-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, QdPhtIHYEfCFnS1lCJnWnUsSXS8qT9u/MXluTGqWbW2lbf93PwaW0unSD4oSg1q2 MzsDDMQp+Ij0tROjXU9nsg== 0000940180-01-500585.txt : 20020410 0000940180-01-500585.hdr.sgml : 20020410 ACCESSION NUMBER: 0000940180-01-500585 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 20010930 FILED AS OF DATE: 20011113 FILER: COMPANY DATA: COMPANY CONFORMED NAME: EMPIRE DISTRICT ELECTRIC CO CENTRAL INDEX KEY: 0000032689 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 440236370 STATE OF INCORPORATION: KS FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-03368 FILM NUMBER: 1783050 BUSINESS ADDRESS: STREET 1: 602 JOPLIN ST CITY: JOPLIN STATE: MO ZIP: 64801 BUSINESS PHONE: 4176255100 MAIL ADDRESS: STREET 1: P.O. BOX 127 CITY: JOPLIN STATE: MO ZIP: 64802 10-Q 1 d10q.txt FORM 10-Q ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ----------------- FORM 10-Q ----------------- (Mark One) [X] Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended September 30, 2001 or ------------------ [_] Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from to . -------------- -------------- Commission file number: 1-3368 THE EMPIRE DISTRICT ELECTRIC COMPANY (Exact name of registrant as specified in its charter) Kansas 44-0236370 (State of Incorporation) (I.R.S. Employer Identification No.) 602 Joplin Street, Joplin, Missouri 64801 (Address of principal executive offices) (zip code) Registrant's telephone number: (417) 625-5100 Indicate by check mark whether the registrant (1) has 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Common stock outstanding as of November 1, 2001: 17,717,321 shares. ================================================================================ THE EMPIRE DISTRICT ELECTRIC COMPANY INDEX Page Number ------ Part I - Financial Information: Item 1. Consolidated Financial Statements: a. Consolidated Statement of Income .......................... 3 b. Consolidated Statement of Comprehensive Income ............ 6 c. Consolidated Statement of Common Stockholders' Equity ..... 6 d. Consolidated Balance Sheet ................................ 7 e. Consolidated Statement of Cash Flows ...................... 8 f. Notes to Consolidated Financial Statements ................ 9 Forward Looking Statements ..................................... 11 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations ...................................... 12 Results of Operations .......................................... 12 Liquidity and Capital Resources ................................ 18 Item 3. Quantitative and Qualitative Disclosures About Market Risk ..... 20 Part II - Other Information: Item 1. Legal Proceedings - (none) Item 2. Changes in Securities and Use of Proceeds - (none) Item 3. Defaults Upon Senior Securities - (none) Item 4. Submission of Matters to a vote of Security Holders - (none) Item 5. Other Information .............................................. 20 Item 6. Exhibits and Reports on Form 8-K ............................... 20 Signatures ............................................................... 22 2 PART I. FINANCIAL INFORMATION Item 1. Consolidated Financial Statements EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
Three Months Ended September 30, --------------------------------------- 2001 2000 ------------------- ------------------ Operating revenues: Electric $ 83,045,693 $ 85,925,995 Water 293,601 297,129 ------------------ ------------------ 83,339,294 86,223,124 Operating revenue deductions: Operating expenses: Fuel 22,280,914 18,426,824 Purchased power 12,807,364 16,403,004 Other 9,129,616 9,041,204 Merger related Expenses 39,842 78,990 ------------------ ------------------ Total operating expenses 44,257,736 43,950,022 Maintenance and repairs 4,348,149 3,211,084 Depreciation and amortization 8,256,000 6,982,089 Provision for income taxes 4,061,360 8,443,621 Other taxes 3,980,991 3,964,316 ------------------ ------------------ 64,904,236 66,551,132 ------------------ ------------------ Operating income 18,435,058 19,671,992 Other income and deductions: Allowance for equity funds used during construction 9,773 662,015 Interest income 41,804 154,379 Loss on SLCC plant disallowance (4,087,066) - Provision for other income taxes 1,517,852 - Other - net (308,775) 94,554 ------------------- ------------------ (2,826,412) 910,948 ------------------- ------------------ Income before interest charges 15,608,646 20,582,940 Interest charges: Long-term debt: Trust preferred distributions by subsidiary holding solely parent debentures 1,062,500 - Other 6,595,127 6,589,021 Commercial paper 505,064 471,741 Allowance for borrowed funds used during construction (148,418) (913,290) Other 235,666 103,185 ------------------ ------------------ 8,249,939 6,250,657 ------------------ ------------------ Net income applicable to common stock $ 7,358,707 $ 14,332,283 ================== ================== Weighted average number of common shares outstanding 17,680,831 17,555,023 ================== ================== Basic and diluted earnings per weighted average share of common stock $ 0.42 $ 0.82 ========= ========= Dividends per share of common stock $ 0.32 $ 0.32 ========= =========
See accompanying Notes to Financial Statements. 3 EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
Nine Months Ended September 30, --------------------------------------- 2001 2000 ------------------- ------------------ Operating revenues: Electric $ 201,473,759 $ 196,879,596 Water 820,758 801,613 ------------------ ------------------ 202,294,517 197,681,209 Operating revenue deductions: Operating expenses: Fuel 43,870,568 37,253,589 Purchased power 48,604,371 45,292,144 Other 27,115,813 24,712,378 Merger related Expenses 1,276,596 200,854 ------------------ ------------------ Total operating expenses 120,867,348 107,458,965 Maintenance and repairs 11,788,518 10,996,284 Depreciation and amortization 22,694,736 20,713,685 Provision for income taxes 4,260,826 11,032,635 Merger-related income tax benefit (2,323,982) - Other taxes 10,676,776 10,431,099 ------------------ ------------------ 167,964,222 160,632,668 ------------------ ------------------ Operating income 34,330,295 37,048,541 Other income and deductions: Allowance for equity funds used during construction 475,630 1,494,721 Interest income 176,797 516,991 Loss on SLCC plant disallowance (4,087,066) - Provision for other income taxes 1,516,186 - Other - net (817,671) (158,691) ------------------ ------------------ (2,736,124) 1,853,021 ------------------ ------------------ Income before interest charges 31,594,171 38,901,562 Interest charges: Long-term debt: Trust preferred distributions by subsidiary holding solely parent debentures 2,479,167 - Other 19,787,411 19,769,258 Commercial paper 1,979,315 572,196 Allowance for borrowed funds used during construction (3,551,464) (2,062,052) Other 592,974 335,135 ------------------ ------------------ 21,287,403 18,614,537 ------------------ ------------------ Net income applicable to common stock $ 10,306,768 $ 20,287,025 ================== ================== Weighted average number of common shares outstanding 17,641,314 17,472,691 ================== ================== Basic and diluted earnings per weighted average share of common stock $ 0.58 $ 1.16 ========= ========= Dividends per share of common stock $ 0.96 $ 0.96 ========= =========
