-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, DLdsOu+FhtB/mLqUayDZDTGoJiZEVX9I31vy0PiTTaFt4Vvr04AqzViT1c3v88/2 ID1wI1c2gnHW2bsv7ja7Qg== 0000009466-94-000026.txt : 19941116 0000009466-94-000026.hdr.sgml : 19941116 ACCESSION NUMBER: 0000009466-94-000026 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19940930 FILED AS OF DATE: 19941114 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: BALTIMORE GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000009466 STANDARD INDUSTRIAL CLASSIFICATION: 4931 IRS NUMBER: 520280210 STATE OF INCORPORATION: MD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-01910 FILM NUMBER: 94559063 BUSINESS ADDRESS: STREET 1: GAS & ELECTRIC BLDG STREET 2: CHARLES CTR CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4107835920 10-Q 1 SEPTEMBER 30, 1994 FORM 10-Q FORM 10-Q SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Quarterly Period Ended September 30, 1994 Commission file number 1-1910 BALTIMORE GAS AND ELECTRIC COMPANY - ----------------------------------------------------------------- (Exact name of registrant as specified in its charter) Maryland 52-0280210 - ----------------------------------------------------------------- (State of incorporation) (IRS Employer Identification No.) Gas and Electric Building, Charles Center, Baltimore, Maryland 21201 - ----------------------------------------------------------------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code 410-783-5920 Not Applicable - ----------------------------------------------------------------- (Former name, former address and former fiscal year, if changed since last report) 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, and (2) has been subject to such filing requirements for the past 90 days. Yes X No Common Stock, without par value - 147,527,114 shares outstanding on October 31, 1994. BALTIMORE GAS AND ELECTRIC COMPANY PART I. FINANCIAL INFORMATION CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Quarter Ended Sept. 30, Nine Months Ended Sept. 30, 1994 1993 1994 1993 (In Thousands, Except Per-Share Amounts) Revenues Electric ............................................... $ 649,223 $ 686,998 $ 1,666,548 $ 1,632,168 Gas ....................................................... 51,450 49,580 324,520 307,291 Diversified businesses .................................... 53,205 57,445 181,750 140,253 Total revenues ............................................ 753,878 794,023 2,172,818 2,079,712 Expenses Other Than Interest and Income Taxes Electric fuel and purchased energy ........................ 148,082 143,369 395,595 387,418 Gas purchased for resale .................................. 19,868 21,193 178,376 170,652 Operations ................................................ 133,161 146,740 420,187 409,677 Maintenance ............................................... 35,550 37,204 124,540 137,759 Diversified businesses - selling, general, and administrati 37,006 35,379 140,281 102,505 Depreciation and amortization ............................. 90,767 66,151 228,480 189,418 Taxes other than income taxes ............................. 56,971 56,113 153,500 151,352 Total expenses other than interest and income taxes ....... 521,405 506,149 1,640,959 1,548,781 Income From Operations ...................................... 232,473 287,874 531,859 530,931 Other Income Allowance for equity funds used during construction ....... 5,565 3,534 16,180 10,690 Equity in earnings of Safe Harbor Water Power Corporation . 1,088 1,068 3,266 3,204 Net other income and deductions ........................... 213 1,168 366 2,577 Total other income ........................................ 6,866 5,770 19,812 16,471 Income Before Interest and Income Taxes ..................... 239,339 293,644 551,671 547,402 Interest Expense Interest charges .......................................... 54,071 55,232 159,840 160,599 Capitalized interest ...................................... (3,161) (3,935) (8,972) (13,033) Allowance for borrowed funds used during construction ..... (3,009) (1,912) (8,749) (5,994) Net interest expense ...................................... 47,901 49,385 142,119 141,572 Income Before Income Taxes .................................. 191,438 244,259 409,552 405,830 Income Taxes Current ................................................... 51,442 61,604 75,329 82,712 Deferred .................................................. 15,440 27,679 64,896 50,723 Investment tax credit adjustments ......................... (2,060) (2,082) (6,142) (6,335) Total income taxes ........................................ 64,822 87,201 134,083 127,100 Net Income .................................................. 126,616 157,058 275,469 278,730 Preferred and Preference Stock Dividends .................... 9,902 10,547 29,954 31,642 Earnings Applicable to Common Stock ...................... $ 116,714 $ 146,511 $ 245,515 $ 247,088 Average Shares of Common Stock Outstanding ................. 147,487 145,367 146,957 144,770 Total Earnings Per Share of Common Stock .................... $0.79 $1.01 $1.67 $1.71 Dividends Declared Per Share of Common Stock ................ $0.3 $0.37 $1.13 $1.10 Certain prior-year amounts have been restated to conform with the current year's presentation.
See Notes to Consolidated Financial Statements. PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED BALANCE SHEETS September 30, December 31, 1994* 1993 (In Thousands) ASSETS Current Assets Cash and cash equivalents ................................... $ 61,228 $ 84,236 Accounts receivable (net of allowance for uncollectibles).... 424,086 401,853 Fuel stocks ................................................... 67,458 70,233 Materials and supplies ........................................ 144,595 145,130 Prepaid taxes other than income taxes ......................... 83,990 54,237 Other ......................................................... 20,160 38,971 Total current assets .......................................... 801,517 794,660 Investments and Other Assets Real estate projects .......................................... 467,048 487,397 Power generation systems ...................................... 304,456 298,514 Financial investments ......................................... 229,174 213,315 Nuclear decommissioning trust fund ............................ 66,463 56,207 Safe Harbor Water Power Corporation ........................... 34,165 34,138 Senior living facilities ...................................... 10,722 2,005 Other ........................................................ 69,256 65,355 Total investments and other assets ............................ 1,181,284 1,156,931 Utility Plant Plant in service Electric .................................................... 5,835,841 5,713,259 Gas ......................................................... 592,463 557,942 Common ...................................................... 500,196 487,740 Total plant in service ...................................... 6,928,500 6,758,941 Accumulated depreciation ......................................(2,260,552) (2,161,984) Net plant in service .......................................... 4,667,948 4,596,957 Construction work in progress ................................. 511,298 436,440 Nuclear fuel (net of amortization) ............................ 144,737 139,424 Plant held for future use ..................................... 24,238 24,066 Net utility plant ............................................. 5,348,221 5,196,887 Deferred Charges Regulatory Assets Income taxes recoverable through future rates ................ 263,152 259,856 Deferred fuel costs (net of reserve for possible disallowance) 125,516 130,052 Deferred termination benefit costs (net of amortization)...... 83,550 96,793 Deferred nuclear expenditures (net of amortization) .......... 89,295 86,726 Deferred postemployment benefit costs ........................ 70,772 62,892 Deferred cost of decommissioning federal uranium enrichment facilities (net of amortization) ................. 53,736 49,562 Deferred energy conservation expenditures (net of amortizatio 38,935 38,655 Deferred environmental costs (net of amortization) ........... 35,656 32,966 Other ........................................................ 3,904 10,623 Total regulatory assets ...................................... 764,516 768,125 Other ......................................................... 87,782 70,436 Total deferred charges ........................................ 852,298 838,561 TOTAL ASSETS .................................................. $ 8,183,320 $ 7,987,039
* Unaudited See Notes to Consolidated Financial Statements. PART I. FINANCIAL INFORMATION (Continued)
