-----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, VJcyykd4+9VwJ7TiXkhJa2t83AMtJ/ExWTpUNUdCfO/p6GQ8PPxDOekS99/zRAKr f4cugaaVBO9bNc6UhK6xxQ== 0000009466-96-000002.txt : 19960515 0000009466-96-000002.hdr.sgml : 19960515 ACCESSION NUMBER: 0000009466-96-000002 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19960331 FILED AS OF DATE: 19960514 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: BALTIMORE GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000009466 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [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: 96563092 BUSINESS ADDRESS: STREET 1: GAS & ELECTRIC BLDG STREET 2: CHARLES CTR CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4107835920 10-Q 1 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 March 31, 1996 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.) 39 W. Lexington Street 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 April 30, 1996. BALTIMORE GAS AND ELECTRIC COMPANY PART I. FINANCIAL INFORMATION CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended March 31, 1996 1995 (In Thousands, Except Per-Share Amounts) Revenues Electric $554,444 $507,825 Gas 219,264 152,784 Diversified businesses 87,622 57,198 Total revenues 861,330 717,807 Expenses Other Than Interest and Income Taxes Electric fuel and purchased energy 153,852 147,454 Gas purchased for resale 129,028 81,803 Operations 132,168 131,535 Maintenance 34,440 36,881 Diversified businesses-selling,general,administrative 67,573 41,109 Depreciation and amortization 85,399 76,678 Taxes other than income taxes 57,555 54,125 Total expenses other than interest and income taxes 660,015 569,585 Income From Operations 201,315 148,222 Other Income Allowance for equity funds used during construction 1,965 5,369 Equity in earnings of Safe Harbor Water Power Corp 1,123 1,108 Net other income and deductions (2,147) (2,611) Total other income 941 3,866 Income Before Interest and Income Taxes 202,256 152,088 Interest Expense Interest charges 52,718 54,978 Capitalized interest (3,152) (3,484) Allowance for borrowed funds used during construction (1,063) (2,905) Net interest expense 48,503 48,589 Income Before Income Taxes 153,753 103,499 Income Taxes Current 46,899 (3,033) Deferred 7,986 37,706 Investment tax credit adjustments (1,913) (2,027) Total income taxes 52,972 32,646 Net Income 100,781 70,853 Preferred and Preference Stock Dividends 9,663 9,951 Earnings Applicable to Common Stock $91,118 $60,902 Average Shares of Common Stock Outstanding 147,527 147,527 Earnings Per Share of Common Stock $0.62 $0.41 Dividends Declared Per Share of Common Stock $0.39 $0.38 See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform with the current year's presentation.
-2- PART I. FINANCIAL INFORMATION (Continued) CONSOLIDATED BALANCE SHEETS
March 31 December 31, 1996* 1995 (In Thousands) ASSETS Current Assets Cash and cash equivalents $ 116,890 $ 23,443 Accounts receivable (net of allowance for uncollectibles of $16,995 and $16,390 respectively) 432,367 400,005 Fuel stocks 39,576 59,614 Materials and supplies 148,798 145,900 Prepaid taxes other than income taxes 27,918 60,508 Deferred income taxes 26,170 36,831 Trading securities 61,670 47,990 Other 16,325 31,487 Total current assets 869,714 805,778 Investments and Other Assets Real estate projects 481,759 479,344 Power generation systems 363,373 358,629 Financial investments 202,851 205,841 Nuclear decommissioning trust fund 99,355 85,811 Net pension asset 70,220 60,077 Safe Harbor Water Power Corporation 34,331 34,327 Senior living facilities 16,860 16,045 Other 74,575 71,894 Total investments and other assets 1,343,324 1,311,968 Utility Plant Plant in service Electric 6,398,127 6,360,624 Gas 709,338 692,693 Common 527,384 522,450 Total plant in service 7,634,849 7,575,767 Accumulated depreciation (2,534,968) (2,481,801) Net plant in service 5,099,881 5,093,966 Construction work in progress 240,410 247,296 Nuclear fuel (net of amortization) 126,993 130,782 Plant held for future use 25,870 25,552 Net utility plant 5,493,154 5,497,596 Deferred Charges Regulatory assets (net) 607,952 637,915 Other deferred charges 68,354 63,406 Total deferred charges 676,306 701,321 TOTAL ASSETS $ 8,382,498 $ 8,316,663 * Unaudited See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation.
