued 1,200,000 Depositary Shares ($30 million aggregate stated capital) each representing one-fourth of a share of 5.25% Series Preferred Stock, cumulative, par value $100 per share. The proceeds from this sale were primarily used to redeem various issues of higher cost preferred stock and the remainder was used for general corporate purposes.
Mississippi Power plans to continue, when economically feasible, a program to retire higher-cost debt and replace these obligations with lower-cost capital if market conditions permit.
80
SAVANNAH ELECTRICANDPOWER COMPANY
81
SAVANNAH ELECTRIC AND POWER COMPANYCONDENSED STATEMENTS OF INCOME (UNAUDITED)
The accompanying notes as they relate to Savannah Electric are an integral part of these condensed financial statements.
82
SAVANNAH ELECTRIC AND POWER COMPANYCONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
83
SAVANNAH ELECTRIC AND POWER COMPANYCONDENSED BALANCE SHEETS (UNAUDITED)
84
85
SAVANNAH ELECTRIC AND POWER COMPANYMANAGEMENT’S DISCUSSION AND ANALYSIS OFRESULTS OF OPERATIONS AND FINANCIAL CONDITION
Savannah Electric’s net income for the second quarter and year-to-date 2004 was $7.3 million and $10.5 million, respectively, compared to $6.3 million and $9.8 million, respectively, for the corresponding periods of 2003. Earnings increased by $1.1 million, or 16.7%, in the second quarter 2004 primarily due to higher operating revenues and other income, net, partially offset by higher operating expenses. Year-to-date 2004 earnings were up by $0.7 million, or 7.1%, as a result of higher operating revenues, also partially offset by higher operating expenses.
Retail sales. Excluding fuel revenues, which do not affect net income, retail sales revenue increased by $4.5 million, or 10.2%, in the second quarter 2004 and increased by $6.5 million, or 7.9%, year-to-date 2004 when compared to the corresponding periods in 2003. The second quarter 2004 increase in retail sales revenue is mainly attributed to an 11.7% increase in retail kilowatt-hour energy sales. Energy sales to residential and commercial customers were higher by 12.0% and 12.5%, respectively, mainly due to more favorable weather conditions and growth in the number of customers when compared to the same period in 2003. Energy sales to industrial customers increased by 9.3% in the second quarter 2004 compared to the second quarter 2003 primarily due to increased usage by several industrial customers as a result of the improving economy. The year-to-date 2004 increase in retail revenues is primarily a result of more favorable weather conditions and growth in the number of customers. Year-to-date 2004, energy sales to residential and commercial customers were higher by 14.1% and 7.4%, respectively. Energy sales to industrial customers year-to-date 2004 were down 4.4% when compared to the prior year mainly due to the installation of a cogeneration facility by one customer in late 2003.
Sales for resale — affiliates. Revenues from sales for resale to affiliated companies within the Southern Company system will vary depending on demand and the availability and cost of generating resources at each company. Sales for resale to affiliates increased in the second quarter and year-to-date 2004 primarily due to an increase in demand. These transactions do not have a significant impact on net income.
86
Fuel expense. Fuel expense increased in the second quarter and year-to-date 2004 primarily as a result of increased generation to meet demand for energy and increases in the price of fuel. Generation increased 4.8% for second quarter and 3.2% for year-to-date 2004 when compared to the prior year. Fuel costs increased 7.1% for second quarter 2004. Since fuel expenses are generally offset by fuel revenues through Savannah Electric’s fuel cost recovery clause, these expenses do not have a significant impact on net income. See “Future Earnings Potential — FERC and Georgia PSC Matters — Fuel Cost Recovery Rate Filings” and Note (L) to the Condensed Financial Statements herein for additional information.
Purchased power — non-affiliates. In the second quarter and year-to-date 2004, the increases in purchased power from non-affiliates are primarily due to higher demand and the opportunity to purchase this energy at a cost lower than self-generation or available from affiliates. These transactions do not have a significant impact on earnings, as energy costs are generally recovered through Savannah Electric’s fuel cost recovery clause.