CONSOLIDATED BALANCE SHEETS September 30, December 31, 1994* 1993 (In Thousands) LIABILITIES AND CAPITALIZATION Current Liabilities Short-term borrowings ....................................... $ 69,400 $ 0 Current portions of long-term debt and preference stock ....... 41,618 44,516 Accounts payable .............................................. 176,616 195,534 Customer deposits ............................................. 25,205 22,345 Accrued taxes ................................................. 46,270 20,623 Accrued interest .............................................. 59,617 58,541 Dividends declared ............................................ 66,040 63,966 Accrued vacation costs ........................................ 34,383 35,546 Other ......................................................... 23,236 38,716 Total current liabilities ..................................... 542,385 479,787 Deferred Credits and Other Liabilities Deferred income taxes ......................................... 1,134,673 1,067,611 Deferred investment tax credits ............................... 151,399 157,426 Pension and postemployment benefits ........................... 146,776 183,043 Decommissioning of federal uranium enrichment facilities ...... 49,786 46,858 Other ......................................................... 67,926 56,974 Total deferred credits and other liabilities .................. 1,550,560 1,511,912 Capitalization Long-term Debt First refunding mortgage bonds of BGE ......................... 1,744,385 1,802,148 Other long-term debt of BGE ................................... 544,550 482,550 Long-term debt of Constellation Companies ..................... 577,891 597,716 Unamortized discount and premium .............................. (18,119) (17,754) Current portion of long-term debt ............................. (40,118) (41,516) Total long-term debt .......................................... 2,808,589 2,823,144 Preferred Stock ................................................. 59,185 59,185 Redeemable Preference Stock ..................................... 342,500 345,500 Current portion of redeemable preference stock ................ (1,500) (3,000) Total redeemable preference stock ............................. 341,000 342,500 Preference Stock Not Subject to Mandatory Redemption ............ 150,000 150,000 Common Shareholders' Equity Common stock .................................................. 1,425,254 1,391,464 Retained earnings ............................................. 1,330,536 1,251,140 Pension liability adjustment ................................ (22,093) (22,093) Net unrealized loss on available-for-sale securities ........ (2,096) 0 Total common shareholders' equity ............................. 2,731,601 2,620,511 Total capitalization .......................................... 6,090,375 5,995,340 TOTAL LIABILITIES AND CAPITALIZATION .......................... $ 8,183,320 $ 7,987,039
* Unaudited See Notes to Consolidated Financial Statements. PART I. FINANCIAL INFORMATION (Continued) CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1994 1993 (In Thousands) Cash Flows From Operating Activities Net income ................................................... $ 275,469 $ 278,730 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization .............................. 266,945 231,097 Deferred income taxes ...................................... 64,896 50,723 Investment tax credit adjustments .......................... (6,142) (6,335) Deferred fuel costs ........................................ 4,536 52,361 Accrued pension and postemployment benefits ................ (44,210) 9,910 Allowance for equity funds used during construction......... (16,180) (10,690) Equity in earnings of affiliates and joint ventures (12,551) (2,375) Changes in current assets ......................... (42,073) (122,238) Changes in current liabilities, other than short-te......... (6,296) 37,994 Other ...................................................... 24,105 (12,649) Net cash provided by operating activities .................... 508,499 506,528 Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings (net) ................................ 69,400 (11,900) Long-term debt ............................................. 207,018 1,030,995 Preference stock ........................................... (4) 89,213 Common stock ............................................... 33,762 44,490 Reacquisition of long-term debt .............................. (238,571) (962,238) Redemption of preference stock ............................... (2,906) (102,410) Common stock dividends paid .................................. (164,092) (157,275) Preferred and preference stock dividends paid ................ (29,970) (32,217) Other ........................................................ (214) (623) Net cash used in financing activities ........................ (125,577) (101,965) Cash Flows From Investing Activities Utility construction expenditures ............................ (344,993) (309,948) Allowance for equity funds used during construction .......... 16,180 10,690 Nuclear fuel expenditures .................................... (38,337) (33,501) Deferred nuclear expenditures ................................ (5,674) (7,972) Deferred energy conservation expenditures .................... (29,712) (21,170) Contributions to nuclear decommissioning trust fund .......... (7,335) (6,675) Purchases of marketable equity securities .................... (43,505) (24,756) Sales of marketable equity securities ........................ 25,418 24,715 Other financial investments .................................. 2,751 30,830 Real estate projects ......................................... 21,048 (21,433) Power generation systems ..................................... (2,330) (22,692) Other ........................................................ 559 (938) Net cash used in investing activities ........................ (405,930) (382,850) ......... Net Increase (Decrease) in Cash and Cash Equivalents ........... (23,008) 21,713 Cash and Cash Equivalents at Beginning of Period ...... 84,236 27,122 ......... Cash and Cash Equivalents at End of Period ............ $ 61,228 $ 48,835 Other Cash Flow Information Cash paid during the period for: ......... Interest (net of amounts capitalized) ...................... $ 137,982 $ 139,912 Income taxes ............................................... $ 58,408 $ 57,910 Certain prior-year amounts have been restated to conform with the current year's presentation. See Notes to Consolidated Financial Statements.
PART I. FINANCIAL INFORMATION (Continued) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Results for interim periods, which can be largely influenced by weather conditions, are not necessarily indicative of results to be expected for the year. The preceding interim financial statements of Baltimore Gas and Electric Company (BGE) and Subsidiaries (collectively, the Company) reflect all adjustments which are, in the opinion of Management, necessary for the fair presentation of the Company's financial position and results of operations for such interim periods. These adjustments are of a normal recurring nature. Effective July 1, 1994, BGE formed a wholly owned subsidiary, BGE Home Products & Services, Inc. (HPS), consisting of BGE's existing merchandise and gas and appliance service operations. HPS' revenues and expenses are included in diversified businesses revenues and diversified businesses selling, general and administrative expenses, respectively. Prior-period amounts have been restated to conform with the current year's presentation. Statement of Financial Accounting Standards No. 115 The Company adopted Statement of Financial Accounting Standards No. 115 (Statement No. 115), "Accounting for Certain Investments in Debt and Equity Securities," effective January 1, 1994. As of September 30, 1994, marketable equity securities totaling $48.5 million, which are included in financial investments in the consolidated balance sheets, and the nuclear decommissioning trust fund have been classified as available-for- sale in accordance with the requirements of Statement No. 115. Changes in the fair value of these securities are included in common shareholders' equity. Long-term Debt of BGE The following is a summary of issuances and early redemptions of long-term debt that have occurred or have been announced during the period January 1, 1994 through the date of this Report. The net proceeds from the new issuances were used for general corporate purposes relating to BGE's utility business, including the redemptions. Gains and losses on the reacquisition of debt are amortized over the remaining original lives of the issuances. Principal Amount Issue Net Issuances Issued Date Proceeds (Amounts in Thousands) First Refunding Mortgage Bonds Floating Rate Series due 4/15/99 $125,000 3/21/94 $124,438 6.00% Pollution Control Revenue Refunding Loan due 4/1/24 75,000 4/14/94 73,971 6 PART I. FINANCIAL INFORMATION (Continued) Redemption Price as a Principal % of the Amount Redemption Principal Early Redemptions Redeemed Date Amount (Amounts in Thousands) First Refunding Mortgage Bonds: 7 1/4% Series due 4/15/01 $59,911 3/11/94 101.88% 6.80% Series due 9/15/04 20,000 4/14/94 101.00 6.90% Installment Series due 9/15/09 55,000 4/14/94 101.00 7% Series due 1998 28,638 4/18/94 101.11 In addition, in connection with the annual sinking fund required by BGE's mortgage, on August 1, 1994, the following principal amounts of First Refunding Mortgage Bonds were redeemed: $11,986,000 of the 9-1/8% Series due October 15, 1995, $3,775,000 of the 8.40% Series due October 15, 1999, $2,550,000 of the 8-3/8% Series due August 15, 2001, and $473,000 from various other series. Diversified Business Financing Matters See Management's Discussion and Analysis of Financial Condition and Results of Operations - Diversified Businesses Capital Requirements for additional information about the debt of the Constellation Company and its subsidiaries. Environmental Matters The Clean Air Act of 1990 (the Act) contains provisions designed to reduce sulfur dioxide and nitrogen oxide (NOx) emissions from electric generating stations in two separate phases. Under Phase I of the Act, which must be implemented by 1995, BGE expects to incur expenditures of approximately $55 million, most of which are attributable to its portion of the cost of installing a flue gas desulfurization system at the Conemaugh generating station, in which BGE owns a 