-----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, MtDkXSIjYI5ZTLos+cVtB70F6ODD3VdjFjVSFrYXoj7VYQqRuSx6UxcHFfc06x38 SqYwRLYmplpeeXm/XKVrZQ== 0000009466-95-000032.txt : 19951119 0000009466-95-000032.hdr.sgml : 19951119 ACCESSION NUMBER: 0000009466-95-000032 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19950930 FILED AS OF DATE: 19951113 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: 95589834 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 September 30, 1995 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 October 31, 1995. BALTIMORE GAS AND ELECTRIC COMPANY PART I. FINANCIAL INFORMATION CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Quarter Ended Nine Months Ended September 30, September 30, 1995 1994 1995 1994 (In Thousands, Except Per-Share Amounts) Revenues Electric ............................................... $ 713,769 $ 649,223 $ 1,726,220 $ 1,666,548 Gas ....................................................... 49,477 51,450 270,229 324,520 Diversified businesses .................................... 85,535 53,205 212,638 181,648 Total revenues ............................................ 848,781 753,878 2,209,087 2,172,716 Expenses Other Than Interest and Income Taxes Electric fuel and purchased energy ........................ 155,085 148,082 435,667 395,595 Gas purchased for resale .................................. 18,339 19,868 129,330 178,376 Operations ................................................ 135,056 136,855 401,184 424,857 Maintenance ............................................... 34,478 35,550 122,720 124,540 Diversified businesses-selling, general, and administrative 54,590 33,312 148,337 135,559 Depreciation and amortization ............................. 93,559 90,767 245,574 228,480 Taxes other than income taxes ............................. 57,930 56,971 157,389 153,500 Total expenses other than interest and income taxes ....... 549,037 521,405 1,640,201 1,640,907 Income From Operations ...................................... 299,744 232,473 568,886 531,809 Other Income Allowance for equity funds used during construction ....... 2,026 5,565 12,227 16,180 Equity in earnings of Safe Harbor Water Power Corporation . 1,108 1,088 3,323 3,266 Net other income and deductions ........................... (1,661) 213 (7,600) 416 Total other income ........................................ 1,473 6,866 7,950 19,862 Income Before Interest and Income Taxes ..................... 301,217 239,339 576,836 551,671 Interest Expense Interest charges .......................................... 55,436 54,071 165,746 159,840 Capitalized interest ...................................... (3,509) (3,161) (10,676) (8,972) Allowance for borrowed funds used during construction ..... (1,096) (3,009) (6,615) (8,749) Net interest expense ...................................... 50,831 47,901 148,455 142,119 Income Before Income Taxes .................................. 250,386 191,438 428,381 409,552 Income Taxes Current ................................................... 64,611 51,442 69,523 75,329 Deferred .................................................. 24,470 15,440 79,865 64,896 Investment tax credit adjustments ......................... (2,030) (2,060) (6,085) (6,142) Total income taxes ........................................ 87,051 64,822 143,303 134,083 Net Income .................................................. 163,335 126,616 285,078 275,469 Preferred and Preference Stock Dividends .................... 10,231 9,902 30,135 29,954 Earnings Applicable to Common Stock ...................... $ 153,104 $ 116,714 $ 254,943 $ 245,515 Average Shares of Common Stock Outstanding ................. 147,527 147,487 147,527 146,957 Total Earnings Per Share of Common Stock .................... $1.04 $0.79 $1.73 $1.67 Dividends Declared Per Share of Common Stock ................ $0.39 $0.38 $1.16 $1.13 Certain prior-year amounts have been reclassified to conform with the current year's presentation.