Purchased power — affiliates. Purchased power from affiliates increased in the second quarter and year-to-date 2004 as compared to the same periods in the prior year primarily due to the availability of system generation at prices below self generation to meet increased sales demand and also as the result of an accounting order approved by the Georgia PSC in December 2002 which allows Savannah Electric to write-down a portion of the approximately $3.8 million annual deferral in Plant Wansley purchased power costs. See Note 3 to the financial statements of Savannah Electric under “Retail Regulatory Matters” in Item 8 of the Form 10-K for additional information. The net impact of these transactions compared to the prior year was a $0.6 million increase to expense for the second quarter and a $0.9 million increase year-to-date. Purchased power from affiliates also includes energy purchases which will vary depending on demand and cost of generation resources at each company and higher energy costs. These energy costs are recovered through the fuel cost recovery clause and have no significant impact on earnings.
Other operations expense. The increases for the second quarter and year-to-date 2004 as compared to the same periods in the prior year in other operations expense are attributed to an increase in administrative and general expenses primarily relating to accounting and auditing services, legal and employee benefit expenses.
Maintenance expense. The increases in the second quarter and year-to-date 2004 as compared to the same periods in the prior year are mainly due to an unscheduled coal mill repair at Plant Kraft.
Interest expense, net of amounts capitalized. The second quarter and year-to-date 2004 increases in this expense as compared to the same period in the prior year are mainly due to an increase in long term debt outstanding. These increases were more than offset by decreases in distributions on mandatorily redeemable preferred securities. These preferred securities were redeemed in January 2004 with proceeds from the issuance of senior notes in late 2003.
The results of operations discussed above are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors including Savannah Electric’s ability to maintain a stable regulatory environment, to achieve energy sales growth while containing costs and to recover costs related to growing demand and increasingly stricter environmental standards. Growth in energy sales is subject to a number of factors, which include weather, competition, new energy contracts with neighboring utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand and the rate of economic growth in the service area. For additional information relating to these issues, see BUSINESS — The
87
SOUTHERN System — “Risk Factors” in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential” of Savannah Electric in Item 7 of the Form 10-K.
Compliance costs related to the Clean Air Act and other environmental regulations could affect earnings if such costs cannot be recovered. See MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential — Environmental Matters” of Savannah Electric in Item 7 and Note 3 to the financial statements of Savannah Electric under “New Source Review Actions” in Item 8 of the Form 10-K. As of March 15, 2004, civil penalties under the Clean Air Act were increased prospectively to a maximum of $32,500 per day, per violation. To the extent alleged violations under either the New Source Review litigation or Plant Wansley environmental litigation are deemed to be continuing, this increased civil penalty amount could apply to such violations found to continue after that date. On May 3, 2004, the U.S. Supreme Court denied the EPA’s petition to review the Eleventh Circuit Court of Appeals’ decision in the EPA’s similar New Source Review enforcement action against the TVA. The case against Savannah Electric has been effectively stayed pending final resolution of the TVA case. With the denial of the EPA’s petition for review, the Court of Appeals’ decision became final. At this time, no party to the case against Savannah Electric has sought to reopen that case, which remains administratively closed in the District Court for the Northern District of Georgia. An adverse outcome in this case could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.
On April 21, 2004, the EPA published the final regional nitrogen oxide reduction rules applicable to the State of Georgia. These rules specify that Georgia must submit a revised state implementation plan by April 2005, and affected sources must comply with the reduction requirements by May 1, 2007. The impact of these regulations will depend on the development and approval of Georgia’s state implementation plan and cannot be determined at this time.