See accompanying Notes to Financial Statements. 4 EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
Twelve Months Ended September 30, --------------------------------------- 2001 2000 ------------------- ------------------ Operating revenues: Electric $ 263,531,492 $ 249,260,598 Water 1,085,274 1,071,087 ------------------ ------------------ 264,616,766 250,331,685 Operating revenue deductions: Operating expenses: Fuel 55,516,557 45,082,212 Purchased power 68,550,323 56,587,220 Other 34,819,417 32,265,331 Merger Related Expenses 1,557,651 328,835 ------------------ ------------------ 160,443,948 134,263,598 Total operating expenses Maintenance and repairs 15,587,444 14,447,477 Depreciation and amortization 29,764,624 27,564,790 Provision for income taxes 4,603,191 13,256,494 Merger-related income tax benefit (2,323,982) - Other taxes 13,357,772 14,195,200 ------------------ ------------------ 221,432,997 203,727,559 ------------------ ------------------ Operating income 43,183,769 46,604,126 Other income and deductions: Allowance for equity funds used during construction 1,354,619 1,494,721 Interest income 301,408 850,451 Loss on SLCC plant disallowance (4,087,066) - Provision for other income taxes 1,729,882 - Other - net (1,532,962) (617,673) ------------------ ------------------ (2,234,119) 1,727,499 ------------------- ------------------ Income before interest charges 40,949,650 48,331,625 Interest charges: Long-term debt: Trust preferred distributions by subsidiary holding solely parent debentures 2,479,167 - Other 26,374,054 25,316,150 Commercial paper 2,654,808 1,017,436 Allowance for borrowed funds used during construction (4,890,737) (2,338,110) Other 695,461 422,831 ------------------ ------------------ 27,312,753 24,418,307 ------------------ ------------------ Net income applicable to common stock $ 13,636,897 $ 23,913,318 ================== ================== Weighted average number of common shares outstanding 17,629,871 17,437,554 ================== ================== Basic and diluted earnings per weighted average share of common stock $ 0.77 $ 1.37 ========= ========= Dividends per share of common stock $ 1.28 $ 1.28 ========= =========
See accompanying Notes to Financial Statements. 5 EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENT OF COMPREHENSIVE (LOSS) INCOME (UNAUDITED)
September, 2001 CURRENT YEAR TO 12 MONTHS QUARTER DATE ENDED ------------------ ------------------ ------------------- Net income $ 7,358,707 $ 10,306,768 $ 13,636,897 Net change in unrealized gain/(loss) on derivative instruments: (1,176,000) (1,889,000) (1,889,000) ------------------ ------------------ ------------------- Comprehensive Income $ 6,182,707 $ 8,417,768 $ 11,747,897 ================== ================== =================== - -----------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY (UNAUDITED)
Sept. 30, 2001 Dec. 31, 2000 Sept. 30, 2000 ------------------ ------------------ ------------------ Common stock - $1 par value $ 17,650,369 $ 17,547,742 $ 17,539,616 Common stock equity rights 54,888 48,788 48,259 Capital in excess of par value 169,932,853 167,908,881 167,688,689 Accumulated other comprehensive income loss (1,889,000) - - Installments received on common stock 283,259 530,208 327,098 Retained earnings 47,480,772 54,117,292 56,417,883 ------------------ ------------------ ------------------ Total Common Shareholders' Equity $ 233,513,141 $ 240,152,911 $ 242,021,545 ================== ================== ==================
See accompanying Notes to Financial Statements. 6 EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET (UNAUDITED)
September 30, December 31, 2001 2000 ------------------ ------------------ ASSETS Utility plant, at original cost: Electric $ 1,049,466,810 $ 921,033,228 Water 7,741,970 7,528,233 Construction work in progress 29,437,888 120,126,571 ------------------ ------------------ 1,086,646,668 1,048,688,032 Accumulated depreciation 344,403,054 328,370,253 ------------------ ------------------ 742,243,614 720,317,779 Current assets: Cash and cash equivalents 6,114,752 2,490,580 Accounts receivable - trade, net 26,091,503 19,960,839 Accrued unbilled revenues 8,071,370 11,824,546 Accounts receivable - other 6,425,050 3,631,654 Fuel, materials and supplies 14,506,609 14,589,253 Prepaid expenses 635,407 3,034,716 ------------------ ------------------ 61,844,691 55,531,588 ------------------ ------------------ Noncurrent Assets and deferred charges: Regulatory assets 36,368,663 36,590,292 Unamortized debt issuance costs 5,301,519 3,769,628 Other 17,334,385 13,530,017 ------------------ ------------------ 59,004,567 53,889,937 ------------------ ------------------ Total Assets $ 863,092,872 $ 829,739,304 ================== ================== CAPITALIZATION AND LIABILITIES: Common stock, $1 par value, 17,705,257 and 17,596,530 shares issued and outstanding, respectively $ 17,705,257 $ 17,596,530 Capital in excess of par value 170,216,112 168,439,089 Retained earnings (Note 2) 47,480,772 54,117,292 Accumulated other comprehensive loss (1,889,000) - ------------------ ------------------ Total common stockholders' equity 233,513,141 240,152,911 Long-term debt: Company obligated manditorily redeemable trust preferred securities of subsidiary holding solely parent debentures 50,000,000 - Other 288,052,464 325,643,766 ------------------ ------------------ 571,565,605 565,796,677 ------------------ ------------------ Current liabilities: Current maturities - mortgage bonds 57,500,000 20,000,000 Obligations under capital lease 133,155 - Accounts payable and accrued liabilities 29,594,130 35,782,456 Commercial paper 63,000,000 69,500,000 Customer deposits 3,924,413 3,789,583 Interest accrued 10,817,160 5,402,131 Loss in fair value of derivatives 1,889,000 - Taxes accrued, including income taxes 9,083,574 1,823,513 ------------------ ------------------ 175,941,431 136,297,683 ------------------ ------------------ Noncurrent liabilities and deferred credits: Regulatory liability 13,249,313 14,170,175 Deferred income taxes 85,740,615 83,581,349 Unamortized investment tax credits 6,704,859 7,231,000 Postretirement benefits other than pensions 4,872,008 4,835,897 State Line advance payments - 14,399,757 Other 5,019,042 3,426,766 ------------------ ------------------ 115,585,836 127,644,944 ------------------ ------------------ Total Capitalization and Liabilities $ 863,092,872 $ 829,739,304 ================== ==================