-3- PART I. FINANCIAL INFORMATION (Continued) CONSOLIDATED BALANCE SHEETS
March 31 December 31, 1996* 1995 (In Thousands) LIABILITIES AND CAPITALIZATION Current Liabilities Short-term borrowings $ 284,845 $ 279,305 Current portions of long-term debt, preferred stock, and preference stock 195,082 146,969 Accounts payable 165,499 177,092 Customer deposits 27,568 26,857 Accrued taxes 62,459 8,244 Accrued interest 52,924 56,670 Dividends declared 67,198 67,198 Accrued vacation costs 35,955 33,403 Other 14,644 39,417 Total current liabilities 906,174 835,155 Deferred Credits and Other Liabilities Deferred income taxes 1,308,214 1,311,530 Pension and postemployment benefits 156,233 148,594 Decommissioning of federal uranium enrichment facilities 43,694 43,695 Other 56,195 55,568 Total deferred credits and other liabilities 1,564,336 1,559,387 Capitalization Long-term Debt First refunding mortgage bonds of BGE 1,538,528 1,538,528 Other long-term debt of BGE 639,000 649,500 Long-term debt of Constellation Companies 561,141 546,903 Unamortized discount and premium (15,247) (15,708) Current portion of long-term debt (109,897) (120,969) Total long-term debt 2,613,525 2,598,254 Preferred Stock 59,185 59,185 Current portion of preferred stock (59,185) - Total preferred stock - 59,185 Redeemable Preference Stock 268,000 268,000 Current portion of redeemable preference stock (26,000) (26,000) Total redeemable preference stock 242,000 242,000 Preference Stock Not Subject to Mandatory Redemption 210,000 210,000 Common Shareholders' Equity Common stock 1,425,645 1,425,805 Retained earnings 1,415,000 1,381,417 Net unrealized gain on available-for-sale securities 5,818 5,460 Total common shareholders' equity 2,846,463 2,812,682 Total capitalization 5,911,988 5,922,121 TOTAL LIABILITIES AND CAPITALIZATION $ 8,382,498 $ 8,316,663 * Unaudited See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation.
-4- PART I. FINANCIAL INFORMATION (Continued) CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 1996 1995 (In Thousands) Cash Flows From Operating Activities Net income $100,781 $ 70,853 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 100,141 92,102 Deferred income taxes 7,986 37,706 Investment tax credit adjustments (1,913) (2,017) Deferred fuel costs 15,009 10,366 Accrued pension and postemployment benefits (3,174) (5,037) Allowance for equity funds used during construction (1,965) (5,369) Equity in earnings of affiliates and joint ventures (net) (1,038) 2,995 Changes in current assets, other than sale of accounts receivable 19,978 30,893 Changes in current liabilities, other than short-term borrowings 17,305 (43,687) Other 3,331 10,124 Net cash provided by operating activities 256,441 198,929 Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings (net) 5,540 (35,900) Long-term debt 21,729 10,641 Common stock (159) 14 Reacquisition of long-term debt (18,149) (5,789) Common stock dividends paid (57,536) (56,060) Preferred and preference stock dividends paid (9,663) (9,952) Other (353) (748) Net cash used in financing activities (58,591) (97,794) Cash Flows From Investing Activities Utility construction expenditures (69,655) (81,395) Allowance for equity funds used during construction 1,965 5,369 Nuclear fuel expenditures (9,153) (6,576) Deferred energy conservation expenditures (5,493) (10,226) Contributions to nuclear decommissioning trust fund (12,260) (2,445) Purchases of marketable equity securities (11,702) (4,395) Sales of marketable equity securities 11,670 18,127 Other financial investments 5,524 5,041 Real estate projects (3,585) (11,266) Power generation systems (10,116) (15,960) Other (1,598) (1,868) Net cash used in investing activities (104,403) (105,594) Net Increase (Decrease) in Cash and Cash Equivalents 93,447 (4,459) Cash and Cash Equivalents at Beginning of Period 23,443 38,590 Cash and Cash Equivalents at End of Period $116,890 $ 34,131 Other Cash Flow Information Cash paid during the period for: Interest (net of amounts capitalized) $ 52,391 $ 47,403 Income taxes $ (9,985) $ 153 See Notes to Consolidated Financial Statem Certain prior-year amounts have been restated to conform with the current year's presentation.