10.56% interest. BGE is currently examining what actions will be required in order to comply with Phase II of the Act, which must be implemented by 2000. However, BGE anticipates that compliance will be attained by some combination of fuel switching, flue gas desulfurization, unit retirements, or allowance trading. At this time, plans for complying with NOx control requirements under the Act are less certain because all implementation regulations have not yet been finalized by the government. It is expected that by the year 1999 these regulations will require additional NOx controls for ozone attainment at BGE's generating plants and at other BGE facilities. The controls will result in additional expenditures 7 PART I. FINANCIAL INFORMATION (Continued) that are difficult to predict prior to the issuance of such regulations. Based on existing and proposed ozone nonattainment regulations, BGE currently estimates that the NOx controls at BGE's generating plants will cost approximately $70 million. BGE is currently unable to predict the cost of compliance with the additional requirements at other BGE facilities. BGE has been notified by the Environmental Protection Agency and several state agencies that it is being considered a potentially responsible party with respect to the cleanup of certain environmentally contaminated sites owned and operated by third parties. Although the cleanup costs for certain environmentally contaminated sites could be significant, BGE believes that the resolution of these matters will not have a material effect on its financial position or results of operations. Also, BGE is coordinating investigation of several former gas manufacturing plant sites, including exploration of corrective action options to remove coal tar. However, no formal legal proceedings have been instituted. As of September 30, 1994, BGE has an accrual of approximately $27 million for estimated future environmental costs at these sites. Based on previous actions of the Public Service Commission of Maryland (PSC), BGE has deferred these estimated future costs, as well as actual costs which have been incurred to date, as a regulatory asset. The technology for cleaning up such sites is still developing, and potential remedies for these sites have not been identified. Cleanup costs in excess of the amounts recognized, which could be significant in total, cannot presently be estimated. Nuclear Insurance An accident or an extended outage at either unit of the Calvert Cliffs Nuclear Power Plant could have a substantial adverse effect on BGE. The primary contingencies resulting from an incident at the Calvert Cliffs plant would involve the physical damage to the plant, the recoverability of replacement power costs, and BGE's liability to third parties for property damage and bodily injury. BGE maintains various insurance policies for these contingencies. In the past, BGE had purchased all available insurance for these contingencies. However, BGE decided not to purchase additional property insurance that recently became available because the added premium expense appeared high relative to the risk being covered. The costs that could result from a major accident or an extended outage at either of the Calvert Cliffs units could exceed the coverage limits. In addition, in the event of an incident at any commercial nuclear power plant in the country, BGE could be assessed for a portion of any third party claims associated with the incident. Under the provisions of the Price Anderson Act, the limit for third party claims from a nuclear incident is $9.0 billion. If third party claims relating to such an incident exceed $200 million (the amount of primary insurance), BGE's share of the total liability for third party claims could be up to $159 8 PART I. FINANCIAL INFORMATION (Continued) million per incident, that would be payable at a rate of $20 million per year. BGE and other operators of commercial nuclear power plants in the United States are required to purchase insurance to cover claims of certain nuclear workers. Other non-governmental commercial nuclear facilities may also purchase such insurance. Coverage of up to $400 million is provided for claims against BGE or others insured by these policies for radiation injuries. If certain claims were made under these policies, BGE and all policyholders could be assessed, with BGE's share being up to $6.2 million in any one year. For physical damage to Calvert Cliffs, BGE has $2.75 billion of property insurance, including $1.4 billion from an industry mutual insurance company. If accidents at any insured plants cause a shortfall of funds at the industry mutual, BGE and all policyholders could be assessed, with BGE's share being up to $14.6 million. If an outage at Calvert Cliffs is caused by an insured physical damage loss and lasts more than 21 weeks, BGE has up to $426 million per unit of insurance, provided by a different industry mutual insurance company for replacement power costs. This amount can be reduced by up to $85 million per unit if an outage to both units at Calvert Cliffs is caused by a singular insured physical damage loss. If an outage at any insured plant causes a shortfall of funds at the industry mutual, BGE and all policyholders could be assessed, with BGE's share being up to $9.4 million. Recoverability of Electric Fuel Costs By statute, actual electric fuel costs are recoverable so long as the PSC finds that BGE demonstrates that, among other things, it has maintained the productive capacity of its generating plants at a reasonable level. The PSC and Maryland's highest appellate court have interpreted this as permitting a subjective evaluation of each unplanned outage at BGE's generating plants to determine whether or not BGE had implemented all reasonable and cost-effective maintenance and operating control procedures appropriate for preventing the outage. Effective January 1, 1987, the PSC authorized the establishment of a Generating Unit Performance Program (GUPP) to measure, annually, utility compliance with maintaining the productive capacity of generating plants at reasonable levels by establishing a system-wide generating performance target and individual performance targets for each base load generating unit. In future fuel rate hearings, actual generating performance after adjustment for planned outages will be compared to the system-wide target and, if met, should signify that BGE has complied with the requirements of Maryland law. Failure to meet the system-wide target will result in review of each unit's adjusted actual generating performance versus its performance 9 PART I. FINANCIAL INFORMATION (Continued) target in determining compliance with the law and the basis for possibly imposing a penalty on BGE. Parties to fuel rate hearings may still question the prudence of BGE's actions or inactions with respect to any given generating plant outage, which could result in the disallowance of replacement energy costs by the PSC. Since the two units at BGE's Calvert Cliffs Nuclear Power Plant utilize BGE's lowest cost fuel, replacement energy costs associated with outages at these units can be significant. BGE cannot estimate the amount of replacement energy costs that could be challenged or disallowed in future fuel rate proceedings, but such amounts could be material. In October 1988, BGE filed its first fuel rate application for a change in its electric fuel rate under GUPP. The resultant case before the PSC covers BGE's operating performance in calendar year 1987, and BGE's filing demonstrated that it met the system-wide and individual nuclear plant performance targets for 1987. In November 1989, testimony was filed on behalf of the Maryland People's Counsel (People's Counsel) alleging that seven outages at the Calvert Cliffs plant in 1987 were due to management imprudence and that the replacement energy costs associated with those outages should be disallowed by the Commission. Total replacement energy costs associated with the 1987 outages were approximately $33 million. In May 1989, BGE filed its fuel rate case in which 1988 performance was examined. BGE met the system-wide and nuclear plant performance targets in 1988. People's Counsel alleged that BGE imprudently managed several outages at Calvert Cliffs, and BGE estimates that the total replacement energy costs associated with these 1988 outages were approximately $2 million. On November 14, 1991, a Hearing Examiner at the PSC issued a proposed Order, which became final on December 17, 1991 and concluded that no disallowance was warranted. The Hearing Examiner found that BGE maintained the productive capacity of the Plant at a reasonable level, noting that it produced a near record amount of power and exceeded the GUPP standard. Based on this record, the Order concluded there was sufficient cause to excuse any avoidable failures to maintain productive capacity at higher levels. During 1989, 1990, and 1991, BGE experienced extended outages at its Calvert Cliffs Nuclear Power Plant. In the Spring of 1989, a leak was discovered around the Unit 2 pressurizer heater sleeves during a refueling outage. BGE shut down Unit 1 as a precautionary measure on May 6, 1989, to inspect for similar leaks and none were found. However, Unit 1 was out of service for the remainder of 1989 and 285 days of 1990 to undergo maintenance and modification work to enhance the reliability of various safety systems, to repair equipment, and to perform required periodic surveillance tests. Unit 2, which returned to service on May 4, 1991, remained out of service for the remainder 10 PART I. FINANCIAL INFORMATION (Continued) of 1989, 1990, and the first part of 1991 to repair the pressurizer, perform maintenance and modification work, and complete the refueling. The replacement energy costs associated with these extended outages for both units at Calvert Cliffs, concluding with the return to service of Unit 2, are estimated to be $458 million. In a December 1990 order issued by the PSC in a BGE base rate proceeding, the PSC found that certain operations and maintenance expenses incurred at Calvert Cliffs during the test year should not be recovered from ratepayers. The PSC found that this work, which was performed during the 1989-1990 Unit 1 outage and fell within the test year, was avoidable and caused by BGE actions which were deficient. The PSC noted in the order that its review and findings on these issues pertain to the reasonableness of BGE's test-year operations and maintenance expenses for purposes of setting base rates and not to the responsibility for replacement power costs associated with the outages at Calvert Cliffs. The PSC stated that its decision in the base rate case will have no res judicata (binding) effect in the fuel rate proceeding examining the 1989- 1991 outages. The work characterized as avoidable significantly increased the duration of the Unit 1 outage. Despite the PSC's statement regarding no binding effect, BGE recognizes that the views expressed by the PSC make the full recovery of all of the replacement energy costs associated with the Unit 1 outage doubtful. Therefore, in December 1990, BGE recorded a provision of $35 million against the possible disallowance of such costs. BGE cannot determine whether replacement energy costs may be disallowed in the present fuel rate proceeding in excess of the provision, but such amounts could be material. 11 PART I. FINANCIAL INFORMATION (Continued) MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The financial condition and results of operations of Baltimore Gas and Electric Company (BGE) and its subsidiaries (collectively, the Company) are set forth in the Consolidated Financial Statements and Notes to Consolidated Financial Statements (Notes) sections of this Report. Factors significantly affecting results of operations, liquidity, and capital resources are discussed below. RESULTS OF OPERATIONS FOR THE QUARTER AND NINE MONTHS ENDED SEPTEMBER 30, 1994 COMPARED WITH THE CORRESPONDING PERIODS OF 1993 Earnings per Share of Common Stock Consolidated earnings per share for the quarter and nine months ended September 30, 1994 were $.79 and $1.67, respectively, which represent decreases of $.22 and $.04 compared to the earnings for the corresponding periods of 1993. These decreases in earnings per share reflect a lower level of earnings applicable to common stock and a slight increase in the number of common shares outstanding. The earnings per share are summarized as follows: Quarter Ended Nine Months Ended September 30 September 30 1994 1993 1994 1993 Utility operations............. $.75 $.99 $1.61 $1.65 Diversified businesses......... .04 .02 .06 .06 Total.......................... $.79 $1.01 $1.67 $1.71 Earnings Applicable to Common Stock Earnings applicable to common stock decreased $29.8 million during the quarter and $1.6 million during the nine months ended September 30, 1994. These decreases are the result of lower earnings from utility operations. Earnings from utility operations decreased during the third quarter of 1994 primarily as a result of lower sales of electricity due to cooler late summer weather and the write-off of a portion of the construction work in progress at BGE's Perryman site. These factors were offset partially by labor savings achieved through the Company's employee reduction programs and a moderate increase in the number of electric customers. The effect of weather on utility sales is discussed 12 PART I. FINANCIAL INFORMATION (Continued) on pages 13 and 14. The Perryman write-off is discussed on pages 20 and 21. Earnings from utility operations decreased during the nine months ended September 30, 1994 due to the factors noted above for the third quarter of 1994, offset partially by increased electric system sales as a result of significantly hotter weather during the spring and early summer and increased electric system and gas sales caused by colder winter weather in 1994. The following factors influence BGE's utility operations earnings: regulation by the Public Service Commission of Maryland (PSC), the effect of weather and economic conditions on sales, and competition in the generation and sale of electricity. The base rate increases authorized by the PSC in April 1993 favorably affected utility earnings through April 1994. Several electric fuel rate cases now pending before the PSC discussed in Notes 1 and 13 of the Form 10-K for the year ended December 31, 1993 (Form 10-K) could also affect future years' earnings. Electric utilities presently face competition in the construction of generating units to meet future load growth and in the sale of electricity in the bulk power markets. Electric utilities also face the future prospect of competition for electric sales to retail customers. It is not possible to predict currently the ultimate effect competition will have on BGE's earnings in future years. Earnings from diversified businesses, which primarily represent the operations of Constellation Holdings, Inc. and its subsidiaries (collectively, the Constellation Companies) and BGE Home Products & Services, Inc. (HPS), were higher during the quarter and unchanged for the nine months ended September 30, 1994. Diversified businesses' earnings are discussed on pages 21 through 23. Effect of Weather on Utility Sales Weather conditions affect BGE's utility sales. BGE measures weather conditions using degree days. A degree day is the difference between the average daily actual temperature and the baseline temperature of 65 degrees. Colder weather during the winter, as measured by greater heating degree days, results in greater demand for electricity and gas to operate heating systems. Conversely, warmer weather during the winter, measured by fewer heating degree days, results in less demand for electricity and gas to operate heating systems. Hotter weather during the summer, measured by more cooling degree days, results in greater demand for electricity to operate cooling systems. Conversely, cooler weather during the summer, measured by fewer cooling degree days, results in less demand for electricity to operate cooling systems. The degree-days chart on the following 13 PART I. FINANCIAL INFORMATION (Continued) page presents information regarding heating and cooling degree days for the quarter and nine months ended September 30, 1994 and 1993. Quarter Ended Nine Months Ended September 30 September 30 1994 1993 1994 1993 Heating degree days............ 79 883,275 3,192 Percent change compared to prior period.................. (10.2)% 2.6% Cooling degree days............ 615 640 935 853 Percent change compared to prior period.................. (3.9)% 9.6% BGE Utility Revenues and Sales Electric revenues changed during 1994 because of the following factors: Quarter Ended Nine Months Ended September 30 September 30 1994 vs. 1993 1994 vs. 1993 (In millions) System sales volumes.......... $(31.3) $22.6 Base rates.................... (9.3) 6.1 Fuel rates.................... (7.6) (17.0) Revenues from system sales.... (48.2) 11.7 Interchange sales............. 10.2 23.8 Other revenues................ 0.6 (0.8) Total......................... $(37.4) $34.7 Electric system sales represent volumes sold to customers within BGE's service territory at rates determined by the PSC. These amounts exclude interchange sales, discussed separately later. As of December 31, 1993, BGE changed its classification of commercial and industrial customers to present this information on a basis which is more consistent with predominant industry practices. Prior-period amounts have been reclassified to conform to the current period's presentation. Below is a comparison of the changes in electric system sales volumes. 14 PART I. FINANCIAL INFORMATION (Continued) Quarter Ended Nine Months Ended September 30 September 30 1994 vs. 1993 1994 vs. 1993 Residential................... (6.5)% 2.9% Commercial.................... (3.4) (0.2) Industrial.................... 