88
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS — “Future Earnings Potential — FERC Matters — Market-Based Rate Authority” in Item 7 and Note 3 to the financial statements of Savannah Electric under “FERC Matters” in Item 8 of the Form 10-K. On April 14, 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach includes a pivotal supplier analysis and a wholesale market share analysis, the results of which provide a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power. Southern Company, the retail operating companies, including Savannah Electric, and Southern Power believe that it may be difficult for a traditional utility company, or an affiliate thereof, with a significant load service obligation and generation to satisfy that obligation, and that is not a member of a large, FERC-approved RTO, to pass all aspects of the market power screens as currently designed. However, each of the companies believes that it has an appropriate basis to rebut the generation market power presumption.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS — “Future Earnings Potential — FERC Matters — Transmission” of Savannah Electric in Item 7 of the Form 10-K for information on the FERC’s order related to RTOs and the FERC’s notice of proposed rulemaking regarding open access transmission service and standard electricity market design.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS — “Future Earnings Potential — FERC Matters — Southern Power PPAs” of Savannah Electric in Item 7 and Note 3 to the financial statements of Savannah Electric under “FERC Matters” in Item 8 of the Form 10-K for information regarding PPAs between Southern Power and Savannah Electric and Georgia Power for Plant McIntosh capacity. In April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund and ordered that hearings be held. To ensure the timely completion of construction on McIntosh units 10 and 11 and their availability in the summer of 2005 as supply side resources for the retail customers in the State of Georgia, on May 7, 2004, Savannah Electric and Georgia Power requested the Georgia PSC to direct them to acquire the McIntosh construction project. Savannah Electric and Georgia Power proposed to place the units in rate base at a cost approved by the Georgia PSC and to recover the unit operation and maintenance costs as retail service expenses as may be approved by the Georgia PSC. The Georgia PSC issued such an order on May 18, 2004 and the transfer
89
occurred on May 24, 2004. On May 20, 2004, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. On August 4, 2004, the FERC issued a notice that it allowed the request to withdraw the PPAs to be accepted and to become effective by operation of law on July 20, 2004. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. The ultimate outcome of this matter cannot now be determined.
The May 18, 2004 Georgia PSC order also directed Georgia Power and Savannah Electric to file an application within 10 days of completing such purchase to amend the resource certificate granted by the Georgia PSC in 2002 to describe the capacity resource as being the McIntosh units 10 and 11 (as opposed to the McIntosh PPAs), the approximate construction schedule (which is not expected to change) and the proposed rate base treatment. The application was filed on June 3, 2004 and the Georgia PSC will have 180 days to respond. The Georgia PSC is expected to review the application in accordance with its affiliate transaction guidelines, which require a lower of cost or market approach unless otherwise determined by the Georgia PSC. Georgia Power and Savannah Electric have submitted information showing that the book cost of the McIntosh construction project is lower than its market value. However, full recovery of the project costs depends on the outcome of the Georgia PSC’s review. In the event the Georgia PSC does not allow full recovery of the project costs, then part of such costs may have to be written off in accordance with FASB Statement No. 90, “Accounting for Abandonments and Disallowed Plant Costs.” At June 30, 2004, the investment in the McIntosh construction project totaled approximately $69.7 million for Savannah Electric. The ultimate outcome of the Georgia PSC’s review cannot now be determined.
Fuel Cost Recovery Rate Filings
On March 23, 2004, Savannah Electric submitted a request to the Georgia PSC for an accounting order which, if approved by the Georgia PSC, would have allowed for the cost of a coal transloader then under construction to be amortized over twenty-four months through fuel expense and recovered through Savannah Electric’s fuel cost recovery clause. The transloader allows foreign coal to be off-loaded from ships at Savannah Electric’s Plant Kraft dock, and then transferred by rail to Plant McIntosh. On June 24, 2004, the Georgia PSC denied Savannah Electric’s request for this accounting order. Consequently, accumulated project costs of $2.7 million were recorded as construction work in progress in June 2004 and will be depreciated over the project’s estimated useful life of 35 years once placed in service.
On July 30, 2004, Savannah Electric filed for a fuel cost recovery rate increase with the Georgia PSC. The increase will allow for the recovery of fuel costs based on an estimate of future costs, as well as the collection of the existing under recovery of fuel expenses, over a two-year period. The amount under recovered at June 30, 2004 is approximately $8.9 million and is included in Savannah Electric’s Condensed Balance Sheets herein. The Georgia PSC is expected to rule on this matter by late October 2004. The outcome of the filing cannot be determined at this time.
Savannah Electric anticipates filing a base rate case in late 2004.
Savannah Electric is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Savannah Electric’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged
90
exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Savannah Electric cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Savannah Electric’s financial statements.