-5- 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. BGE Financing Activity There have been no issuances of long-term debt or equity securities during the period from January 1, 1996 through the date of this report. In March 1996, the Company called for redemption of BGE's entire class of Preferred Stock. The following is a summary of the series redeemed: Price Shares Per Share Series B, 4-1/2% Cumulative Preferred Stock, $100 par value 222,921 $110 Series C, 4% Cumulative Preferred Stock, $100 par value 68,928 $105 Series D, 5.40% Cumulative Preferred Stock, $100 par value 300,000 $101 BGE may purchase First Refunding Mortgage Bonds of various series in open market transactions, from time to time in the future, depending upon market conditions and BGE's assessment of optimal capital structure, including the mix of secured and unsecured debt. 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 Constellation Holdings, Inc. and its subsidiaries. Pending Merger with Potomac Electric Power Company BGE, Potomac Electric Power Company (PEPCO), and Constellation Energy Corporation (formerly named "RH Acquisition Corp.") (CEC), have entered into an Agreement and Plan of Merger, dated as of September 22, 1995 (the Merger Agreement). CEC was -6- formed to accomplish the merger and its outstanding capital stock is owned 50% by BGE and 50% by PEPCO. The Merger Agreement provides for a strategic business combination that will be accomplished by merging both BGE and PEPCO into CEC (the Merger). The Merger, which was unanimously approved by the Boards of Directors of BGE and PEPCO and approved by the shareholders of both companies, is expected to close during 1997 after all other conditions to the consummation of the Merger, including obtaining applicable regulatory approvals, are met or waived. In connection with the Merger, BGE common shareholders will receive one share of CEC common stock for each BGE share and PEPCO common shareholders will receive 0.997 of a share of CEC common stock for each PEPCO share. Preliminary estimates by the managements of PEPCO and BGE indicate that the synergies resulting from the combination of their utility operations could generate net cost savings of up to $1.3 billion over a period of 10 years following the Merger. These estimates indicate that about two-thirds of the savings will come from reduced labor costs, with the remaining savings split between nonfuel purchasing and corporate and administrative programs. These savings are expected to be allocated among shareholders and customers. This allocation will depend upon the results of regulatory proceedings in the various jurisdictions in which BGE and PEPCO operate their utility businesses. The analyses employed in order to develop estimates of the potential savings as a result of the Merger were necessarily based upon various assumptions which involve judgments with respect to, among other things, future national and regional economic and competitive conditions, inflation rates, regulatory treatment, weather conditions, financial market conditions, interest rates, future business decisions and other uncertainties, all of which are difficult to predict and many of which are beyond the control of BGE and PEPCO. Accordingly, while BGE believes that such assumptions are reasonable for purposes of the development of estimates of potential savings, there can be no assurance that such assumption will approximate actual experience or that all such savings will be realized. The reasons for the Merger, the terms and conditions contained in the Merger Agreement, and other matters concerning the Merger, PEPCO, and CEC are discussed in more detail in the Registration Statement on Form S-4 (Registration No. 33-64799) which is included as an exhibit to this Report on Form 10-Q by incorporation by reference. Environmental Matters The Clean Air Act of 1990 (the Act) contains two titles designed to reduce emissions of sulfur dioxide and nitrogen oxide (NOx) from electric generating stations. Title IV contains provisions for compliance in two separate phases. Phase I of Title IV became effective January 1, 1995, and Phase II of Title IV must be implemented by 2000. BGE met the requirements of -7- Phase I by installing flue gas desulfurization systems and fuel switching and through unit retirements. BGE is currently examining what actions will be required in order to comply with Phase II of the Act. 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 Title I of 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 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 $90 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. In addition, a subsidiary of Constellation Holdings, Inc. has been named as a defendant in a case concerning an alleged environmentally contaminated site owned and operated by a third party. Cleanup costs for these sites cannot be estimated, except that BGE's 15.79% share of the possible cleanup costs at one of these sites, Metal Bank of America, a metal reclaimer in Philadelphia, could exceed amounts BGE has recognized by up to approximately $7 million based on the highest estimate of costs in the range of reasonably possible alternatives. Although the cleanup costs for certain of the remaining 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 tar. However, no formal legal proceedings have been instituted against BGE. BGE has recognized estimated environmental costs at these sites totaling $38.6 million as of March 31, 1996. These costs, net of accumulated amortization, have been deferred 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. -8- 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. 