See accompanying Notes to Financial Statements. 7 EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, --------------------------------------- 2001 2000 ------------------ ------------------ Operating activities: Net income $ 10,306,768 $ 20,287,025 Adjustments to reconcile net income to cash flows: Depreciation and amortization 25,062,284 23,345,089 Pension income (2,822,250) (4,792,230) Deferred income taxes, net 1,796,117 2,403,122 Investment tax credit, net (526,141) (521,733) Allowance for equity funds used during construction (475,630) (1,494,721) Issuance of common stock for 401(k) plan 550,900 560,721 Other 222,637 - Loss on SLCC Plant Disallowance 4,087,066 - Issuance of common stock units for director retirement plan 84,000 84,000 Cash flows impacted by changes in: Accounts receivable and accrued unbilled revenues (5,170,884) (9,526,411) Fuel, materials and supplies 3,032,118 1,930,762 Prepaid expenses, other non-current assets and deferred 1,727,507 (614,036) charges Accounts payable and accrued liabilities (6,188,327) 2,052,895 Customer deposits, interest and taxes accrued 11,252,748 19,108,028 Other liabilities and other deferred credits 1,023,697 179,562 ------------------ ------------------ Net cash provided by operating activities 43,962,610 53,002,073 Investing activities: Construction expenditures (66,816,237) (94,467,266) Allowance for equity funds used during construction 475,630 1,494,721 ------------------ ------------------ Net cash used in investing activities (66,340,607) (92,972,545) Financing activities: Proceeds from issuance of common stock 1,250,850 3,679,354 Dividends (16,943,288) (16,777,573) Repayment of first mortgage bonds (151,000) (256,000) Payment of debt issue costs 114,513 48,857 State Line advance payments - 6,504,516 Proceeds from issuance of trust preferred securities 50,000,000 - Preferred securities issuance costs (1,768,906) - Net issuances (repayments) from short-term borrowings (6,500,000) 32,000,000 ------------------ ------------------ Net cash provided by (used in) financing activities 26,002,169 25,199,154 ------------------ ------------------ Net increase (decrease) in cash and cash equivalents 3,624,172 (14,771,318) Cash and cash equivalents at beginning of period 2,490,580 20,778,856 ------------------ ------------------ Cash and cash equivalents at end of period $ 6,114,752 $ 6,007,538 ================== ==================
See accompanying Notes to Financial Statements. 8 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Note 1 - Summary of Significant Accounting Policies The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2000. The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to present fairly the results for the interim periods presented. Certain reclassifications have been made to prior year information to conform with current year presentation. Note 2 - Retained Earnings Balance at January 1, 2001 $ 54,117,292 Changes January 1 through June 30: Net Income 2,948,062 Quarterly cash dividends on common stock: - $0.64 per share (11,285,885) Total changes January 1 through June 30 (8,337,823) -------------------- Balance at July 1, 2001 45,779,469 Changes July 1 through September 30: Net Income 7,358,707 Quarterly cash dividends on common stock: - $0.32 per share (5,657,404) Total changes July 1 through September 30 1,701,303 -------------------- Balance at September 30, 2001 $ 47,480,772 ====================
Note 3 - Income Taxes As a result of the termination in January 2001 of our proposed merger with UtiliCorp, approximately $6.1 million in merger related expenses that were not tax deductible when incurred by us became deductible. This deduction was taken in January 2001, decreasing income tax expense for the first quarter of 2001 by approximately $2.3 million. Note 4 - Trust Preferred Securities On March 1, 2001, Empire District Electric Trust I, issued 2,000,000 8.5% Trust Preferred Securities (liquidation amount $25 per preferred security) in a public underwritten offering. This 9 issuance generated proceeds of $50.0 million and issuance costs of $1.8 million. Holders of the trust preferred securities are entitled to receive distributions at an annual rate of 8.5% of the $25 liquidation amount. Quarterly payments of dividends by the trust, as well as payments of principal, are made from cash received from corresponding payments made by us on the $50.0 million aggregate principal amount of 8.5% Junior Subordinated Debentures due March 1, 2031, issued by us to the trust, and held by the trust, as assets. Our interest payments on the debentures are tax deductible by us. We have effectively guaranteed the payments due on the outstanding trust preferred securities. The net proceeds of this offering were added to our general funds and were used to repay short-term indebtedness. Note 5 - Recently Issued Accounting Standards On January 1, 2001, we adopted the provision of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) and Statement of Financial Accounting Standards No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities An Amendment of SFAS 133" (SFAS 138). SFAS 133, as amended, requires recognition of all derivatives as either assets or liabilities on the balance sheet measured at fair value. Adoption of these accounting rules in January 2001 had no immediate impact on us. However, during the second quarter of 2001, we began utilizing derivatives to manage our gas commodity market risk to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset. By using derivative financial instruments, we are exposed to credit risk and market risk. Credit risk is the risk that the counterparty might fail to fulfill its performance obligations under contractual terms. At September 30, 2001 we had minimal exposure to credit risk from counterparties. Market risk is the exposure to a change in the value of commodities caused by fluctuations in market variables, such as price. As of September 30, 2001, we have recorded liabilities of $1.9 million equal to the fair value of derivative financial instruments held as of that date in Current Liabilities on the balance sheet. As of September 30, 2001, we had one swap contract in place that was designated as a cash-flow hedging instrument. A $1.9 million unrealized loss representing the fair market value of this contract is recognized as Accumulated Other Comprehensive Loss in the capitalization section of the balance sheet. This amount will be adjusted cumulatively on a monthly basis until the determination periods, beginning November 1, 2001 and ending March 31, 2002. At the end of each determination period, which is the last day of each calendar month in the period, any gain or loss for that period related to the contract will be reclassified to fuel expense. As of September 30, 2001, $417,360 of losses relating to options has been recognized within other income and deductions in the accompanying statement of income. These option contracts did not qualify for hedge accounting. All option contracts have been exercised as of September 30, 2001. We have also entered into fixed-price forward contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to the reporting requirements of SFAS 133 because they are considered to be normal purchases and normal sales. Cash Flow Hedges - Hedging is compensating for a risk in a transaction by undertaking a further transaction. If the first transaction suffers a loss, the hedge will have a compensatory gain. Examples of cash flow hedges would be hedging the forecasted issuance of fixed rate debt, hedging the forecasted sale/purchase of power or hedging the forecasted purchase of coal or natural gas. SFAS 133 dictates that the effective portion of a gain or loss on cash flow hedges must be recorded in comprehensive income. This is adjusted when the gain or loss is recorded monthly as the value of the 10 derivatives is calculated based on current market prices. For a qualifying cash flow hedge, the derivative's gain or loss, to the extent that it is offset by the losses or gains on (1) the forecasted transaction or (2) the cash flows of the asset or liability being hedged, is deferred and reported as a component of other comprehensive income. The gains and losses accumulated in other comprehensive income are then reclassified to earnings in the same period or periods in which the hedged forecasted transaction or cash flows affect earnings. Comprehensive income does not affect earnings per share. In order to minimize our risk from volatile natural gas prices, we intend to utilize our resources and purchase contracts, at least once a year, to establish anticipated gas requirements for our retail load for each of the next four years. We will then model our system in the context of the regional power market to establish anticipated gas requirements for our generation units given the overall mix of the region. We have set the following guidelines for our procurement of gas for regional market needs: 0%-20% of year 2005 gas, 20%-40% of year 2004 gas, 40%-60% of year 2003 gas and 60%-80% of year 2002 gas. In July 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets". These statements eliminate the amortization of purchased goodwill and instead require an annual review of goodwill and intangibles for impairment or when a change or event occurs that indicates goodwill may be impaired. SFAS No. 142 is required to be adopted no later than the first quarter of fiscal 2002. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001 and establishes specific criteria for recognition of intangible assets separately from goodwill. We had no recorded goodwill as of September 30, 2001 but will continue to evaluate the total impact of the adoption of these Statements on our financial statements and financial reporting. In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Obligations Associated with the Retirement of Long-Lived Assets." This statement establishes standards for accounting and reporting for legal and constructive obligations associated with the retirement of tangible long-lived assets. In August 2001, the Financial Accounting Standards Board issued SFAS No. 144, " Accounting for the Impairment or Disposal of Long-Lived Assets", establishing new standards for accounting and reporting for the impairment or disposal of long-lived assets. This statement eliminates the requirement under SFAS 121 to allocate goodwill to long-lived assets to be tested for impairment. We are required to adopt SFAS No. 144 on January 1, 2002 and SFAS No. 143 on January 1, 2003. We will continue to evaluate the total impact of the adoption of these Statements on our financial statements and financial reporting. FORWARD LOOKING STATEMENTS Certain matters discussed in this quarterly report are "forward-looking statements" intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, competition, litigation, our construction program, rate and other regulatory matters, liquidity and capital resources and accounting matters. Factors that could cause actual results to differ materially from those currently anticipated in such statements include: the cost and availability of purchased power and fuel, and the results of our activities (such as hedging) to reduce the volatility of such costs; electric utility restructuring, including ongoing state and federal activities; weather, business and economic conditions, and other factors which may impact customer growth; operation of our generation 11 facilities; legislation; regulation, including rate relief and environmental regulation (such as NOx regulation); competition, including the impact of deregulation on off-system sales; changes in accounting requirements; other circumstances affecting anticipated rates, revenues and costs; the revision of our construction plans and cost estimates; the performance of projects undertaken by our non-regulated businesses and the success of efforts to invest in and develop new opportunities; and costs and effect of legal and administrative proceedings, settlements, investigations and claims. All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. New factors emerge from time to time and it is not possible for management to predict all such factors or to assess the impact of each such factor on us. Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations RESULTS OF OPERATIONS The following discusses significant changes in the results of operations for the three-month, nine-month and twelve-month periods ended September 30, 2001, compared to the same periods ended September 30, 2000. Terminated Merger With UtiliCorp As a result of the termination in January 2001 of our proposed merger with UtiliCorp, approximately $6.1 million in merger related expenses that were not tax deductible when incurred by us became deductible. This deduction was taken in January 2001, decreasing income tax expense and increasing operating income for the first quarter of 2001 by approximately $2.3 million. In addition, Empire expensed $1.2 million of additional costs related to the proposed merger in the first quarter of 2001. Total merger expenses for the nine months ended September 30, 2001 are $1.3 million. On-System Transactions Of our total electric operating revenues during the third quarter of 2001, approximately 43% were from residential customers, 31% from commercial customers, 16% from industrial customers, 5% from wholesale on-system customers and 1% from wholesale off-system transactions. The remainder of such revenues were derived from miscellaneous sources. From 1997 through 2000 our annual customer growth averaged 1.7%. We expect that number to continue at about 1.6% annually over the next several years. The percentage changes from the prior year in kilowatt-hour ("Kwh") sales and revenue by major customer class were as follows: 12
Operating Kwh Sales Revenues -------------------------------------------------------------------------------------- Nine Twelve Nine Twelve Third Months Months Third Months Months Quarter Ended Ended Quarter Ended Ended -------------------------------------------------------------------------------------- Residential (3.9)% 6.9% 12.3% (3.4)% 2.8% 7.9% Commercial (1.1) 5.9 8.7 (0.7) 4.6 5.7 Industrial (2.8) (0.2) 1.7 (0.5) 1.2 2.3 Wholesale On-System 0.7 5.4 5.3 13.4 11.9 13.6 Total On-System (2.5) 4.9 8.0 (1.3) 3.6 6.4
Residential and commercial Kwh sales and revenues decreased during the third quarter of 2001 compared to the third quarter of 2000 due mainly to milder temperatures in August and September of 2001 as compared to the unusually warm temperatures in August and September of 2000. Although the average temperature in August 2001 was milder than the previous year, a new peak demand of 1001 Mw was set on August 9, 2001. Industrial Kwh sales and related revenues decreased during the third quarter of 2001 as a result of an apparent decrease in consumption by the manufacturing sector in our service territory during August and September 2001. On-system wholesale Kwh sales increased slightly during the third quarter of 2001. Revenues associated with these FERC-regulated sales increased more than the corresponding Kwh sales as a result of the fuel adjustment clause applicable to such sales. This clause permits the pass through to customers of changes in fuel and purchased power costs. Increases in fuel and purchased power costs were higher for the third quarter of 2001 than in the same period a year earlier, causing the increase in revenues associated with such sales for that period to exceed the increase in Kwh sales. For the nine months ended September 30, 2001, Kwh sales to and revenues from our residential and commercial customers increased, primarily reflecting the warmer temperatures experienced during the second quarter of 2001 as well as the unusually cold temperatures experienced during the first quarter of 2001 as