Savannah Electric prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Savannah Electric in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Savannah Electric’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS — ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Savannah Electric in Item 7 of the Form 10-K for a complete discussion of Savannah Electric’s critical accounting policies and estimates related to Electric Utility Regulation and Contingent Obligations.
On March 31, 2004, Savannah Electric prospectively adopted FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” which requires the primary beneficiary of a variable interest entity to consolidate the related assets and liabilities. See Note 6 to the financial statements of Savannah Electric under “Mandatorily Redeemable Preferred Securities” in Item 8 of the Form 10-K regarding Savannah Electric’s redemption of all outstanding preferred securities in January 2004 and the dissolution of the issuing trust. Therefore, the adoption of Interpretation No. 46R had no impact on Savannah Electric’s financial statements.
In May 2004, the FASB approved Staff Position (FSP) No. 106-2, “Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “Medicare Act”).” FSP No. 106-2 requires recognition of the impacts of the Medicare Act in the accumulated post-retirement benefit obligation and future cost of service for post-retirement medical plans and may be applied retroactively to the enactment of the Medicare Act in December 2003 or prospectively effective for the third quarter 2004. Savannah Electric has elected to apply this treatment prospectively. Pending the finalization of federal regulations governing the subsidy effected in the Medicare Act, Savannah Electric does not anticipate a material impact on its financial statements from the adoption of FSP No. 106-2.
Major changes in Savannah Electric’s financial condition during the first six months of 2004 included the addition of approximately $95.9 million to utility plant, which include the Plant McIntosh combined cycle construction project. See Note (J) to the Condensed Financial Statements herein for additional information. The funds for these additions and other capital requirements were derived primarily from operating activities, issuance of securities, capital contributions from Southern Company and short-term debt. See Savannah Electric’s Condensed Statements of Cash Flows herein for further details.
91
Reference is made to MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Capital Requirements and Contractual Obligations” of Savannah Electric in Item 7 of the Form 10-K for a description of Savannah Electric’s capital requirements for its construction program, lease obligations, purchase commitments and trust funding requirements. The projected construction program will increase by $83.1 million and $7.6 million in 2004 and 2005, respectively, for the Plant McIntosh combined cycle construction project and the projected purchased power commitments will decrease by $25.3 million in 2005-2006, $28.2 million in 2007-2008 and $158.0 million beyond 2008 as a result of the purchase of the construction project.
Savannah Electric plans to obtain the funds required for construction and other purposes from sources similar to those used in the past including both internal and external funds. The amount, type and timing of any future financings — if needed — will depend upon market conditions and regulatory approval. See BUSINESS — “Financing Programs” in Item 1 of the Form 10-K for additional information.
To meet short-term cash needs and contingencies, Savannah Electric had at June 30, 2004 approximately $2.4 million of cash and cash equivalents and $50 million of unused committed credit arrangements with banks, of which $31 million expires in 2004, $9 million expires in 2005 and $10 million expires in 2007. Of the unused credit arrangements expiring in 2004 and 2005, $40 million include two year term loan options executable at the expiration date. The credit arrangements provide liquidity support to some of Savannah Electric’s obligations with respect to its variable rate debt and its commercial paper. Savannah Electric expects to renew its credit facilities, as needed, prior to expiration. Savannah Electric may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper and extendible commercial notes at the request and for the benefit of Savannah Electric and other Southern Company subsidiaries. At June 30, 2004, Savannah Electric had $10.7 million of commercial paper and $6.9 million of extendible commercial notes outstanding. Management believes that the need for working capital can be adequately met by utilizing lines of credit and access to the financial markets.
Savannah Electric does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
Savannah Electric’s market risk exposures relative to interest rate changes have not changed materially compared with the December 31, 2003 reporting period. In addition, Savannah Electric is not aware of any facts or circumstances that would significantly affect such exposures in the near term.
92
Due to cost-based rate regulations, Savannah Electric has limited exposure to market volatility in interest rates, commodity fuel prices and prices of electricity. To mitigate residual risks relative to movements in electricity prices, Savannah Electric enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, similar contracts for gas and oil purchases. Savannah Electric has also implemented a retail fuel hedging program at the instruction of the Georgia PSC. The fair value of derivative energy contracts at June 30, 2004 was as follows:
For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” of Savannah Electric in Item 7 and Notes 1 and 6 to the financial statements of Savannah Electric under “Financial Instruments” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein.