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 $8.92 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 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 $6.02 million in any one year. For physical damage to Calvert Cliffs, BGE has $2.75 billion of property insurance from industry mutual insurance companies. If an outage at Calvert Cliffs is caused by an insured physical damage loss and lasts more than 21 weeks, BGE has up to $473.2 million per unit of insurance, provided by an industry mutual insurance company, for replacement power costs. This amount can be reduced by up to $94.6 million per unit if an outage to both units at Calvert Cliffs is caused by a singular insured physical damage loss. If accidents at any insured plants cause a shortfall of funds at the industry mutuals, BGE and all policyholders could be assessed, with BGE's share being up to $44.1 million. Recoverability of Electric Fuel Costs By statute, actual electric fuel costs are recoverable so long as the Public Service Commission of Maryland (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 -9- 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 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. On January 23, 1995, the Hearing Examiner issued his decision in the 1987 fuel rate proceeding and found that the Company had met the GUPP standard which establishes a presumption that BGE had operated the plant at a reasonably productive capacity level. However, the Order found that the presumption of reasonableness would be overcome by a showing of mismanagement and that such a showing was made with respect to the environmental qualifications outage time. In mitigation for meeting the GUPP standard, the Hearing Examiner disallowed replacement energy costs recovery for 15.5 days of the 66-day outage time. The Hearing Examiner's Order was appealed to the PSC by both BGE and People's Counsel. -10- If the PSC upholds the Hearing Examiner, the Company's earnings would be impacted by approximately $4.5 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 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 -11- 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. Subsequent Event Subsequent to March 31, 1996, a subsidiary of Constellation Holdings, Inc. realized an after-tax gain of approximately $15 million, or 10 cents per share, on the sale of its ownership interest in a power sales contract. This gain will be reported in earnings for the quarter ending June 30, 1996. -12- 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 ENDED MARCH 31, 1996 COMPARED WITH THE CORRESPONDING PERIOD OF 1995 Earnings per Share of Common Stock Consolidated earnings per share were $.62 for the quarter ended March 31, 1996 and $.41 for the quarter ended March 31, 1995. The $.21 increase in earnings per share reflects a higher level of earnings applicable to common stock. The earnings per share are summarized as follows: Quarter Ended March 31 1996 1995 Utility operations $ .58 $ .38 Diversified businesses .04 .03 Total $ .62 $ .41 Earnings Applicable to Common Stock Earnings applicable to common stock increased $30.2 million during the first quarter of 1996 compared to last year as a result of significantly higher earnings from utility operations and slightly higher earnings from diversified businesses. Earnings from utility operations increased during the first quarter of 1996 primarily due to higher electric and gas system sales resulting from the colder winter weather experienced in 1996 compared to the same period last year. The effect of weather on utility sales is discussed on page 14. 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 gas base rate increase authorized by the PSC in November 1995 favorably affected utility earnings during the quarter ended March 31, 1996. The electric fuel rate cases now pending before the PSC discussed in Notes 1 and 12 of the Form 10-K for the year -13- ended December 31, 1995 (Form 10-K) could also affect future years' earnings. Future competition may also affect earnings in ways that are not possible to predict (see the discussion of "Response to Regulatory Change" in the Form 10-K). Earnings from diversified businesses, which primarily represent the operations of Constellation Holdings, Inc. and its subsidiaries (collectively, the Constellation Companies), BGE Home Products & Services, Inc. and Subsidiary (HP&S), BGE Energy Projects & Services, Inc. (EP&S) and BNG, Inc., increased slightly during the quarter ended March 31, 1996 compared to the corresponding period of 1995. Diversified businesses' earnings are discussed on pages 20 through 22. 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 below presents information regarding heating degree days for the quarters ended March 31, 1996 and 1995. Quarter Ended March 31 1996 1995 Heating degree days............................. 2,625 2,240 Percent change compared to prior period................................... 