See Notes to Consolidated Financial Statements. -2- PART I. FINANCIAL INFORMATION (Continued) CONSOLIDATED BALANCE SHEETS
September 30, December 31, 1995 * 1994 (In Thousands) ASSETS Current Assets Cash and cash equivalents ................................... $ 28,081 $ 38,590 Accounts receivable (net of allowance for uncollectibles of $15,983 and $14,960, respectively) ................... 388,821 314,842 Fuel stocks ................................................... 65,569 70,627 Materials and supplies ........................................ 148,501 149,614 Prepaid taxes other than income taxes ......................... 39,178 57,740 Other ......................................................... 55,239 47,022 Total current assets .......................................... 725,389 678,435 Investments and Other Assets Real estate projects .......................................... 471,308 471,435 Power generation systems ...................................... 347,372 311,960 Financial investments ......................................... 203,277 224,340 Nuclear decommissioning trust fund ............................ 81,602 66,891 Safe Harbor Water Power Corporation ........................... 34,190 34,168 Senior living facilities ...................................... 15,445 11,540 Other ........................................................ 67,805 58,824 Total investments and other assets ............................ 1,220,999 1,179,158 Utility Plant Plant in service Electric .................................................... 6,256,165 5,929,996 Gas ......................................................... 676,999 616,823 Common ...................................................... 521,743 511,016 Total plant in service ...................................... 7,454,907 7,057,835 Accumulated depreciation ......................................(2,452,705) (2,305,372) Net plant in service .......................................... 5,002,202 4,752,463 Construction work in progress ................................. 303,093 506,030 Nuclear fuel (net of amortization) ............................ 143,132 134,012 Plant held for future use ..................................... 25,295 24,320 Net utility plant ............................................. 5,473,722 5,416,825 Deferred Charges Regulatory assets (net) ....................................... 615,987 623,640 Other deferred charges ........................................ 87,488 96,086 Total deferred charges ........................................ 703,475 719,726 TOTAL ASSETS .................................................. $ 8,123,585 $ 7,994,144 * Unaudited Certain prior-year amounts have been reclassified to conform with the current year's presentation.
See Notes to Consolidated Financial Statements. -3- PART I. FINANCIAL INFORMATION (Continued) CONSOLIDATED BALANCE SHEETS
September 30, December 31, 1995 * 1994 (In Thousands) LIABILITIES AND CAPITALIZATION Current Liabilities Short-term borrowings ....................................... $ 13,800 $ 63,700 Current portions of long-term debt and preference stock ....... 416,546 323,675 Accounts payable .............................................. 126,643 181,931 Customer deposits ............................................. 26,293 24,891 Accrued taxes ................................................. 43,208 19,585 Accrued interest .............................................. 59,724 60,348 Dividends declared ............................................ 67,767 66,012 Accrued vacation costs ........................................ 31,836 30,917 Other ......................................................... 20,737 30,857 Total current liabilities ..................................... 806,554 801,916 Deferred Credits and Other Liabilities Deferred income taxes ......................................... 1,241,711 1,156,429 Pension and postemployment benefits ........................... 135,420 138,835 Decommissioning of federal uranium enrichment facilities ...... 45,637 45,836 Other ......................................................... 53,849 59,645 Total deferred credits and other liabilities .................. 1,476,617 1,400,745 Capitalization Long-term Debt First refunding mortgage bonds of BGE ......................... 1,726,532 1,744,385 Other long-term debt of BGE ................................... 571,500 544,550 Long-term debt of Constellation Companies ..................... 556,175 575,765 Unamortized discount and premium .............................. (16,042) (17,593) Current portion of long-term debt ............................. (329,046) (262,175) Total long-term debt .......................................... 2,509,119 2,584,932 Preferred Stock ................................................. 59,185 59,185 Redeemable Preference Stock ..................................... 341,000 341,000 Current portion of redeemable preference stock ................ (87,500) (61,500) Total redeemable preference stock ............................. 253,500 279,500 Preference Stock Not Subject to Mandatory Redemption ............ 210,000 150,000 Common Shareholders' Equity Common stock .................................................. 1,424,993 1,425,378 Retained earnings ............................................. 1,396,467 1,312,655 Pension liability adjustment ................................ (16,521) (16,521) Net unrealized gain(loss) on available-for-sale securities .. 3,671 (3,646) Total common shareholders' equity ............................. 2,808,610 2,717,866 Total capitalization .......................................... 5,840,414 5,791,483 TOTAL LIABILITIES AND CAPITALIZATION .......................... $ 8,123,585 $ 7,994,144 * Unaudited Certain prior-year amounts have been reclassified to conform with the current year's presentation.