compared to the milder temperatures during the same periods of 2000. Industrial Kwh sales decreased slightly while related revenues increased, reflecting continuing increases in business activity throughout our service territory in the first and second quarters of 2001 and the decrease in the third quarter. On-system wholesale Kwh sales increased for the nine months ended September 30, 2001, reflecting the weather-related reasons discussed above. Revenues associated with these FERC-regulated sales increased more than the corresponding Kwh sales as a result of the operation of the fuel adjustment clause applicable to such sales. Increases in fuel and purchased power costs were higher for the nine months ended September 30, 2001 than in the same period a year earlier, causing the increase in revenues associated with such sales for that period to exceed the increase in Kwh sales. For the twelve months ended September 30, 2001, Kwh sales to and revenue from our residential and commercial customers increased, reflecting the weather conditions discussed above. Industrial sales and revenue increased due to increased business activity in our service territory during the fourth quarter of 2000 and the first two quarters of 2001. On-system wholesale Kwh sales increased for the twelve months ended September 30, 2001, reflecting the weather conditions discussed above as well as unseasonably cold temperatures in the fourth quarter of 2000. Revenues associated with these FERC-regulated sales increased more than the corresponding Kwh sales as a result of the operation of the fuel adjustment clause applicable to such sales. Going forward, we estimate a weather-normalized annual sales growth of 2.5%. 13 On November 3, 2000, we filed a request with the Missouri Public Service Commission for a general annual increase in rates for our Missouri electric customers in the amount of $41,467,926, or 19.36%. This request sought recovery of expenses resulting from significantly higher natural gas prices than the levels contemplated by our existing rates as well as our investment in the Combined Cycle Unit recently constructed at the State Line Power Plant and other plant additions which have occurred since our last rate increase in September 1997. We also filed a request for interim rate relief in February 2001, which was denied in March. The Missouri Commission issued a final order September 20, 2001. The order approves a permanent annual increase in rates in the amount of approximately $17.1 million, or 8.4% effective October 2, 2001. In addition, the order approves an annual Interim Energy Charge (IEC) of approximately $19.6 million effective October 1, 2001 and expiring at 12:01 A.M. on October 1, 2003. This IEC is $0.0054 per kilowatt hour of customer usage and is subject to refund with interest to our customers at the end of the two-year period. The recent extraordinarily high natural gas prices and extreme volatility of natural gas led the Missouri Commission to allow forecasted fuel costs to be used rather than the traditional historical costs in determining the fuel portion of the rate increase. At the end of the two year period, the excess money collected from customers, if any, above the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates, will be refunded to the customers with interest equal to the prime rate in effect on the day the rider expires. As of October 22, 2001, we have hedged approximately 81% of our anticipated natural gas usage for the fourth quarter of 2001 at an average price of $3.226 per Dekatherm (Dth). Approximately 68% of our anticipated volume usage for the year 2002, is hedged at an average price of $3.616 per Dth while approximately 34% of our anticipated volume usage for the year 2003, is hedged at an average price of $3.582 per Dth. On October 26, 2001, we filed a request with the Missouri Public Service Commission for an additional annual increase in rates for our Missouri electric customers in the amount of $3,562,983 to rectify an apparent clerical error in the recent rate order. The Missouri Commission staff recommended that the Commission schedule the matter for oral arguments and/or hearing. In response, we filed a reply on November 7, 2001 suggesting an alternative proposal. We request that the Commission accept the tariffs we filed on October 26, 2001 for an annual increase of $3,562,983 and, in return, we will submit proposed tariffs to simultaneously reduce the amount of annual revenues to be collected pursuant to the IEC by the same amount. The Missouri Commission has given interested parties until November 14, 2001 to respond to this alternative proposal. We cannot predict the outcome of this filing. Off-System Transactions In addition to sales to our own customers, we also sell power to other utilities as available and also provide transmission service through our system for transactions between other energy suppliers. During the third quarter of 2001, revenues from such off-system transactions were approximately $1.9 million as compared to $3.8 million for the same period ended September 30, 2000. Off-system revenues were approximately $5.6 million for the nine-month period ended September 30, 2001 as compared to $8.0 million for the same period in 2000. For the twelve months ended September 30, 2001, revenues from such off-system transactions were approximately $8.2 million as compared to $9.7 million for the twelve months ended September 30, 2000. The decrease in revenues during each of these periods resulted primarily from our peak hour market-based power rates being substantially lower this summer than in 2000 and from the restricted availability of the State Line Plant due to the construction of the Combined Cycle Unit. 14 We are a member of the Southwest Power Pool (SPP), a regional division of the North American Electric Reliability Council, and have been participating with other utility members in an effort to restructure the SPP to make it a regional transmission organization (RTO). However on July 12, 2001,the FERC stated that the SPP was not large enough to form its own RTO. The FERC, moving toward its goal of dividing the nation's grid into four regional RTOs, ordered the SPP to hold talks with others to consider forming a single Southeast RTO but also acknowledged that SPP may want to have discussions with the Midwest Independent Transmission System Operator, Inc. (MISO). On October 19, 2001, the SPP and MISO announced an agreement for the consolidation of the two organizations, which is expected to be completed in the first quarter of 2002. The new organization will operate an interconnected transmission system encompassing over 120,000 megawatts of generation capacity. We cannot predict what effect, if any, this consolidation will have on our off-system sales and revenues. On November 7, 2001, the FERC dropped its year-end deadline for utilities to create four RTOs. Reference is made to our Annual Report on Form 10-K for the year ended December 31, 2000 under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations - Competition". Operating Revenue Deductions During the third quarter of 2001, total operating expenses increased approximately $0.3 million (0.7%) compared with the same period last year. Total fuel costs increased approximately $3.9 million (20.9%) during the third quarter of 2001 as compared to the same period in 2000, reflecting increased generation from