Savannah Electric received contributions to capital from Southern in May 2004 in the amount of $31 million to help finance the purchase of the Plant McIntosh construction project. See Note (J) to the Condensed Financial Statements herein for additional information.
In June 2004, Savannah Electric issued 1,800,000 shares ($45 million aggregate par value) of 6.00% Series Preferred Stock, Non-Cumulative, Par Value $25 Per Share. The proceeds from this sale were used to repay a portion of its outstanding short-term indebtedness that had been incurred primarily to finance the purchase of the Plant McIntosh construction project.
Savannah Electric plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
93
SOUTHERN POWER COMPANY
94
SOUTHERN POWER COMPANYCONDENSED STATEMENTS OF INCOME (UNAUDITED)
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.
95
SOUTHERN POWER COMPANYCONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
96
SOUTHERN POWER COMPANYCONDENSED BALANCE SHEETS (UNAUDITED)
97
98
SOUTHERN POWER COMPANYMANAGEMENT’S DISCUSSION AND ANALYSIS OFRESULTS OF OPERATIONS AND FINANCIAL CONDITION
Southern Power’s net income for the second quarter and year-to-date 2004 was $22.4 million and $49.6 million, respectively, compared to $79.3 million and $102.4 million for the corresponding periods of 2003. The decreases in second quarter 2004 earnings of $56.9 million, or 71.7%, and $52.8 million, or 51.6%, year-to-date 2004 are primarily attributed to a one-time gain of $50 million recognized in May 2003 upon termination of PPAs with Dynegy, as well as a reduction in the earnings from sales of uncontracted capacity as new PPAs have become effective. PPAs with Alabama Power and Georgia Power for Plants Harris Unit 1 and Franklin Unit 2 that began in June 2003, and with the Stanton joint owners for Stanton Unit A that began in October 2003, increased both affiliated and non-affiliated revenues, while significantly reducing uncontracted capacity. A new PPA with Georgia Power for Plant Harris Unit 2 began in June 2004 and further reduced uncontracted capacity. The previously uncontracted capacity that was available to the market from June 2003 through May 2004 consisted of approximately 800 MWs; 600 MWs from Plant Harris Unit 2 and 200 MW from Plant Franklin Unit 2.
Sales for resale — non-affiliates. In the second quarter and year-to-date 2004, revenues from sales for resale to non-affiliates were higher when compared to the corresponding periods in 2003. These increases were primarily due to additional wholesale capacity and energy sales to non-affiliates as a result of commercial operation of Plant Harris Unit 2 in June 2003 and Plant Stanton A in October 2003.
Sales for resale — affiliates. During the second quarter and year-to-date 2004, sales for resale to affiliates increased primarily due to energy and capacity sales through PPAs with Alabama Power and Georgia Power that commenced in June 2003. A new PPA with Georgia Power for Plant Harris Unit 2 that began in June 2004 also contributed to the increases. Revenues from sales to affiliated companies through the Southern Company system power pool and energy sales under PPAs will vary depending on demand and the availability and cost of generating resources accessible throughout the Southern Company system.
99
Fuel expense. Fuel expense for the second quarter and year-to-date 2004 increased significantly when compared to the same periods in 2003. The second quarter 2004 increase resulted primarily from commercial operation of Plant Harris Unit 2, and natural gas prices that averaged 14% higher than in the same period of 2003. For year-to-date 2004, the increase over the same period in 2003 was 6%. Southern Power’s existing PPAs generally provide that the purchasers are responsible for substantially all of the cost of fuel relating to the energy delivered under such PPAs; therefore, these cost increases do not have a significant impact on net income.
Purchased power — non-affiliates. The increases in purchased power from non-affiliates during the second quarter and year-to-date 2004 when compared to the same periods in 2003 are primarily due to higher purchase volumes and pricing related to day-ahead peak-hour purchases in 2004. These purchases minimize daily cycling of Southern Power’s generating units or the need to operate those units during off-peak hours when cheaper energy is available from affiliates. These purchases reduce overall costs when long-term maintenance of the units is considered.