15.1 17.1 Total......................... (2.3) 3.4 Cooler weather in the third quarter of 1994 as compared to the third quarter of 1993 produced the overall decrease in sales to electric customers. This decrease was offset partially by moderate customer growth. Sales to industrial customers reflect an increase in the sale of electricity to Bethlehem Steel, which purchased more electricity from BGE due to increased steel production and the fact that Bethlehem Steel is now purchasing its full electricity requirements from BGE. Bethlehem Steel is still producing power with its own generating facility, but is now selling the output from this facility to BGE rather than using the power to reduce its requirements. Electric system sales for the nine months ended September 30, 1994 reflect the positive impact of hotter spring and early summer weather and severe winter weather conditions during 1994, partially offset by the factors noted above for the third quarter. Sales to commercial customers also reflect a decline in usage-per-customer. Base rates are affected by two principal items: the PSC's April 1993 rate order and recovery of eligible electric conservation program costs through the energy conservation surcharge. The April 1993 rate order provided for an annualized electric base rate increase of $84.9 million including a return on BGE's higher level of electric rate base. The order also reduced the authorized rate of return to 9.40% from the previous rate of 9.94%. Base rates decreased during the quarter ended September 30, 1994 due to the continuing deferral of the portion of conservation surcharge billings subject to refund, as described below. Base rates increased during the nine months ended September 30, 1994 due to the remaining favorable impact of the April 1993 rate order on results for the first four months of the year. Base rate revenues are expected to decrease during the remainder of 1994 compared to 1993 as a result of the continued deferral of a portion of conservation surcharge revenues. If the PSC determines that BGE is earning in excess of its authorized rate of return, BGE will have to refund (by means of lowering future surcharges) a portion of energy conservation surcharge revenues to its customers. The portion subject to the refund is compensation for foregone sales from conservation programs and 15 PART I. FINANCIAL INFORMATION (Continued) incentives for achieving conservation goals. BGE earned in excess of its authorized rate of return on electric operations for the period September 30, 1993 through June 30, 1994. As a result, BGE deferred the portion of electric energy conservation revenues subject to refund beginning in December 1993. The deferral of these billings has averaged approximately $1.7 million each month and is expected to cease after November 1994. The amounts deferred during a surcharge year will begin to be refunded to customers with interest in the ensuing July when the annual resetting of the conservation surcharge rates occurs. Changes in fuel rate revenues result from the operation of the electric fuel rate formula. The fuel rate formula is designed to recover the actual cost of fuel, net of revenues from interchange sales. (See Notes 1 and 13 of the Form 10-K.) Changes in fuel rate revenues and interchange sales normally do not affect earnings. However, if the PSC was to disallow recovery of any part of these costs, earnings would be reduced as discussed in Note 13 of the Form 10-K. Fuel rate revenues decreased during the third quarter of 1994 as a result of decreased electric system sales volumes and a lower fuel rate. Fuel rate revenues decreased during the nine months ended September 30, 1994 due to a lower fuel rate, offset partially by increased electric system sales volumes. The fuel rate was lower because of a less costly twenty-four month generation mix due to greater generation at the Calvert Cliffs Nuclear Power Plant compared to 1993. BGE expects electric fuel rate revenues will decrease during the remainder of 1994 because of a less-costly twenty-four month generation mix. Interchange sales are sales of BGE's energy to the Pennsylvania - New Jersey - Maryland Interconnection (PJM), a regional power pool of eight member companies including BGE. Interchange sales occur after BGE has satisfied the demand for its own system sales of electricity if BGE's available generation is the least costly available to PJM utilities. Interchange sales increased during the quarter and nine months ended September 30, 1994 because BGE had a less costly generation mix than other PJM utilities. The less costly mix relative to other PJM companies during 1994 reflects greater generation from the Brandon Shores Power Plant and continued operation of the Calvert Cliffs Nuclear Power Plant. 16 PART I. FINANCIAL INFORMATION (Continued) Gas revenues increased during 1994 because of the following factors: Quarter Ended Nine Months Ended September 30 September 30 1994 vs. 1993 1994 vs. 1993 (In millions) Sales volumes................. $2.8 $7.9 Base rates.................... 0.4 1.5 Gas cost adjustment revenues.. (0.9) 9.2 Other revenues................ (0.4) (1.4) Total......................... $1.9 $17.2 As of December 31, 1993, BGE changed its classification of commercial and industrial customers to present this information on a basis which is more consistent with predominant industry practices. Prior-period amounts have been reclassified to conform to the current period's presentation. Below is a comparison of the changes in gas sales volumes: Quarter Ended Nine Months Ended September 30 September 30 1994 vs. 1993 1994 vs. 1993 Residential................... 7.4% 6.5% Commercial.................... 7.8 (2.0) Industrial.................... 18.8 2.5 Total......................... 13.8 2.6 Gas sales for the quarter ended September 30, 1994 increased for all classes of customers as compared with the same period in 1993. Sales to residential and commercial customers increased due to greater usage-per-customer and an increase in the number of customers. Sales to industrial customers increased due to greater usage of delivery service gas by Bethlehem Steel. Total gas sales for the nine months ended September 30, 1994 were higher compared to 1993 because of higher sales to residential and industrial customers were offset partially by lower sales to commercial customers. The increase in sales to residential customers reflects the colder winter weather during the first quarter of 1994 as compared to 1993, and to a lesser extent customer growth. Sales to industrial customers reflects primarily the greater usage of natural gas by Bethlehem Steel in its production process. Sales to commercial and industrial customers were negatively impacted because delivery service customers either voluntarily switched their fuel source from natural gas to alternate fuels, or were involuntarily interrupted by BGE as a result of the extreme winter weather conditions. Interruptible customers maintain alternate fuel sources and pay reduced rates 17 PART I. FINANCIAL INFORMATION (Continued) in exchange for BGE's right to interrupt service during periods of peak demand. Base rates increased slightly in 1994 due to an increased recovery of eligible gas conservation program costs through the energy conservation surcharge. The continued recovery of gas conservation program costs under the energy conservation surcharge will continue to increase base rate revenues during the remainder of 1994. Changes in gas cost adjustment revenues result primarily from the operation of the purchased gas adjustment clause, commodity charge adjustment clause, and the actual cost adjustment clause which are designed to recover actual gas costs. (See Note 1 of the Form 10-K.) Changes in gas cost adjustment revenues normally do not affect earnings. Gas cost adjustment revenues decreased slightly during the third quarter of 1994 because of lower prices for purchased gas, offset partially by higher sales volumes subject to gas cost adjustment clauses. During the nine months ended September 30, 1994, gas cost adjustment revenues increased over last year due to the combination of higher sales volumes subject to gas cost adjustment clauses and increased prices of purchased gas during the first quarter. Delivery service sales volumes are not subject to gas cost adjustment clauses because these customers purchase their gas directly from third parties. BGE Utility Fuel and Energy Expenses Electric fuel and purchased energy expenses were as follows: Quarter Ended Nine Months Ended September 30 September 30 1994 1993 1994 1993 (In millions) Actual costs.................. $141.5 $131.9 $414.7 $359.7 Net (deferral) recovery of costs under electric fuel rate clause (see Note 1 of the Form 10-K)............... 6.6 11.5 (19.1) 27.7 Total......................... $148.1 $143.4 $395.6 $387.4 Electric fuel and purchased energy expenses increased during the quarter and nine months ended September 30, 1994 due to increases in actual fuel costs, offset partially by the impact on expenses of changes in deferred fuel costs as a result of the operation of the electric fuel rate clause. 18 PART I. FINANCIAL INFORMATION (Continued) Actual electric fuel and purchased energy costs increased for the quarter and nine months ended September 30, 1994 as a result of a more costly actual generation mix and, during the nine months ended September 30, 1994, due to an increase in the net output of electricity generated to meet the demand of BGE's system and the PJM system. The cost of the actual generation mix increased due to refueling and maintenance outages at the Calvert Cliffs Nuclear Power Plant and, during the first quarter of 1994, higher purchased energy costs. Purchased gas expenses were as follows: Quarter Ended Nine Months Ended September 30 September 30 1994 1993 1994 1993 (In millions) Actual costs.................. $21.4 $25.4 $174.6 $166.9 Net (deferral) recovery of costs under purchased gas adjustment clause (see Note 1 of the Form 10-K)................... (1.5) (4.2) 3.8 3.8 Total......................... $19.9 $21.2 $178.4 $170.7 Actual purchased gas costs decreased during the quarter ended September 30, 1994 as the result of lower gas prices, offset partially by higher output associated with increased demand for BGE gas. The lower gas prices primarily reflect favorable market conditions and additional take-or-pay refunds (discussed below). Actual purchased gas costs increased during the nine months ended September 30, 1994. This increase was due to higher gas prices and to a lesser extent the higher output associated with the increased demand for BGE gas during the first quarter. The higher gas prices reflect primarily higher reservation charges, greater transition costs related to the implementation of Federal Energy Regulatory Commission (FERC) Order No. 636, and market conditions, offset partially by