the gas turbines at the Energy Center and the new State Line Combined Cycle Unit and the higher cost of natural gas used to fuel these units. The Asbury Plant was taken out of service on September 15, 2001 for a major scheduled ten-week outage. State Line Unit One was out of service on an unscheduled maintenance outage from September 6, 2001 through October 16, 2001 and the State Line Combined Cycle Unit was taken out of service on October 19, 2001 for a maintenance outage scheduled to run through November 12, 2001. Purchased power costs decreased approximately $3.6 million (21.9%) during the period, primarily due to decreased demand resulting from the milder temperatures in August and September of 2001 as well as the increased generating capability due to the completion of the State Line Combined Cycle Unit. Other operating expenses increased $0.1 million (1.0%) during the third quarter. Maintenance and repairs expense increased approximately $1.1 million (35.4%) during the quarter, primarily due to the first payment on a new State Line maintenance contract. We signed a long-term maintenance agreement with Siemens Westinghouse in July 2001 for scheduled maintenance associated with the two combustion turbines utilized in the Combined Cycle Unit. We also signed a long-term maintenance agreement with Siemens Westinghouse for scheduled maintenance associated with the two simple cycle combustion turbines at the Energy Center and the one simple cycle combustion turbine located at the State Line Power Plant. These maintenance costs were included in our recent rate case. Depreciation and amortization expenses increased approximately $1.3 million (18.3%) during the quarter due to increased levels of plant and equipment placed in service. Depreciation and amortization expenses will begin to decrease in the fourth quarter of 2001 due to new depreciation rates put into effect as a result of the Missouri rate case. This decrease is expected to total approximately $8 million in 2002. Total income taxes decreased $4.4 million (51.9%) due primarily to a decrease in taxable income. Other taxes increased slightly. For the nine months ended September 30, 2001, total operating expenses increased approximately $13.4 million (12.5%). Merger related expenses (which include expenses related to severance benefits incurred in the first quarter of 2001) accounted for approximately $1.1 million of 15 this increase. Purchased power costs increased $3.3 million (7.3%) primarily due to increased demand resulting from unusually cold temperatures in the first quarter of 2001 and increased costs for this energy. Total fuel costs increased $6.6 million (17.8%) primarily due to the increased generation from the gas turbines at the Energy Center and the new State Line Combined Cycle Unit during the third quarter of 2001 as well as increased natural gas prices. Other operating expenses increased $2.4 million (9.7%), primarily due to an actuarially determined adjustment to our fully-funded pension benefit expense in the first quarter of 2001 as well as decreased income from the pension fund caused by a decline in the value of invested funds during 2001. Maintenance and repairs expense increased $0.8 million (7.2%) for the nine months ended September 30, 2001 primarily due to the first payment under our new maintenance contracts. Total provisions for income taxes decreased $9.1 million (82.4%) due primarily to a decrease in taxable income and to the benefit created by the deductibility of the approximately $6.1 million in merger related expenses in the first quarter of 2001. Other taxes increased $0.2 million (2.4%) during the period. During the twelve months ended September 30, 2001, total operating expenses increased approximately $26.2 million (19.5%) compared to the year ago period. The merger related expenses discussed above accounted for approximately $1.2 million of this increase. Total purchased power costs increased approximately $12.0 million (21.1%) while total fuel costs increased approximately $10.4 million (23.1%) during the twelve-month period. Purchased power costs increased primarily due to increased demand resulting from unusually cold temperatures in the first quarter of 2001 and December of 2000 as well as increased costs for the purchased power. Total fuel costs increased primarily reflecting the increased generation from the gas turbines at the Energy Center and the State Line Power Plant in the third quarter of 2001 and fourth quarter of 2000 and the increased natural gas prices. Our natural gas costs were 50% higher during the twelve-months ended September 30, 2001 as compared to the same period in 2000. Other operating expenses increased approximately $2.6 million (7.9%) during the twelve months ended September 30, 2001, compared to the same period a year earlier primarily due to an actuarially determined adjustment to our pension benefit obligation in the first quarter of 2001 as well as decreased income from the pension fund caused by a decline in the value of invested funds during 2001. Maintenance and repairs expense increased approximately $1.1 million (7.9%) during the twelve months ended September 30, 2001 compared to the prior period primarily due to the first payment under our new maintenance contracts in the third quarter of 2001. Depreciation and amortization expense increased approximately $2.2 million (8.0%) due to increased levels of plant and equipment placed in service. Total provision for income taxes decreased $11.0 million (82.8%) due to lower taxable income during the current period and to the benefit created by the deductibility of approximately $6.1 million in merger related expenses in the first quarter of 2001. Other taxes decreased $0.8 million (5.9%). Nonoperating Items Total allowance for funds used during construction (AFUDC) decreased significantly during the third quarter of 2001 reflecting the completion of the State Line Combined Cycle Unit. AFUDC increased during both the nine-months ended and the twelve-months ended September 30, 2001 periods reflecting the construction of the State Line Combined Cycle Unit. Other-net deductions increased during each of the periods presented as compared to prior year levels, reflecting a loss in the second and third quarters of 2001 caused by the marking to market, required by SFAS 133, of option contracts entered into in connection with our hedging activities. 