Purchased power — affiliates. The decrease in purchased power from affiliates during the second quarter 2004 compared to the same period in the prior year is due to the availability of power at prices lower than from affiliates. The availability of power at prices lower than Southern Power’s self-generation, which is primarily natural gas-fired, accounted for the year-to-date 2004 increase in purchased power from affiliates when compared to the same period in the prior year. Expenses from purchased power transactions will vary depending on demand, availability and the cost of generating resources accessible throughout the Southern Company system.
Other operations expense. During the second quarter and year-to-date 2004, other operations expense increased when compared to the same periods in the prior year due mainly to expenses associated with the commercial operation of Plant Franklin Unit 2 and Plant Harris Units 1 and 2, which were all placed into commercial operation in June 2003, and Plant Stanton A, which was placed into commercial operation in October 2003.
Depreciation and amortization. New generating units placed into service in June and October 2003 are the main drivers for the increases in depreciation and amortization in the second quarter and year-to-date 2004 as compared to the corresponding periods in the prior year.
Interest expense, net of amounts capitalized. In the second quarter and year-to-date 2004, interest expense, net of amounts capitalized increased when compared to the same periods in 2003 due to an increase in the amount of senior notes outstanding and a lower percentage of interest costs being capitalized as projects have reached completion. In addition, see Note (J) to the Condensed Financial Statements herein for information regarding the transfer of the Plant McIntosh Unit 10 and 11 construction project to Georgia Power and Savannah Electric on May 24, 2004.
Income taxes. The decreases in income taxes for the second quarter and year-to-date 2004 correspond to the decrease in pre-tax earnings due to the Dynegy settlement recorded in the second quarter of 2003. There were no audit adjustments or settlements related to income taxes through June 30, 2004.
The results of operations are not necessarily indicative of future earnings. The level of future earnings depends on numerous factors including completion of construction on new generating facilities, regulatory matters including those related to affiliate contracts, energy sales, creditworthiness of customers, total generating
100
capacity available in the Super Southeast and the remarketing of capacity. Another major factor is federal regulatory policy, which may impact Southern Power’s level of participation in the wholesale energy market. For additional information relating to these issues, see Business – The SOUTHERN System – “Risk Factors” in Item 1 and MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Future Earnings Potential” of Southern Power in Item 7 of the Form 10-K.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – “Future Earnings Potential – FERC Matters – Market-Based Rate Authority” of Southern Power in Item 7 and Note 3 to the financial statements of Southern Power under “FERC Matters” in Item 8 of the Form 10-K. On April 14, 2004, the FERC issued an order that abandoned the SMA test and adopted a new interim analysis for measuring generation market power. This new interim approach includes a pivotal supplier analysis and a wholesale market share analysis, the results of which provide a rebuttable presumption regarding generation market power. The FERC’s order also sets forth procedures for rebutting these presumptions and addresses mitigation measures for those entities that are found to have market power. In the absence of specific mitigation measures, the order includes several cost-based mitigation measures that would apply by default. The FERC also initiated a new rulemaking proceeding that, among other things, will adopt a final methodology for assessing generation market power. Southern Company, the retail operating companies and Southern Power believe that it may be difficult for a traditional utility company, or an affiliate thereof, with a significant load service obligation and generation to satisfy that obligation, and that is not a member of a large, FERC-approved RTO, to pass all aspects of the market power screens as currently designed. However, each of the companies believes that it has an appropriate basis to rebut the generation market power presumption.
See Note 3 to the financial statements of Southern Power under “FERC Matters” in Item 8 of the Form 10-K for information regarding PPAs between Southern Power and Georgia Power and Savannah Electric for Plant McIntosh Units 10 and 11 capacity. In April 2003, Southern Power applied for FERC approval of these PPAs. In July 2003, the FERC accepted the PPAs to become effective June 1, 2005, subject to refund, and ordered that hearings be held. To ensure the timely completion of construction on McIntosh units 10 and 11 and their availability in the summer of 2005 as supply side resources for the retail customers in the State of Georgia, on May 7, 2004, Savannah Electric and Georgia Power requested the Georgia PSC to direct them to acquire the McIntosh construction project. Savannah Electric and Georgia Power proposed to place the units in rate base at a cost approved by the Georgia PSC and to recover the unit operation and maintenance costs as retail service expenses as may be approved by the Georgia PSC. The Georgia PSC issued such an order on May 18, 2004 and the transfer occurred on May 24, 2004. On May 20, 2004, Southern Power filed a request to withdraw the PPAs and to terminate the ongoing FERC proceedings. On August 4, 2004, the FERC issued a notice that it allowed the request to withdraw the PPAs to be accepted and to become effective by operation of law on July 20, 2004. However, the FERC made no determination on what additional steps may need to be taken with respect to testimony provided in the proceedings. The ultimate outcome of this matter cannot now be determined.