take-or-pay and other supplier refunds. The take-or-pay refunds primarily represent a $16.6 million refund received during the second quarter of 1994 from Columbia Gas Transmission Corporation (Columbia Gas). The refund resulted from a FERC action regarding the reallocation of take-or-pay amounts charged to BGE by Columbia Gas between September 1988 and December 1990. This refund is being returned to BGE's gas customer's over a twelve-month period beginning in June 1994 pursuant to an agreement with the PSC. 19 PART I. FINANCIAL INFORMATION (Continued) Purchased gas costs exclude gas purchased by delivery service customers, including Bethlehem Steel, who obtain gas directly from third parties. Future purchased gas costs are expected to continue to increase due to additional transition costs incurred by BGE's gas pipeline suppliers. These transition costs, if approved by FERC, will be passed on to BGE's customers through the purchased gas adjustment clause. Other Operating Expenses Operations expense decreased during the quarter ended September 30, 1994 due primarily to decreased labor costs as a result of the Company's employee reduction programs. The decrease was offset partially by the higher amortization of the deferred Voluntary Special Early Retirement Program (VSERP) costs (see Note 7 of the Form 10-K). Operations expense increased for the nine months ended September 30, 1994 because the nine months ended September 30, 1993 reflected a credit to utility operations expense equivalent to the $9.8 million cost of termination benefits associated with the Company's 1992 VSERP program. In addition, operations expense for 1994 reflects a $10.0 million one-time bonus paid to employees in lieu of a general wage increase. In June 1994, BGE reclassified the amortization of deferred energy conservation expenditures and deferred nuclear expenditures from operations expense to depreciation and amortization expense. In addition, BGE reclassified diversified businesses' expenses from operations expense to diversified businesses - selling, general, and administrative expense. Prior- period amounts have been restated to conform with the current presentation. Operations expense is expected to be reduced during the remainder of 1994 due to continued cost savings realized from the 1993 employee reduction programs and the absence of the December 1993 one-time cost of employee reduction programs. These lower costs are expected to exceed the continued increase in the amortization of deferred VSERP costs and other increases in operations expenses. Maintenance expense decreased during the quarter and nine months ended September 30, 1994 due primarily to lower costs at the Calvert Cliffs Nuclear Power Plant. Depreciation and amortization expense increased during the quarter and nine months ended September 30, 1994 because of the write-off of certain Perryman costs discussed below, higher levels of energy conservation program costs, higher depreciable plant in service, and amortization of deferred environmental 20 PART I. FINANCIAL INFORMATION (Continued) costs for certain Company-owned sites beginning in October 1993 (see Environmental Matters on page 24). The increase in depreciable plant in service resulted from the addition of electric transmission and distribution plant and certain capital additions at the Calvert Cliffs Nuclear Power Plant during 1994 and 1993. Initially, BGE had planned to build two combined cycle generating units at its Perryman site. However, due to significant changes in the environment in which utilities operate, BGE now has no plans to construct the second combined cycle generating unit. Accordingly, during the third quarter of 1994, BGE wrote off $15.7 million of the costs associated with that second combined cycle unit. This write-off reduced after-tax earnings for the quarter and the nine months ended September 30, 1994 by $11 million, or 7 cents per share. Other Income and Expenses The allowance for funds used during construction (AFC) increased during the quarter and nine months ended September 30, 1994 because of a higher level of construction work in progress which was offset partially by the lower AFC rate established by the PSC in the April 1993 rate order. Capitalized interest decreased during the quarter and nine months ended September 30, 1994 due to lower capitalized interest on the Constellation Companies' power generation systems projects. The decrease during the nine month period was offset partially by BGE beginning to accrue carrying charges on electric deferred fuel costs excluded from rate base. (See Note 5 of the Form 10-K.) Income tax expense decreased during the quarter ended September 30,1994 because of lower taxable income and increased for the nine months ended September 30, 1994 because of higher taxable income. Diversified Businesses Earnings Earnings per share from diversified businesses were: Quarter Ended Nine Months Ended September 30 September 30 1994 1993 1994 1993 Power generation systems...... $.05 $.03 $.06 $.07 Financial investments......... .00 .05 .02 .08 Real estate development and senior living facilities..... (.01) (.02) (.02) (.05) 21 PART I. FINANCIAL INFORMATION (Continued) Effect of 1993 Tax Act........ .00 (.04) .00 (.04) Total......................... $.04 $.02 $.06 $.06 The Constellation Companies' power generation systems business includes the development, ownership, management, and operation of wholesale power generating projects in which the Constellation Companies hold ownership interests, as well as the provision of services to power generation projects under operation and maintenance contracts. Power generation systems earnings were higher for the quarter ended September 30, 1994 than the same period of 1993 due to higher earnings on various energy projects, and the effect of $2 million in after-tax charges related to fuel supply problems at the Panther Creek waste-coal project during 1993. Power generation systems earnings were lower for the nine months ended September 30, 1994 as 1993 results included the recognition of $8 million of energy tax credits related to the Puna geothermal plant, offset partially by total after-tax charges of $6 million related to fuel supply problems at the Panther Creek waste-coal project. The Constellation Companies' investment in wholesale power generating projects includes $170 million representing ownership interests in 16 projects that sell electricity in California under Interim Standard Offer No. 4 power purchase agreements. Under these agreements, the projects supply electricity to purchasing utilities at a fixed rate for the first ten years of the agreements and at variable rates based on the utilities' avoided cost for the remaining term of the agreements. Avoided cost generally represents a utility's next lowest cost generation to service the demands on its system. These power generation projects are scheduled to convert to supplying electricity at avoided cost rates in various years beginning in late 1996 through the end of 2000. As a result of declines in purchasing utilities' avoided costs subsequent to the inception of these agreements, revenues at these projects based on current avoided cost levels would be substantially lower than revenues presently being realized under the fixed price terms of the agreements. If current avoided cost levels were to continue into 1996 and beyond, the Constellation Companies could experience reduced earnings or incur losses associated with these projects, which could be significant. The Constellation Companies are investigating and pursuing alternatives for certain of these power generation projects including, but not limited to, repowering the projects to reduce operating costs, renegotiating the power purchase agreements, and selling its ownership interests in the projects. Two of these wholesale power generating projects, in which the Constellation Companies' investment totals $25.1 million, have executed agreements with Pacific Gas & Electric (PG&E) providing for the curtailment of output through the end of the fixed price period in return for payments from PG&E. The payments from PG&E during the curtailment period will be sufficient to fully amortize the existing project finance debt. However, following the curtailment period, the projects remain contractually obligated 22 PART I. FINANCIAL INFORMATION (Continued) to commence production of electricity at the avoided cost rates, which could result in reduced earnings or losses for the reasons described above. The Company cannot predict the impact that these matters regarding any of the 16 projects may have on the Constellation Companies or the Company, but the impact could be material. Earnings from the Constellation Companies' portfolio of financial investments include capital gains and losses, dividends, income from financial limited partnerships, and income from financial guaranty insurance companies. Financial investment earnings were lower for the quarter and nine months ended September 30, 1994 as the third quarter of 1993 reflected a gain from the sale of a portion of an investment in a financial guaranty insurance company. The Constellation Companies' real estate development business includes land under development; office buildings; retail projects; commercial projects; an entertainment, dining and retail complex in Orlando, Florida; a mixed-use planned-unit- development; and senior living facilities. The majority of these projects are in the Baltimore-Washington corridor. They have been affected adversely by the depressed real estate market and economic conditions, resulting in reduced