See Notes to Consolidated Financial Statements. -4- PART I. FINANCIAL INFORMATION (Continued) CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1995 1994 (In Thousands) Cash Flows From Operating Activities Net income ................................................... $ 285,078 $ 275,469 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization .............................. 288,698 266,945 Deferred income taxes ...................................... 79,865 64,896 Investment tax credit adjustments .......................... (6,085) (6,142) Deferred fuel costs ........................................ 21,690 4,536 Accrued pension and postemployment benefits ................ (10,540) (44,210) Allowance for equity funds used during construction......... (12,227) (16,180) Equity in earnings of affiliates and joint ventures (net)... (14,854) (12,551) Changes in current assets, other than sale of accounts receivable ... (57,784) (42,073) Changes in current liabilities, other than short-term borrowings..... (38,415) (6,296) Other ...................................................... (4,969) 24,105 Net cash provided by operating activities .................... 530,457 508,499 Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings (net) ................................ (49,900) 69,400 Long-term debt ............................................. 56,164 207,018 Preference stock ........................................... 59,475 (4) Common stock ............................................... 140 33,762 Reacquisition of long-term debt .............................. (67,002) (238,571) Redemption of preference stock ............................... - (2,906) Common stock dividends paid .................................. (169,656) (164,092) Preferred and preference stock dividends paid ................ (29,856) (29,970) Other ........................................................ 325 (214) Net cash used in financing activities ........................ (200,310) (125,577) Cash Flows From Investing Activities Utility construction expenditures ............................ (258,331) (344,993) Allowance for equity funds used during construction .......... 12,227 16,180 Nuclear fuel expenditures .................................... (45,434) (38,337) Deferred nuclear expenditures ................................ - (5,674) Deferred energy conservation expenditures .................... (30,068) (29,712) Contributions to nuclear decommissioning trust fund .......... (7,335) (7,335) Purchases of marketable equity securities .................... (12,055) (43,505) Sales of marketable equity securities ........................ 40,856 25,418 Other financial investments .................................. 7,941 2,751 Real estate projects ......................................... (3,898) 21,048 Power generation systems ..................................... (29,949) (2,330) Other ........................................................ (14,610) 559 Net cash used in investing activities ........................ (340,656) (405,930) Net Decrease in Cash and Cash Equivalents ...................... (10,509) (23,008) Cash and Cash Equivalents at Beginning of Period ............... 38,590 84,236 Cash and Cash Equivalents at End of Period ..................... $ 28,081 $ 61,228 Other Cash Flow Information Cash paid during the period for: Interest (net of amounts capitalized) ...................... $ 148,018 $ 137,982 Income taxes ............................................... $ 57,342 $ 58,408
See Notes to Consolidated Financial Statements. -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. Statement of Financial Accounting Standards No. 121 In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 121 regarding accounting for asset impairments. This statement, which must be adopted by the Company by January 1, 1996, requires the Company to review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Additionally, the statement requires rate-regulated companies to write-off regulatory assets against earnings whenever those assets no longer meet the criteria for recognition of a regulatory asset as defined by SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Adoption of SFAS No. 121 is not expected to have a material impact on the Company's financial statements. Regulatory Assets Deferred investment tax credits represent investment tax credits associated with BGE's regulated utility operations as discussed in Note 1 of the Form 10-K for the year ended December 31, 1994. Previously, the Company reported deferred investment tax credits in the consolidated balance sheets as Deferred Credits and Other Liabilities. Effective September 30, 1995, the Company reclassified those credits as a reduction of Regulatory Assets, which reflects the Company's policy to defer such credits solely because of the regulatory treatment. Prior-year amounts have been reclassified to conform with the current year's presentation. BGE Financing Activity The following is a summary of issuances of long-term debt and preference stock during the period from January 1, 1995 through the date of this report. The net proceeds from these issuances were used to meet capital requirements and for general corporate purposes relating to BGE's utility business. -6- Principal Amount or Par Value Issue Net Issued Date Proceeds