17.2% BGE Utility Revenues and Sales Electric revenues changed for the quarter ended March 31, 1996 because of the following factors: -14- Quarter Ended March 31 1996 vs. 1995 (In millions) System sales volumes $30.0 Base rates 5.2 Fuel rates 1.2 Revenues from system sales 36.4 Interchange and other sales 9.4 Other revenues 0.8 Total $46.6 Electric system sales represent volumes sold to customers within BGE's service territory at rates determined by the PSC. These amounts exclude interchange sales and sales to other utilities, which are discussed separately. Following is a comparison of the changes in electric system sales volumes: Quarter Ended March 31 1996 vs. 1995 Residential 15.2% Commercial 3.7 Industrial 4.4 Total 8.6 Sales to residential customers increased compared to last year due primarily to colder winter weather and greater usage per customer. Sales to commercial customers increased compared to last year due primarily to colder winter weather and a greater number of customers, offset partially by lower usage per customer. Sales to industrial customers increased compared to last year due to an increase in the number of customers and higher usage per industrial customer. Base rates are affected by two principal items: rate orders by the PSC and recovery of eligible electric conservation program costs through the energy conservation surcharge. Base rates increased for the quarter ended March 31, 1996 compared to last year due to recovery of a higher level of eligible electric conservation program costs. Under the energy conservation surcharge, 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 incentives for achieving conservation goals and will be refunded to customers with interest beginning in the ensuing July when the annual resetting of the conservation surcharge rates occurs. -15- 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 and sales to other utilities. (See Notes 1 and 12 of the Form 10-K.) Changes in fuel rate revenues and interchange and other sales normally do not affect earnings. However, if the PSC were to disallow recovery of any part of these costs, earnings would be reduced as discussed in Note 12 of the Form 10-K. Fuel rate revenues were higher for the quarter ended March 31, 1996 as compared to the same period in 1995 as a result of increased electric system sales volumes, offset partially by a lower fuel rate. The fuel rate was lower for the quarter ended March 31, 1996 as compared to the same period last year because of a less costly twenty-four month generation mix due to greater generation at the Calvert Cliffs Nuclear Power Plant and the Brandon Shores Power Plant. BGE expects electric fuel rate revenues to remain relatively constant through 1996. Interchange and other sales represent sales of BGE's energy to the Pennsylvania - New Jersey - Maryland Interconnection (PJM), a regional power pool of eight member companies including BGE, and sales to other non-PJM utilities. These 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. Interchange and other sales increased for the quarter ended March 31, 1996 compared to last year because BGE had a less costly generation mix. This less costly generation mix was due primarily to greater generation from the Brandon Shores Power Plant and the Calvert Cliffs Nuclear Power Plant. Gas revenues changed for the quarter ended March 31, 1996 because of the following factors: Quarter Ended March 31 1996 vs. 1995 (In millions) Sales volumes $ 9.4 Base rates 8.3 Gas cost adjustment revenues 44.7 Revenues from system sales 62.4 Off-system Sales 3.7 Other revenues 0.4 Total $ 66.5 -16- Below is a comparison of the changes in gas sales volumes: Quarter Ended March 31 1996 vs. 1995 Residential 21.8% Commercial 7.7 Industrial (6.5) Total 10.5 Gas sales to residential customers increased during the first quarter of 1996 as compared to the same period last year due to colder winter weather, an increase in the number of customers, and increased usage per customer. Sales to commercial customers increased compared to last year due to colder winter weather and an increase in the number of customers, offset partially by lower usage per customer. Sales to industrial customers decreased compared to last year due to decreased usage per customer (including Bethlehem Steel) as a result of a greater number of interruptions caused by the colder winter weather in 1996. Base rates increased during the quarter ended March 31, 1996 compared to the same period last year primarily as a result of the PSC's November 1995 rate order, which increased annual base rate revenues by $19.3 million, including $2.4 million to recover higher depreciation expense. 