16 Interest income decreased for all periods presented reflecting lower balances of cash available for investment. A one-time write-down of $4.1 million was taken in the third quarter of 2001 for disallowed capital costs related to the construction of the State Line Combined Cycle Unit. These disallowed costs were part of a stipulated agreement between the Missouri Public Service Commission and Empire in connection with our recent rate case and will not be recovered in rates. The net effect on earnings after considering the tax effect on this write-down is $2.5 million. Interest charges on long-term debt increased slightly during the third quarter of 2001 and for the nine months ended September 30, 2001. Interest charges on long-term debt increased $1.1 million (4.2%) for the twelve months ended period when compared to the same period last year due to the issuance of $100 million of our unsecured Senior Notes in November 1999. Commercial paper interest increased slightly during the third quarter of 2001 compared to the same period last year, while increasing $1.4 million (245.9%) for the nine months ended September 30, 2001 and $1.6 million (160.9%) for the twelve months ended period. These increases in commercial paper interest were caused by the increased usage of short-term debt for financing our ongoing construction program. Interest related to our Trust Preferred Securities issued March 1, 2001 added $1.1 million to interest charges in the second quarter and $2.5 million to interest charges in both the nine month and twelve-month periods ended in 2001. Earnings For the third quarter of 2001, earnings per share of common stock were $0.42 compared to $0.82 during the third quarter of 2000. Earnings per share were negatively impacted by the mild temperatures in August and September of 2001, significantly increased natural gas and purchased power costs and the one-time non-cash charge of $2.5 million, net of related income taxes, from the write-down of the State Line construction expenditures which were disallowed by the Missouri Public Service Commission. Excluding merger expenses and the net one-time non-cash charge, earnings per share would have been $0.56 for the third quarter of 2001. Earnings per share for the nine months ended September 30, 2001, were $0.58 compared to $1.16 for the nine months ended a year earlier. The decline in earnings per share for the nine months ended September 30, 2001, excluding merger costs and the one-time write-down of construction expenditures, was primarily due to increased fuel and purchased power costs. Positively impacting earnings for the nine months ended September 30, 2001 was a one-time tax benefit of $2.3 million from previously incurred merger-related costs that became deductible for income tax purposes in the first quarter of 2001. Excluding $1.3 million in merger costs for the first nine months of 2001 and $0.2 million for the first nine months of 2000, the one-time write-down of construction expenditures and the tax benefit from merger expenses that became deductible in 2001, earnings per share would have been $0.67 for the nine months ended September 30, 2001 and $1.17 for the nine months ended September 30, 2000. For the twelve months ending September 30, 2001, earnings per share of common stock were $0.77 compared to $1.37 for the year earlier period. Excluding $1.6 million in merger costs for the twelve months ended September 2001 and $0.3 million in merger costs for the twelve months ended September 2000, the one-time write-down of construction expenditures and the tax benefit from merger expenses that became deductible in 2001, earnings per share would have been $0.87 and $1.39 respectively. This decline in earnings per share was primarily due to increased fuel and purchased power costs. Earnings for the twelve months ended September 30, 2001 were positively impacted by the one-time tax benefit from merger expenses in 2001 and significantly higher AFUDC related to the construction of the State Line Combined Cycle Unit. 17 Environmental Matters In July 2000, we received a request for information from the EPA regarding the State Line Power Plant. The information request indicated that the State Line Power Plant units should have an Acid Rain Permit under Title IV of the 1990 Amendments to the Clean Air Act in addition to the construction and operating permits previously issued to us by the Missouri Department of Natural Resources. In response, in August 2000, we applied for the required Acid Rain Permit with the Missouri Department of Natural Resources and subsequently received the required permit. The EPA notified us in June 2001 that we were subject to being fined approximately $173,000 because of the lack of the permit but had the right to request a hearing or a settlement conference. We had a settlement conference with the EPA in July. The EPA offered to settle if we agreed to a $35,000 fine and to undertake a supplemental environmental project with a cost approximating $128,500. We have preliminary consensus with the EPA and expect to conclude this matter during the fourth quarter of 2001. Competition The Arkansas Legislature passed a bill in April 1999 that would deregulate the state's electricity industry as early as January 2002. The Staff of the Arkansas Public Service Commission filed testimony in October 2000 recommending that the Commission encourage the legislature to extend the date for retail open access beyond the current statutory deadline of June 30, 2003. A bill was enacted in February 2001 delaying deregulation until October 2003 and giving the Commission authority to set further delays in one-year increments until October 2005. In September 2001, the Staff of the Arkansas Public Service Commission recommended that the Commission either end efforts to deregulate the electric market or delay those efforts for three years because of the threat of higher and unstable rates. The Staff's recommendations were based on a study performed for them by a Washington D.C.-based consulting firm. The Commission's executive director favors repealing laws deregulating the state's retail electric market and starting over when conditions change. The three-member Commission held a hearing on November 1, 2001 to consider the Staff's recommendation. Approximately 3.15% of our retail electric revenues for the nine months ended September 30, 2001 were derived from sales subject to Arkansas regulation. There is no activity in the other jurisdictions we serve. LIQUIDITY AND CAPITAL RESOURCES Our construction-related expenditures totaled $10.4 million during the third quarter of 2001, compared to $35.8 million for the same period in 2000. For the nine months ended September 30, 2001, construction-related expenditures totaled $56.8 million compared to $94.5 million for the same period in 2000. Approximately $5.6 million and $25.7 million of construction expenditures during the third quarter and first nine months, respectively, of 2001 were related to additions to our transmission and distribution systems to meet projected increases in customer demand. Approximately $1.5 million of these third quarter expenditures and $2.3 million for the first nine months of 2001 were related to additions and replacements at the Asbury Power Plant. Approximately $0.8 million of these third quarter expenditures and approximately $1.2 million during the first nine months of 2001 were related to additions to our investment in fiber optics cable and equipment. Approximately $0.9 million during the third quarter of 2001 and $24.1 million during the first nine months of 2001 were related to the 18 construction of the State Line Combined Cycle Unit. During the first nine months of 2000, approximately 41% of construction expenditures were satisfied with internally generated funds. Construction of the 500-megawatt State Line Combined Cycle Unit was substantially completed and the plant was placed into commercial operations on June 25, 2001. The total cost of this unit was approximately $204 million, including the one-time non-cash charge of $4.1 million, before related income taxes, that was taken in the third quarter of 2001 for the disallowed capital costs. Our 60% share of this amount was approximately $122 million before considering our contribution of 40% of existing property. After the transfer to Westar Generating on June 15, 2001 of an undivided 40% joint ownership interest in the existing State