Medium-Term Notes, Series C (Maturing August through December, 1998) $26,950,000 9/1-9/6/95 $26,869,000 6.99% Cumulative Preference Stock, 1995 Series ($100 Par Value) $60,000,000 9/7/95 $59,475,000 During this period, BGE redeemed the following principal amounts of First Refunding Mortgage Bonds at various prices through operation of the annual sinking fund as required by BGE's Mortgage: $10,259,000 of the 7-1/8% Series due January 1, 2002; $5,025,000 of the 8.40% Series due October 15, 1999; $1,333,000 of the 7-1/2% Series due January 15, 2007; and $631,000 from various other series. In addition, on October 1, BGE exercised its option to double-up the required sinking fund on certain series of preference stock by redeeming at par a total of 30,000 shares of the 7.50% Cumulative Preference Stock 1986 Series ($100 par value) and a total of 200,000 shares of the 8.25% Cumulative Preference Stock 1989 Series ($100 par value). 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 As described in detail in the Report on Form 8-K filed September 27, 1995, BGE, Potomac Electric Power Company, a District of Columbia and Virginia corporation (PEPCO), and RH Acquisition Corp., a Maryland corporation (the New Company), have entered into an Agreement and Plan of Merger, dated as of September 22, 1995. The New Company, which will be renamed, was formed to accomplish the merger and its outstanding capital stock is owned 50% by BGE and 50% by PEPCO. The Agreement and Plan of Merger provides for a strategic business combination that will be accomplished by merging both BGE and PEPCO into the New Company (the Transaction). The Transaction, which was unanimously approved by the Boards of Directors of BGE and PEPCO, is expected -7- to close during 1997 after shareholder approval is obtained and all other conditions to the consummation of the Transaction, including obtaining applicable regulatory approvals, are met or waived. In connection with the Transaction, BGE common shareholders will receive one share of New Company common stock for each BGE share and PEPCO common shareholders will receive 0.997 share of New Company common stock for each PEPCO share. 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 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 recognized by up to approximately $14 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. -8- 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 September 30, 1995. 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. 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 $6.08 million in any one year. For physical damage to Calvert Cliffs, BGE has $2.75 billion of property insurance, including $1.9 billion 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 -9- 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 $33.33 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 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 -10- 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 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- -11- 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. -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 AND NINE MONTHS ENDED SEPTEMBER 30, 1995 COMPARED WITH THE CORRESPONDING PERIODS OF 1994 Earnings per Share of Common Stock Consolidated earnings per share for the quarter and nine months ended September 30, 1995 were $1.04 and $1.73, respectively, which represent increases of $.25 and $.06 compared to the earnings for the corresponding periods of 1994. These increases in earnings per share reflect a higher level of earnings applicable to common stock. The earnings per share are summarized as follows: Quarter Ended Nine Months Ended September 30 September 30 1995 1994 1995 1994 Utility operations $ .96 $ .75 $1.59 $1.61 Diversified businesses .08 .04 .14 .06 Total $1.04 $ .79 $1.73 $1.67 Earnings Applicable to Common Stock Earnings applicable to common stock increased $36.4 million during the third quarter of 1995 as a result of higher earnings from both utility operations and diversified businesses. Earnings increased $9.4 million during the nine months ended September 30, 1995, as a result of higher earnings from diversified businesses, partially offset by slightly lower earnings from utility operations. Earnings from utility operations increased during the third quarter of 1995 primarily due to higher electric system sales resulting from the extremely hot summer weather in 1995 in contrast to the weather experienced during the third quarter of last year. The effect of weather on utility sales is discussed on pages 14 and 15. Earnings from utility operations decreased during the nine months ended September 30, 1995 due to lower electric and gas sales resulting from substantially milder winter weather in 1995, as well as higher depreciation and amortization expense as -13- compared to 1994. This was partially offset by higher electric system sales due to the extremely hot summer weather experienced in 1995 and lower operations and maintenance expenses as compared to 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. 