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 increased for the quarter ended March 31, 1996 because of higher prices for purchased gas and higher sales volumes subject to gas cost adjustment clauses. Delivery service sales volumes are not subject to gas cost adjustment clauses because these customers purchase their gas directly from third parties. Off-system gas sales volumes represent direct sales to end users of natural gas outside of BGE's service territory and are not subject to gas cost adjustment clauses. BGE began sales of off-system gas during the first quarter of 1996. Pursuant to a sharing arrangement approved by the PSC, the gross margin earned on these sales reduces gas cost adjustment charges to customers and increases income available to common shareholders. -17- BGE Utility Fuel and Energy Expenses Electric fuel and purchased energy expenses were as follows: Quarter Ended March 31 1996 1995 (In millions) Actual costs $147.5 $138.6 Net recovery of costs under electric fuel rate clause (see Note 1 of the Form 10-K) 6.4 8.9 Total $153.9 $147.5 Total electric fuel and purchased energy expenses increased during the quarter ended March 31, 1996 as a result of increased actual costs, offset partially by the operation of the electric fuel rate clause. Actual electric fuel and purchased energy costs increased for the quarter ended March 31, 1996 as a result of higher net output of electricity generated and higher purchased energy costs. Purchased gas expenses were as follows: Quarter Ended March 31 1996 1995 (In millions) Actual costs $126.9 $ 87.3 Net (deferral) recovery of costs under purchased gas adjustment clause (see Note 1 of the Form 10-K) 2.1 (5.5) Total $129.0 $ 81.8 Total purchased gas expenses increased for the quarter ended March 31, 1996 compared to last year due to an increase in actual gas costs and the operation of the purchased gas adjustment clause. The increase in actual gas costs reflects substantially higher gas prices and sales volumes during the first quarter of 1996 as compared to last year. Purchased gas costs exclude gas purchased by delivery service customers, including Bethlehem Steel, who obtain gas directly from third parties. -18- Other Operating Expenses Operations and Maintenance expenses were essentially unchanged during the quarter ended March 31, 1996 compared to last year. Depreciation and amortization expense increased $8.7 million during the quarter ended March 31, 1996 compared to the same period last year because of a higher level of depreciable plant in service and higher amortization of energy conservation surcharge costs. Taxes other than income taxes increased $3.4 million during the quarter ended March 31, 1996 compared to last year due to an increase in property taxes resulting from plant additions during 1995 and higher gross receipts taxes in 1996 due to higher revenues. In addition, payroll taxes increased during 1996 due to increased incentive-based payouts and a 3% general wage increase granted March 1, 1996. Other Income and Expenses The Allowance for Funds Used During Construction (AFC)decreased $5.2 million for the quarter ended March 31, 1996 due primarily to a significant reduction in construction work in progress and a lower gas AFC rate. The reduction in construction work in progress resulted from both a lower level of new construction activity and the placement of several projects in service during the past year. Interest charges decreased $2.3 million for the quarter ended March 31, 1996 due primarily to the maturity of long-term debt as well as lower interest rates as compared to last year, offset partially by a higher level of debt outstanding. Income tax expense increased $20.3 million for the quarter ended March 31, 1996 due primarily to higher taxable income from utility operations and diversified businesses. -19- Diversified Businesses Earnings Earnings per share from diversified businesses were: Quarter Ended March 31 1996 1995 Constellation Holdings, Inc. Power generation systems $.04 $.02 Financial investments .01 .02 Real estate development and senior living facilities (.01) (.01) Total Constellation Holdings, Inc. .04 .03 Other Subsidiaries .00 .00 Total diversified businesses $.04 $.03 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 increased for the quarter ended March 31, 1996 due primarily to higher equity earnings from the Constellation Companies' energy projects. See the discussion of the gain to be reported in earnings for the quarter ending June 30, 1996 under the heading Subsequent Event on page 12 of this report. The Constellation Companies' investment in wholesale power generating projects includes $198 million representing ownership interests in 16 projects that sell electricity in California under Interim Standard Offer No. 4 (SO4) 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 thereafter at fixed capacity payments plus variable energy 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. At current avoided cost levels, the Constellation Companies could experience reduced earnings or incur losses associated with these projects, which could be significant. While nine projects transition from fixed to variable energy rates in the 1996 through 1998 timeframe, revenues from the other projects having SO4 contracts are expected to continue to increase during this -20- period tending to offset revenue declines on the nine projects. Six of the seven largest revenue producing projects will not make the transition to variable energy rates until the 1999-2000 timeframe such that any material reductions in revenues would not be anticipated until the years 2000 and 2001. 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, changing fuels, renegotiating the power purchase agreements, restructuring financings, and selling its ownership interests in the projects. Two of these wholesale power generating projects, in which the Constellation Companies' investment totals $33 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 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 ended March 31, 1996 because the quarter ended March 31, 1995 included capital gains realized from a financial limited partnership. 