Line Unit No.2 and certain other property at book value, our net cash requirement was approximately $108 million, excluding AFUDC. We are responsible for the operation and maintenance of the State Line Combined Cycle Unit with the costs shared in the same 60/40 split. Our budgeted construction expenditures for 2001, including AFUDC, were approximately $63.3 million, including approximately $25.0 million for the Combined Cycle Unit and approximately $20.8 million for additions to our distribution system. We currently expect that internally generated funds will provide 100% of the funds required for the remainder of our 2001 construction expenditures, which we estimate to be $8.3 million. On October 25, 2001, we agreed with P2 Energy to purchase two Twin Pac aero units to be installed at the Empire Energy Center in Jasper County, Missouri with generating capacity of 50 megawatts each. An initial payment of $3.4 million was made at that time. The first unit is to be delivered in October 2002 and is expected to be operational by April 2003. The second unit is scheduled to be delivered in October 2003 and is expected to be operational by April 2004. Contracts with other vendors will be entered into for construction and installation of the units. The estimated cost for the purchase, construction and installation of these units will be approximately $18.8 million in 2002, $25.8 million in 2003 and $7.0 million in 2004. As in the past, we intend to utilize short-term debt to finance our needs and repay such borrowings with the proceeds of sales of public offerings of long-term debt or equity securities, (including the sale of our common stock pursuant to our Employee Stock Purchase Plan) and with internally-generated funds. We currently have lines of credit aggregating $75 million. In February 2001, the SEC declared effective our $80 million shelf registration statement covering our unsecured debt securities and preferred securities of two newly created trusts of which $30 million remains available for issuance. We also have an effective shelf registration statement on file with the SEC under which up to an aggregate of $50 million of our common stock, first mortgage bonds and unsecured debt securities remain available for issuance pending the approval of the Kansas Corporation Commission. On October 1, 2001, we announced plans, subject to market and other conditions, to sell up to $50 million of newly issued shares of our common stock to the public in an underwritten public offering during the fourth quarter of 2001. Proceeds from the sale of the additional common stock will be used to repay short-term debt. Following announcement of the merger with UtiliCorp, the ratings for our first mortgage bonds (other than the pollution control bonds) were placed on credit watch with downward implications by Moody's Investors Service and Standard & Poor's. Standard & Poor's removed the credit watch but kept the downward implication in January 2001 after the merger was terminated. On May 3, 2001, Moody's Investors Service lowered the debt ratings of our first mortgage bonds (other than the pollution control bonds) to Baa1 from A2, and on our senior unsecured debt to Baa2 from A3. This downgrade was primarily due to the risk to our credit profile associated with our ability to obtain necessary rate relief from the Missouri Public Service Commission to recover our capital 19 expenditures associated with the State Line construction and our increased operating expenses primarily caused by escalating natural gas prices. Item 3. Quantitative and Qualitative Disclosures about Market Risk Market risk is the exposure to a change in the value of a physical asset or financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates or commodity prices. We handle market risk in accordance with established policies, which may include entering into various derivative transactions. See Note 5 of "Notes to Consolidated Financial Statements" for further information. Interest Rate Risk. We are exposed to changes in interest rates as a result of significant financing through our issuance of commercial paper. We manage our interest rate exposure by limiting our variable-rate exposure to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates. If market interest rates average 1% more in 2001 than in 2000, our interest expense would increase, and income before taxes would decrease by approximately $700,000. This amount has been determined by considering the impact of the hypothetical interest rates on our commercial paper balances as of December 31, 2000. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure. Commodity Price Risk. We are exposed to the impact of market fluctuations in the price and transportation costs of coal, natural gas, and electricity and employ established policies and procedures to manage the risks associated with these market fluctuations. PART II. OTHER INFORMATION Item 5. Other Information. At September 30, 2001, the Company's ratio of earnings to fixed charges was 1.49x. See Exhibit (12) hereto. William L. Gipson, currently Executive Vice President of Empire, was named to the newly created position of Chief Operating Officer at our Board of Directors meeting held on October 24-25, 2001. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits. (12) Computation of Ratios of Earnings to Fixed Charges. 20 (b) Reports on Form 8-K. (1) In a current report dated September 21, 2001, Empire filed, under Item 5. "Other Events," a press release relating to Empire's rate increase for its Missouri electric customers and the Report and Order from the Missouri Public Service Commission issued on September 20, 2001. (2) In a current report dated October 16, 2001, Empire furnished, under Item 9. "Regulation FD Disclosure," the 2001 Analyst Presentation presented by Empire on October 16, 2001 and the accompanying slide show. 21 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 EMPIRE DISTRICT ELECTRIC COMPANY Registrant By /s/ D. W. Gibson ---------------------------------- D. W. Gibson Vice President - Finance By /s/ D. L. Coit ---------------------------------- D. L. Coit Controller, Assistant Treasurer and Assistant Secretary November 13, 2001 22 EX-12 3 dex12.txt COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES EXHIBIT (12) COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
Twelve Months Ended September 30, 2001 ----------------------- Income before provision for income taxes and fixed charges (Note A) $ 47,839,355 Fixed charges: Interest on first mortgage bonds $ 17,272,119 Amortization of debt discount and expense less premium 1,073,997 Interest on short-term debt 2,654,808 Interest on other long-term debt 8,172,184 Interest on trust preferred distributions by subsidiary holding solely parent debentures 2,479,167 Other interest 423,012 Rental expense representative of an interest factor (Note B) 20,672 ----------------------- Total fixed charges 32,095,959 Ratio of income before provision for incomes taxes to net income 1.154x ----------------------- Ratio of earnings to fixed charges 1.49x
NOTE A: For the purpose of determining earnings in the calculation of the ratio, net income has been increased by the provision for income taxes, non-operating income taxes and by the sum of fixed charges as shown above. NOTE B: One-third of rental expense (which approximates the interest factor). -----END PRIVACY-ENHANCED MESSAGE-----