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, 1994 (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. In response to the competitive forces and regulatory changes, as discussed in Part 1 of the Form 10-K under the heading Regulatory Matters and Competition, BGE from time to time will consider various strategies designed to enhance its competitive position and to increase its ability to adapt to and anticipate regulatory changes in its utility business. These strategies may include internal restructurings involving the complete or partial separation of its generation, transmission and distribution businesses, acquisitions of related or unrelated businesses, business combinations, and additions to or dispositions of portions of its franchised service territories. BGE may from time to time be engaged in preliminary discussions, either internally or with third parties, regarding one or more of these potential strategies. No assurances can be given as to whether any potential transaction of the type described above may actually occur, or as to the ultimate effect thereof on the financial condition or competitive position of BGE. See the discussion of BGE's pending merger with PEPCO under the heading Pending Merger with Potomac Electric Power Company on page 7 of this Report. 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) and its subsidiary were higher during the quarter and nine months ended September 30, 1995 compared to the corresponding periods of 1994. Diversified businesses' earnings are discussed on pages 22 through 24. 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 -14- 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 and cooling degree days for the quarter and nine months ended September 30, 1995 and 1994. Quarter Ended Nine Months Ended September 30 September 30 1995 1994 1995 1994 Heating degree days............ 53 79 2,772 3,275 Percent change compared to prior period.................. (32.9)% (15.4)% Cooling degree days............ 746 615 997 935 Percent change compared to prior period.................. 21.3% 6.6% BGE Utility Revenues and Sales Electric revenues changed for the quarter and nine months ended September 30, 1995 because of the following factors: Quarter Ended Nine Months Ended September 30 September 30 1995 vs. 1994 1995 vs. 1994 (In millions) System sales volumes $ 41.2 $ 6.2 Base rates 12.4 16.2 Fuel rates (0.4) (16.0) Revenues from system sales 53.2 6.4 Interchange and other sales 10.4 53.1 Other revenues 0.9 0.2 Total $ 64.5 $59.7 Electric system sales represent volumes sold to customers within BGE's service territory at rates determined by the PSC. These amounts exclude interchange sales and sales to other utilities, which are discussed separately. Following is a comparison of the changes in electric system sales volumes: -15- Quarter Ended Nine Months Ended September 30 September 30 1995 vs. 1994 1995 vs. 1994 Residential 10.5% (1.5)% Commercial 5.8 0.9 Industrial 5.5 3.4 Total 7.6 0.3 The increase in sales to the residential and commercial classes of electric customers during the third quarter of 1995 is primarily attributable to the extremely hot summer weather conditions in 1995 as compared to the weather experienced during the third quarter of 1994. The increase in industrial sales was primarily due to an increase in the number of customers as compared to last year. The slight decrease in sales to residential customers during the nine months ended September 30, 1995 reflects milder weather experienced during the first half of 1995 as compared to last year, offset partially by the extremely hot summer weather during 1995. Sales to commercial customers increased slightly compared to last year due to an increased number of customers and higher usage per customer, offset partially by the net impact of the hotter summer and milder winter weather patterns experienced this year. Sales to industrial customers increased primarily due to an increase in the number of customers and the increased sale of electricity to Bethlehem Steel, offset partially by lower usage by other industrial customers. Bethlehem Steel has been purchasing its full electricity requirements from BGE since March of 1994 and is still producing power with its own generating facility which it is now selling to BGE rather than using the power to reduce its requirements. 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 and nine months ended September 30, 1995 due to the deferral in 1994 of the portion of conservation surcharge billings subject to refund, as described below. 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. BGE earned in excess of its authorized rate of return on electric operations for the period July 1, 1993 through June 30, 1994. As a result, BGE deferred the portion of electric energy conservation revenues subject to refund for the period December -16- 1993 through November 1994. The deferral of these billings totaled $20.1 million, of which $6.6 million occurred during the quarter ended September 30, 1994 and a total of $15.1 million occurred during the nine months ended September 30, 1994. 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 13 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 13 of the Form 10-K. Fuel rate revenues were slightly lower for the quarter ended September 30, 1995 as compared to the same period in 1994 as a result of a lower fuel rate, offset substantially by increased electric system sales volumes. Fuel rate revenues were lower for the nine months ended September 30, 1995 compared to the same period last year as a result of a lower fuel rate. The fuel rate was lower for the quarter and nine months ended September 30, 1995 as compared to the same periods last year because of a less costly twenty-four month generation mix due to greater generation in 1995 at the Calvert Cliffs Nuclear Power Plant and the Brandon Shores Power Plant. BGE expects electric fuel rate revenues to decrease slightly during the remainder of 1995 due to a lower fuel rate. 