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 oversupply of and limited demand for land and office space due to modest economic growth and corporate downsizings. Earnings from real estate development and senior living facilities for the quarter ended March 31, 1996 are essentially unchanged from the prior year. The Constellation Companies' real estate portfolio has experienced continuing carrying costs and depreciation. Additionally, the Constellation Companies have been expensing rather than capitalizing interest on certain undeveloped land for which substantially all development activities have been suspended. These factors have affected earnings negatively and are expected to continue to do so until the levels of undeveloped land are reduced. Cash flow from real estate operations has been insufficient to cover the debt service requirements of certain of -21- 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. To the extent the real estate market continues to improve, earnings from real estate activities are expected to improve also. 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. The Constellation Companies' Management believes that although the real estate market has improved, 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 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. The earnings of other subsidiaries, which include HP&S, EP&S, and BNG, Inc., were essentially unchanged during the quarter ended March 31, 1996 compared to last year. 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 and 8 of this Report. LIQUIDITY AND CAPITAL RESOURCES Liquidity For the twelve months ended March 31, 1996, the Company's ratio of earnings to fixed charges and ratio of earnings to combined fixed charges and preferred and preference dividend requirements were 3.47 and 2.72, respectively. -22- Capital Requirements The Company's capital requirements reflect the capital- intensive nature of the utility business. Actual capital requirements for the three months ended March 31, 1996, along with estimated annual amounts for the years 1996 through 1998, are reflected below. Three Months Ended March 31 Calendar Year Estimate 1996 1996 1997 1998 (In millions) Utility Business: Construction expenditures (excluding AFC) Electric $ 42 $ 231 $205 $212 Gas 14 68 73 67 Common 11 41 47 46 Total construction expenditures 67 340 325 325 AFC 3 11 10 10 Nuclear fuel (uranium purchases and processing charges) 9 45 45 44 Deferred energy conservation expenditures 5 34 25 27 Retirement of long-term debt and redemption of preferred and preference stock 11 160 164 125 Total utility business 95 590 569 531 Diversified Businesses: Retirement of long-term debt 7 55 131 157 Investment requirements 20 108 71 82 Total diversified businesses 27 163 202 239 Total $122 $ 753 $771 $770 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 the second of two 5,000 kilowatt diesel generators at Calvert Cliffs Nuclear Power Plant scheduled to be placed in service in 1996 and improvements in BGE's existing generating plants and its transmission and distribution facilities. Future electric construction expenditures do not include additional generating units. During the twelve months ended March 31, 1996, the internal generation of cash from utility operations provided 104% of the funds required for BGE's capital requirements exclusive of retirements and redemptions of debt and preference stock. During the three-year period 1996 through 1998, the Company expects to provide through utility operations 115% of the funds required for BGE's capital requirements, exclusive of retirements and redemptions. -23- Utility capital requirements not met through the internal generation of cash are met through the issuance of debt and equity securities. The amount and timing of issuances and redemptions depends upon market conditions and BGE's actual capital requirements. From January 1, 1996 through the date of this Report, there were no issuances of debt or equity securities. During the same period, BGE redeemed, or announced the redemption of, $37 million principal amount of debt and $61 million par value of preferred and preference stock outstanding. All outstanding preferred stock was called for redemption as described on page 6 under the heading "BGE Financing Activity". At the date of this Report, BGE's securities ratings are as follows: Standard Moody's & Poors Investors Duff & Phelps Rating Group Service Credit Rating Co. Senior Secured Debt A+ A1 AA- (First Mortgage Bonds) Unsecured Debt A A2 A+ Preference Stock A "a2" A The Constellation Companies' capital requirements are discussed below in the section titled "Diversified Businesses Capital Requirements - Debt and Liquidity." The Constellation Companies are exploring expansion of their energy, real estate service, and senior living facility businesses. Expansion may be achieved in a variety of ways, including without limitation increased investment activity and acquisitions. 