demand for the purchase or lease of available land, office, and retail space. Earnings from real estate development and senior living facilities for the nine months ended September 30, 1994 increased due to gains recognized from the sale of two retail centers, an office building and Constellation's interests in two senior living facilities. The increases in diversified businesses' revenues and in selling, general and administrative expenses for the nine months ended September 30, 1994 reflect the proceeds of these sales and the cost of the facilities sold, respectively. The Constellation Companies' real estate portfolio has experienced continuing carrying costs and depreciation. During 1991, the Constellation Companies began expensing rather than capitalizing interest on certain undeveloped land where development activities were at minimal levels. These factors have affected earnings negatively during 1994 and 1993 and are expected to continue to do so until current market conditions improve. Cash flow from real estate operations has been insufficient to cover the debt service requirements of certain of these projects. Resulting cash shortfalls have been satisfied through cash infusions from Constellation Holdings, Inc., which obtained the funds through a combination of cash flow generated by other Constellation Companies and its corporate borrowings. Until the real estate market shows sustained improvement, earnings from real estate activities are expected to remain depressed. The Constellation Companies continued investment in real estate projects is a function of market demand, interest rates, credit availability, and the strength of the economy in general. 23 PART I. FINANCIAL INFORMATION (Continued) The Constellation Companies' Management believes that although the real estate market is beginning to show signs of improvement, until the economy reflects sustained growth and the excess inventory in the market in the Baltimore-Washington corridor goes down, real estate values will not improve significantly. If the Constellation Companies were to sell their real estate projects in the current depressed market, losses would occur in amounts difficult to determine. Depending upon market conditions, future sales could also result in losses. In addition, were the Constellation Companies to change their intent about any project from an intent to hold until market conditions improve to an intent to sell, applicable accounting rules would require a write-down of the project to market value at the time of such change in intent if market value is below book value. Earnings from the Constellation Companies increased during the quarter and nine months ended September 30, 1994 because the same periods of 1993 reflect a $6.0 million charge to income tax expense for the impact of the 1993 Tax Act. Environmental Matters The Company is subject to increasingly stringent federal, state, and local laws and regulations relating to improving or maintaining the quality of the environment. These laws and regulations require the Company to remove or remedy the effect on the environment of the disposal or release of specified substances at ongoing and former operating sites, including Environmental Protection Agency Superfund sites. Details regarding these matters, including financial information, are presented in the Environmental Matters section on pages 7, 8, and 30 of this Report. LIQUIDITY AND CAPITAL RESOURCES Liquidity For the twelve months ended September 30, 1994, the Company's ratio of earnings to fixed charges and ratio of earnings to combined fixed charges and preferred and preference dividend requirements were 3.04 and 2.39, respectively. Capital Requirements The Company's capital requirements reflect the capital- intensive nature of the utility business. Actual capital requirements for the nine months ended September 30, 1994, along with estimated annual amounts for the years 1994 through 1996, are reflected on the following page. 24 PART I. FINANCIAL INFORMATION (Continued) Nine Months Ended September 30 Calendar Year Estimate 1994 1994 1995 1996 (In millions) Utility Business: Construction expenditures (excluding AFC) Electric........................ $251 $350 $231 $219 Gas............................. 44 55 63 71 Common.......................... 25 45 56 50 Total construction expenditures. 320 450 350 340 AFC............................. 25 34 34 20 Deferred nuclear expenditures... 6 13 - - Deferred energy conservation expenditures................... 30 48 45 40 Nuclear fuel (uranium purchases and processing charges)........ 38 49 56 59 Retirement of long-term debt and redemption of preference stock ......................... 201 203 268 98 Total utility business.......... 620 797 753 557 Diversified Businesses: Retirement of long-term debt.... 35 37 69 57 Investment requirements......... 31 60 65 19 Total diversified businesses.... 66 97 134 76 Total............................ $686 $894 $887 $633 BGE Utility Capital Requirements BGE's construction program is subject to continuous review and modification, and actual expenditures may vary from the estimates above. Electric construction expenditures include the installation of two 5,000 kilowatt diesel generators at Calvert Cliffs Nuclear Power Plant, scheduled to be placed in service in 1995; the construction of a 140-megawatt combustion turbine at Perryman, scheduled to be placed in service in 1995, which the PSC authorized in an order dated March 25, 1993; and improvements in BGE's existing generating plants and its transmission and distribution facilities. Future electric construction expenditures do not include additional generating units in light of the competitive bidding process established by the PSC. The Company estimates currently that expenditures for compliance with the sulfur dioxide provisions of the Clean Air Act of 1990 will total approximately $55 million through 1995. During the twelve months ended September 30, 1994, the internal generation of cash from utility operations provided 62% of the funds required for BGE's capital requirements exclusive of retirements and redemptions of debt and preference stock. During the three-year period 1994 through 1996, the Company expects to provide through utility operations approximately 70% of the funds 25 PART I. FINANCIAL INFORMATION (Continued) required for BGE's capital requirements, exclusive of retirements and redemptions. Utility capital requirements not met through the internal generation of cash are met through the issuance of debt and equity securities. From January 1, 1994 through the date of this Report, BGE's issuances of long-term debt and common stock were $200 million and $34 million, respectively. During the same period, retirements and redemptions of BGE's long-term debt and preference stock totaled $196 million and $4.5 million, respectively, exclusive of any redemption premiums. The amount and timing of future issuances and redemptions will depend upon market conditions and BGE's actual capital requirements. The Constellation Companies' capital requirements are discussed below in the section titled "Diversified Businesses Capital Requirements - Debt and Liquidity." The Constellation Companies plan to meet their capital requirements with a combination of debt and internal generation of cash from their operations. Additionally, from time to time, BGE may make loans to Constellation Holdings, Inc., or contribute equity to enhance the capital structure of Constellation Holdings, Inc. Diversified Businesses Capital Requirements Debt and Liquidity The Constellation Companies intend to meet capital requirements by refinancing debt as it comes due and through internally generated cash. These internal sources include cash that may be generated from operations, sale of assets, and cash generated by tax benefits earned by the Constellation Companies. In the event the Constellation Companies can obtain reasonable value for real estate properties, additional cash may become available through the sale of projects (for additional information see the discussion of the real estate business and market on pages 21 to 24 under the heading "Diversified Businesses Earnings"). The ability of the Constellation Companies to sell or liquidate assets described above will depend on market conditions, and no assurances can be given that such sales or liquidations can be made. Also, to provide additional liquidity to meet interim financial needs, CHI may enter into additional credit facilities. 26 PART I. FINANCIAL INFORMATION (Continued) Investment Requirements The investment requirements of the Constellation Companies include its portion of equity funding to committed projects under development, as well as net loans made to project partnerships. Investment requirements for the years 1994 through 1996 reflect the Constellation Companies' estimate of funding for ongoing and anticipated projects and are subject to continuous review and modification. Actual investment requirements may vary significantly from the estimates on page 25 because of the type and number of projects selected for development, the impact of market conditions on those projects, the ability to obtain financing, and the availability of internally generated cash. The Constellation Companies have met their investment requirements in the past through the internal generation of cash and through borrowings from institutional lenders. 