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 and nine months ended September 30, 1995 because of 1995 sales to other utilities and because BGE had a less costly generation mix than other PJM utilities. This less costly generation mix was due to greater generation from the Brandon Shores Power Plant and continued operation of the Calvert Cliffs Nuclear Power Plant. Gas revenues changed for the quarter and nine months ended September 30,1995 because of the following factors: Quarter Ended Nine Months Ended September 30 September 30 1995 vs. 1994 1995 vs. 1994 (In millions) Sales volumes $ (0.7) $ (6.1) Base rates 0.1 2.1 Gas cost adjustment revenues (1.7) (50.3) Other revenues 0.3 0.0 Total $ (2.0) $ (54.3) -17- Below is a comparison of the changes in gas sales volumes: Quarter Ended Nine Months Ended September 30 September 30 1995 vs. 1994 1995 vs. 1994 Residential (8.1)% (10.8)% Commercial 8.5 (2.8) Industrial (1.6) 9.6 Total (0.7) (1.5) Gas sales to residential customers decreased during the third quarter of 1995 due to lower usage per customer, offset partially by an increased number of customers. Sales to commercial customers were higher compared to last year due to increased usage per customer and an increase in the number of customers. Sales to industrial customers were lower compared to last year due to decreased usage by Bethlehem Steel, offset partially by increased usage by other industrial customers. Total gas sales for the nine months ended September 30, 1995 decreased as a result of lower sales to residential and commercial customers, offset partially by an increase in sales to industrial customers. Sales to residential customers decreased due to milder winter weather in 1995 and lower usage-per- customer, offset partially by an increase in the number of customers. Sales to commercial customers decreased due to milder winter weather, offset partially by an increase in the number of customers and higher usage-per-customer during 1995. Sales to industrial customers increased compared to last year due to greater usage of gas per customer, including Bethlehem Steel, and fewer customer interruptions in the first quarter of 1995 due to the milder weather as compared to the same period last year. Base rates increased slightly during 1995 due to an increased recovery of eligible gas conservation program costs through the energy conservation surcharge. Future gas base rate revenues are expected to be impacted positively by the Maryland Commission's anticipated Order in response to BGE's April 21, 1995 application for $29 million of increased gas base rates. In a proposed Order issued October 3, 1995, a hearing examiner approved a $19.4 million increase to gas base rates. The proposed Order has been appealed, and the Maryland Commission is expected to issue a final Order on November 20, 1995. 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 for the quarter and nine months ended September 30, 1995 because of lower prices for purchased gas and lower sales volumes subject to gas cost adjustment clauses. Delivery service sales volumes are not -18- 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 1995 1994 1995 1994 (In millions) Actual costs $156.7 $141.5 $420.2 $414.7 Net (deferral) recovery of costs under electric fuel rate clause (see Note 1 of the Form 10-K) (1.6) 6.6 15.5 (19.1) Total $155.1 $148.1 $435.7 $395.6 Total electric fuel and purchased energy expenses increased during the quarter ended September 30, 1995 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 September 30, 1995 as a result of higher net output of electricity generated and higher purchased energy costs. Total electric fuel and purchased energy expenses increased during the nine months ended September 30, 1995 as a result of the operation of the electric fuel rate clause and increased actual electric costs. Actual electric fuel and purchased energy costs increased during the nine months ended September 30, 1995 primarily due to a higher net output of electricity and higher purchased energy and capacity costs, offset partially by a less costly generation mix resulting primarily from refueling and maintenance outages at the Calvert Cliffs Nuclear Power Plant during the first quarter of 1994. Purchased gas expenses were as follows: Quarter Ended Nine Months Ended September 30 September 30 1995 1994 1995 1994 (In millions) Actual costs $ 16.9 $21.4 $135.6 $174.6 Net (deferral) recovery of costs under purchased gas adjustment clause (see Note 1 of the Form 10-K) 1.4 (1.5) (6.3) 3.8 Total $ 18.3 $19.9 $129.3 $178.4 -19- Total purchased gas expenses decreased slightly for the quarter ended September 30, 1995 compared to last year due to a decrease in actual gas costs, offset partially by the operation of the purchased gas adjustment clause. The decrease in actual gas costs reflects substantially lower gas prices during the third quarter of 1995 as compared to last year. Total purchased gas expenses decreased during the nine months ended September 30, 1995 due to significantly lower actual purchased gas costs and due to the operation of the purchased gas adjustment clause. Actual purchased gas costs decreased during the nine months ended September 30, 1995 due to the lower output associated with the decreased demand for BGE gas and lower gas prices. The decreased demand for BGE gas and the lower gas prices reflect the significantly milder weather experienced during the first quarter of 1995 compared to the first quarter of 1994. This decrease is offset partially by $6.5 million of take- or-pay refunds received in the second quarter of 1994 from Columbia Gas Transmission Corporation. 