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. Historically, Constellation's energy projects have been in the United States. Over the last year, Constellation has pursued energy projects in Latin America. As of March 31, 1996, one of the Constellation Companies had invested about $14.6 million and committed another $8.4 million in power projects in Latin America. Constellation's future energy business expansion may include domestic and international projects. 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 -24- 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 and 22 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 has a $75 million revolving credit agreement of which $5 million was outstanding at the date of this Report. 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 1996 through 1998 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 23 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. -25- PART II. OTHER INFORMATION ITEM 1. Legal Proceedings Asbestos Since 1993, BGE has been served in several actions concerning asbestos. 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 516 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 one manufacturer - Pittsburgh Corning Corp. - against BGE and approximately eight others, as third-party defendants. These claims relate to approximately 1,500 individual plaintiffs. 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. -26- PART II. OTHER INFORMATION (Continued) ITEM 4. Submission of Matters to a Vote of Security Holders On March 29, 1996, BGE held a special meeting of shareholders. At that meeting, the following matters were voted upon: 1. The proposed merger of BGE with Potomac Electric Power Company was approved. Common and preference shareholders were entitled to vote. With respect to holders of BGE common stock, the number of affirmative votes cast for the proposed merger was 110,871,295, the number of negative votes cast for the proposed merger was 2,454,946, and the number of abstentions was 1,440,297. With respect to holders of BGE preference stock, the number of affirmative votes cast for the proposed merger was 3,834,731, the number of negative votes cast for the proposed merger was 61,384, and the number of abstentions was 5,677. With respect to holders of the aggregate of both classes of stock, the number of affirmative votes cast for the proposed merger was 114,706,026, the number of negative votes cast for the proposed merger was 2,516,330, and the number of abstentions was 1,445,974. 2. The proposal to implement a Long-Term Incentive Plan for the new company was approved. Only common shareholders were entitled to vote. With respect to holders of common stock, the number of affirmative votes cast for the proposal was 95,237,374, the number of negative votes cast for the proposal was 14,676,425, and the number of abstentions was 4,857,127. -27- PART II. OTHER INFORMATION (Continued) ITEM 6. Exhibits and Reports on Form 8-K (a) Exhibit No. 2* Registration Statement on Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799. 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. Exhibit No. 27 Financial Data Schedule. *Incorporated by Reference. (b) Reports on Form 8-K for the quarter ended March 31, 1996: Date Filed Items Reported February 6, 1996 Item 5. Other Events Item 7. Financial Statements and Exhibits 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 May 14, 1996 /s/ C.W. Shivery C. W. Shivery, Vice President on behalf of the Registrant and as Principal Financial Officer -28- EXHIBIT INDEX Exhibit Number 2* Registration Statement on Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799. 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. *Incorporated by Reference. -29- 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 March December December December December December 1996 1995 1994 1993 1992 1991 (In Thousands of Dollars) Net Income $ 367,934 $ 338,007 $ 323,617 $ 309,866 $ 264,347 $ 233,681 Taxes on Income 192,761 172,388 156,702 140,833 105,994 88,041 Adjusted Net Income $ 560,695 $ 510,395 $ 480,319 $ 450,699 $ 370,341 $ 321,722 Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $ 204,732 $ 206,666 $ 204,206 $ 199,415 $ 200,848 $ 213,616 Capitalized Interest 14,717 15,050 12,427 16,167 13,800 20,953 Interest Factor in Rentals 1,931 2,099 2,010 2,144 2,033 1,801 Total Fixed Charges $ 221,380 $ 223,815 $ 218,643 $ 217,726 $ 216,681 $ 236,370 Preferred and Preference Dividend Requirements: (1) Preferred and Preference Dividends $ 40,289 $ 40,578 $ 39,922 $ 41,839 $ 42,247 $ 42,746 Income Tax Required 20,843 20,434 19,074 18,763 16,729 15,916 Total Preferred and Preference Dividend Requirements $ 61,132 $ 61,012 $ 58,996 $ 60,602 $ 58,976 $ 58,662 Total Fixed Charges and Preferred and Preference Dividend Requirements $ 282,512 $ 284,827 $ 277,639 $ 278,328 $ 275,657 $ 295,032 Earnings (2) $ 767,358 $ 719,160 $ 686,535 $ 652,258 $ 573,222 $ 537,139 Ratio of Earnings to Fixed Charges 3.47 3.21 3.14 3.00 2.65 2.27 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements 2.72 2.52 2.47 2.34 2.08 1.82
(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
UT 3-MOS DEC-31-1996 MAR-31-1996 PER-BOOK 5,493,154 1,343,324 869,714 676,306 0 8,382,498 1,425,645 0 1,415,000 2,846,463 242,000 210,000 2,613,525 0 0 284,845 109,897 85,185 0 0 1,990,583 8,382,498 861,330 52,972 660,015 712,987 148,343 941 149,284 48,503 100,781 9,663 91,118 57,536 52,718 256,441 .62 .62
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