101
See MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential — FERC Matters” of Southern Company in Item 7 the Form 10-K for information on the FERC’s order related to RTOs and the FERC’s notice of proposed rulemaking regarding open access transmission service and standard electricity market design.
See MANAGEMENT’S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS — “Future Earnings Potential — General” and“— Power Sales Agreements” of Southern Power in Item 7 of the Form 10-K for additional information on long-term power sales agreements and PPAs. Southern Power’s PPAs with non-affiliated counterparties have provisions that require the posting of collateral or an acceptable substitute guarantee in the event that S&P or Moody’s downgrades the credit ratings of such counterparty to below-investment grade, or, if the counterparty is not rated, fails to maintain a minimum coverage ratio. The PPAs are expected to provide Southern Power with a stable source of revenue during their respective terms.
In June 2003, Southern Power placed Plant Franklin Unit 2 and Plant Harris Units 1 and 2 into commercial operation. In October 2003, Southern Power placed Plant Stanton A into commercial operation. In June 2004, sales under the PPA with Georgia Power for the remaining 200 MW of uncontracted capacity at Plant Franklin Unit 2 began. Also, in June 2004, sales under the PPA with Georgia Power for Plant Harris Unit 2 began. Sales under PPAs for the other units became effective upon commercial operation. The opportunity for non-affiliate sales from uncontracted capacity has declined significantly since these PPAs became effective.
Southern Power is also completing limited construction activities on Plant Franklin Unit 3 to preserve the long-term viability of the project but has deferred final completion until the 2008-2011 period. See Note 3 to the financial statements of Southern Power under “Uncontracted Generating Capacity” in Item 8 of the Form 10-K for additional information. The final outcome of these matters cannot now be determined.
Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. In addition, Southern Power’s business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury and citizen enforcement of environmental requirements, has increased generally throughout the United States. In particular, personal injury claims for damages caused by alleged exposure to hazardous materials have become more frequent. The ultimate outcome of such litigation against Southern Power cannot be predicted at this time; however, management does not anticipate that the liabilities, if any, arising from such current proceedings would have a material adverse effect on Southern Power’s financial statements.
See also the Notes to the Condensed Financial Statements herein for discussion of various contingencies and other matters which may affect future earnings potential.
See MANAGEMENT’S DISCUSSION AND ANALYSIS — RESULTS OF OPERATIONS — “Future Earnings Potential — Environmental Matters” of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emission of air pollution from industrial sources, including electric generating facilities. Compliance costs related to current and future environmental laws and regulations could affect earnings if such costs are not fully recovered.
102
Southern Power prepares its financial statements in accordance with accounting principles generally accepted in the United States. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power’s results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT’S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – “Application of Critical Accounting Policies and Estimates” of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power’s critical accounting policies and estimates related to Revenue Recognition and Asset Impairments.
The major change in Southern Power’s financial condition during the first six months of 2004 was the sale of the Plant McIntosh Units 10 and 11 combined cycle construction project to Georgia Power and Savannah Electric on May 24, 2004 at book cost of $429 million. See Note (J) to the Condensed Financial Statements herein for additional information. As a result of the sale, Southern Power repaid its note payable to Southern Company of $89 million, declared dividends of $225 million to Southern Company ($113 million from capital surplus and $112 million from retained earnings) and repaid $114 million in commercial paper borrowings. In September 2003, the SEC had approved, under the PUHCA, Southern Power’s payment of dividends in an amount up to $190 million to Southern Company from capital surplus.