27 PART II. OTHER INFORMATION (Continued) ITEM 1. Legal Proceedings Puna Project As discussed in previous filings made by the Company under the Securities Exchange Act of 1934, the Constellation Companies have a 50% ownership interest in a joint venture, Puna Geothermal Venture (PGV). PGV developed and is operating a 25-megawatt geothermal energy project on the island of Hawaii (the Big Island) in the State of Hawaii (the Puna project). Construction of the Puna project was scheduled to be completed during 1991; however, it began generating electricity on April 22, 1993. PGV sells the electricity it generates to Hawaii Electric Light Company, Inc. ("Hawaii Electric") under a power purchase agreement that calls for the supply by PGV of at least 22 megawatts. Through the date of this Report, the Constellation Companies' investment in the Puna project was $81.5 million. PGV has outstanding a $93.4 million construction loan. In connection with the construction loan, Constellation Investments, Inc. (CII) provided a guarantee to the lending institution that requires CII to put up to $15 million of equity into the Puna project in certain events. The lender has the right to call the guarantee but has not done so. Negotiations are ongoing with the project lenders to convert the construction loan to permanent financing. The diversified businesses section of the capital requirements chart on page 25 includes $4.2 million for the year 1994 and $14 million for the year 1995 relating to the Puna project. The majority of this amount is additional equity that the Constellation Companies will be required to contribute to PGV under the CII guarantee. The Company cannot predict the impact that the matters involving the Puna project discussed below may have on the Constellation Companies or the Company, but such impact could be material. Previously reported issues involving production and resource wells have been addressed. On April 13, 1993, Hawaii Electric filed suit, Hawaii Electric Light Company, Inc. v. Puna Geothermal Venture Company, Inc., Civil No. 93-234 (3rd Circuit Vt., Hawaii), seeking to require PGV to pay contractual penalties of $7.5 million (for delays in the scheduled delivery of power to Hawaii Electric) and seeking to require PGV to pay consequential damages. PGV asserts that the delay was caused by a "force majeure" event. Negotiation of a tentative settlement, which requires no additional capital contributions from the Constellation Companies, is near completion. 28 PART II. OTHER INFORMATION (Continued) PGV intervened in Wao Kele O Puna, et al. v. Waihee, et al., Civil No. 91-3553-10 (1st Circuit Court, Hawaii) on the grounds that plaintiffs improperly are seeking to include the Puna project in an existing suit against the State of Hawaii and the County regarding an unrelated project. If plaintiffs succeed, the State and the County could be enjoined from any further permit review and issuance and from monitoring activity for the Puna project, effectively shutting down the Puna project. The Constellation Companies understand that the unrelated project has been cancelled, but the effect, if any, on this lawsuit are uncertain. Litigation, captioned Pele Defense Fund, et al. v. Puna Geothermal Venture, et al. No. 16098 (originally Civil No. 90-106 (Hilo)) was described in previous reports filed under the Securities Exchange Act of 1934 by the registrant. The litigation involved the administrative procedures used in the issuance of PGV's authority-to-construct permits. On September 23, 1994, the Hawaii Supreme Court issued a decision in an appeal concerning jurisdiction over the matter, and remanded the case to the Third Circuit Court. Prior to issuance of the decision, the authority-to-construct permits were superseded by operating permits. It is not clear whether the plaintiffs intend to continue to prosecute their case at the circuit court level, and, if so, what the affect, if any, might be upon the PGV operating permits. Asbestos During 1993, BGE was served in several actions concerning asbestos. BGE was served with more actions during 1994. The actions are collectively titled In re Baltimore City Personal Injuries Asbestos Cases in the Circuit Court for Baltimore City, Maryland. The actions are based upon the theory of "premises liability," alleging that BGE knew of and exposed individuals to an asbestos hazard. The actions relate to two types of claims. The first type, direct claims by individuals exposed to asbestos, were described in a Report on Form 8-K filed August 20, 1993. BGE and approximately 70 other defendants are involved. Approximately 500 non-employee plaintiffs each claim $6 million in damages ($2 million compensatory and $4 million punitive). BGE does not know the specific facts necessary for BGE to assess its potential liability for these type claims, such as the identity of the BGE facilities at which the plaintiffs allegedly worked as contractors, the names of the plaintiffs' employers, and the date on which the exposure allegedly occurred. The second type are claims by two manufacturers - Owens Corning Fiberglas and Pittsburgh Corning Corp. - against BGE and approximately eight others, as third-party defendants. These 29 PART II. OTHER INFORMATION (Continued) relate to approximately 1,500 individual plaintiffs who have settled with the manufacturers. BGE does not know the specific facts necessary for BGE to assess its potential liability for these type claims, such as the identity of BGE facilities containing asbestos manufactured by the two manufacturers, the relationship (if any) of each of the individual plaintiffs to BGE, the settlement amounts for any individual plaintiffs who are shown to have had a relationship to BGE, and the dates on which/places at which the exposure allegedly occurred. Until the relevant facts for both type claims are determined, BGE is unable to estimate what its liability, if any, might be. Although insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any ultimate awards in the actions, BGE's potential liability could be material. Environmental Matters The Company's potential environmental liabilities and pending environmental actions are listed in Item 1. Business - Environmental Matters of the Form 10-K and in Part II. Other Information - Environmental Matters of the Second Quarter 1994 Form 10-Q. During the third quarter of 1994, an additional environmental action was instituted. On August 30, 1994, BGE was served in litigation instituted by EPA in the United States District Court for the Middle District of Pennsylvania involving contamination of the Keystone Sanitation Company landfill Superfund site located in Adams County, Pennsylvania. BGE was named as a third party defendant based upon allegations that BGE had drums of asbestos shipped to the site. There are eleven original defendants and approximately 150 other third party defendants. Neither the costs of future site remediation, nor the extent of BGE's potential liability can be estimated at this time. 30 ITEM 6. Exhibits and Reports on Form 8-K A) Exhibit No. 12 Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. B) Exhibit No. 27 Financial Data Schedule. C) Form 8-K None SIGNATURE 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. BALTIMORE GAS AND ELECTRIC COMPANY (Registrant) Date November 11, 1994 /s/ C. W. Shivery C. W. Shivery, Vice President on behalf of the Registrant and as Principal Financial Officer 31 EXHIBIT INDEX Exhibit Number 12 Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. 27 Financial Data Schedule. 32 EX-12 2 EXHIBIT 12 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS
12 Months Ended September December December December December December 1994 1993 1992 1991 1990 1989 (In Thousands of Dollars) Net Income $306,606 $309,866 $264,347 $233,681 $175,446 $276,291 Taxes on Income 147,886 140,833 105,994 88,041 22,818 84,704 Adjusted Net Income $454,492 $450,699 $370,341 $321,722 $198,264 $360,995 Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness$202,469$199,415 $200,848 $213,616 $194,656 167,503 Capitalized Interest 12,106 16,167 13,800 20,953 25,748 5,842 Interest Factor in Rentals 2,001 2,144 2,033 1,801 1,840 2,388 Total Fixed Charges $216,576 $217,726 $216,681 $236,370 $222,244 $175,733 Preferred and Preference Dividend Requirements: (1) Preferred and Preference Dividends$ 40,161$ 41,839$ 42,247 $ 42,746 $ 40,261 $ 32,381 Income Tax Required 19,111 18,763 6,729 15,916 5,166 9,779 Total Preferred and Preference Dividend Requirements $ 59,272 $ 60,602 $ 58,976 $ 58,662 $ 45,427 $ 42,160 Total Fixed Charges and Preferred and Preference Dividend Requirements $275,848 $278,328 $275,657 $295,032 $267,671 $217,893 Earnings (2) $658,961 $652,258 $573,222 $537,139 $394,760 $530,886 Ratio of Earnings to Fixed Charges 3.04 3.00 2.65 2.27 1.78 3.02 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements 2.39 2.34 2.08 1.82 1.47 2.44 (1) Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings that would be required to meet dividend requirements on preferred stock and preference stock. (2) Earnings are deemed to consist of net income that includes earnings of BGE's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest.
EX-27 3 FINANCIAL DATA SCHEDULE
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM BGE'S CONSOLIDATED INCOME STATEMENT, BALANCE SHEET AND STATEMENT OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRITY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 9-MOS DEC-31-1994 JAN-01-1994 SEP-30-1994 PER-BOOK 5,348,221 1,181,284 801,517 852,298 0 8,183,320 1,425,254 0 1,330,536 2,731,601 341,000 209,185 2,808,589 0 0 69,400 40,118 1,500 0 0 1,981,927 8,183,320 2,172,818 134,083 1,640,959 1,775,042 397,776 19,812 417,588 142,119 275,469 29,954 245,515 166,166 159,840 508,499 1.67 1.67
-----END PRIVACY-ENHANCED MESSAGE-----