Reference is made to MANAGEMENT’S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – “Capital Requirements and Contractual Obligations” of Southern Power in Item 7 of the Form 10-K for a description of Southern Power’s capital requirements for its construction program, maturing debt, purchase commitments and long-term service agreements. The sale of the Plant McIntosh Units 10 and 11 construction project and the suspension of construction activities at Plant Franklin Unit 3 will significantly reduce short-term borrowings under the commercial paper program.
In February 2003, Southern Power initiated a commercial paper program to fund a portion of the construction costs of new generating facilities. The amount of commercial paper initially represented approximately 45% of total debt, but proceeds from the sale of the Plant McIntosh Units 10 and 11 construction project were used to repay $24 million of outstanding commercial paper early in the third quarter of 2004. Southern Power’s strategy has been to refinance most of such short-term borrowings with long-term securities following commercial operation of the generating facilities. See Note 6 to the financial statements of Southern Power under “Commercial Paper” in Item 8 of the Form 10-K for additional information.
To meet liquidity and capital resource requirements, Southern Power had at June 30, 2004 approximately $650 million of an unused committed credit arrangement with banks expiring in 2006. This arrangement also provides liquidity support for Southern Power’s commercial paper program. Amounts drawn under the arrangements may be used to finance acquisition and construction costs related to gas-fired electric generating
103
facilities and for general corporate purposes, subject to borrowing limitations for each generating facility. The arrangements permit Southern Power to fund construction of future generating facilities upon meeting certain requirements. Southern Power expects to renew its credit facility, as needed, prior to expiration.
Southern Power does not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are contracts that could require collateral — but not accelerated payment — in the event of a credit rating change to below investment grade. These contracts are primarily for physical electricity purchases and sales, fixed-price physical gas purchases and agreements covering interest rate swaps. Generally, collateral may be provided by a Southern Company guaranty, letter of credit or cash. At June 30, 2004, the maximum potential collateral requirements were approximately $177 million.
Southern Power’s market risk exposures relative to interest rate changes have not changed materially compared with the December 31, 2003 reporting period. In addition, Southern Power is not aware of any facts or circumstances that would significantly affect such exposures in the near term.
Because energy from Southern Power’s generating facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the purchasers, Southern Power’s exposure to market volatility in commodity fuel prices and prices of electricity is limited. To mitigate residual risks in those areas, Southern Power enters into fixed-price contracts for the sale of electricity. Unrealized gains and losses on electric and gas contracts qualifying as cash flow hedges of anticipated purchases and sales are deferred in Other Comprehensive Income. The fair values of derivative energy contracts at June 30, 2004 were as follows:
At June 30, 2004, all of these contracts mature within one year and are based on actively quoted market prices. For additional information, see MANAGEMENT’S DISCUSSION AND ANALYSIS — FINANCIAL CONDITION AND LIQUIDITY — “Market Price Risk” of Southern Power in Item 7 and Notes 1 and 6 to the financial statements of Southern Power under “Financial Instruments” in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein.
104
NOTES TO THE CONDENSED FINANCIAL STATEMENTSFORTHE SOUTHERN COMPANY AND SUBSIDIARY COMPANIESALABAMA POWER COMPANYGEORGIA POWER COMPANYGULF POWER COMPANYMISSISSIPPI POWER COMPANYSAVANNAH ELECTRIC AND POWER COMPANYSOUTHERN POWER COMPANY
INDEX TO APPLICABLE NOTES TOFINANCIAL STATEMENTS BY REGISTRANT
105
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIESALABAMA POWER COMPANYGEORGIA POWER COMPANYGULF POWER COMPANYMISSISSIPPI POWER COMPANYSAVANNAH ELECTRIC AND POWER COMPANYSOUTHERN POWER COMPANY
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
106
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
107
108
109
110
111
112
113
114
115
116
117
PART II — OTHER INFORMATION
118
119
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
120
121
122
123
124
(b) Reports on Form 8-K.
125
(b) Reports on Form 8-K. (continued)
126
THE SOUTHERN COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Date: August 5, 2004
127
128
129
130
131
SAVANNAH ELECTRIC AND POWER COMPANY
132
133