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 be increased by transition costs incurred by BGE gas pipeline suppliers in implementing FERC Order No. 636. These transition costs, if approved by FERC, will be passed on to BGE customers through the purchased gas adjustment clause. Other Operating Expenses Operations expense decreased slightly for the quarter ended September 30, 1995 due primarily to continuing labor and other savings in 1995 resulting from the Company's ongoing cost control efforts. In addition to the ongoing cost control efforts noted above, operations expense for the nine months ended September 30, 1995 decreased due to a $10.0 million one-time bonus paid to employees in the first quarter of 1994 in lieu of a general wage increase and approximately $4.5 million in higher expenses attributable to the winter storms in the first quarter of 1994. Operations expense is expected to continue to decline during 1995 due to ongoing cost control efforts of the Company. Maintenance expense decreased slightly during the quarter and nine months ended September 30, 1995 due primarily to reduced labor costs and other savings in 1995 resulting from the Company's ongoing cost control efforts, offset partially by approximately $2.3 million in higher costs at the Calvert Cliffs Nuclear Power Plant related to the second quarter 1995 outage. Depreciation and amortization expense increased for the quarter and the nine months ended September 30, 1995 because of higher depreciable plant in service and the completion of a facility-specific study of the cost to decommission the Calvert Cliffs Nuclear Power Plant. The higher level of depreciable plant -20- in service, which is primarily due to certain capital additions at the Calvert Cliffs Nuclear Power Plant, resulted in an increase of approximately $10.5 million in depreciation and amortization during the nine months ended September 30, 1995. The facility-specific study generated a higher decommissioning cost than the prior estimate which will increase depreciation expense by $9 million annually, $6.8 million of which occurred during the nine months ended September 30, 1995. Additionally, as discussed below, depreciation and amortization expense during the third quarter and nine months ended September 30, 1995 and 1994 reflected the write-off of certain Perryman costs. Initially, BGE had planned to build two combined cycle generating units at its Perryman site with each unit consisting of two combustion turbines. However, due to significant changes in the environment in which utilities operate, BGE decided in 1994 not to construct the second combined cycle generating unit and wrote off the construction work in progress costs associated with that unit. This write-off reduced after-tax earnings during the third quarter of 1994 by $11.0 million or 7 cents per share. As a result of the Maryland Public Service Commission's August 1995 Order requiring all new generation capacity needs to be competitively bid and BGE's September 1995 announcement that it will merge with PEPCO, BGE determined that it will not build the second combustion turbine for the first combined cycle unit. Therefore, during the third quarter of 1995, BGE wrote off the remaining construction work in progress costs associated with the first combined cycle unit. This write-off reduced after-tax earnings for the quarter ended September 30, 1995 by $9.7 million, or 7 cents per share. The construction of the first 140- megawatt combustion turbine at Perryman was completed, and the unit was placed in service, during June 1995. Other Income and Expenses Allowance for equity funds used during construction decreased for the quarter and the nine months ended September 30, 1995 due primarily to a significant reduction in construction work in progress. This reduction in construction work in progress resulted from both a lower level of new construction activity and the placement of several projects in service. Net other income and deductions decreased for the quarter and the nine months ended September 30, 1995. For the nine months ended September 30, 1995 net other income and deductions decreased due primarily to approximately $11.0 million in lower other interest, dividend and finance charge income, offset partially by a $2.0 million gain on the sale of receivables. Interest expense increased for the quarter and nine months ended September 30, 1995 primarily due to an increase in the level of interest rates, offset partially by more capitalized interest related to increased investment in capitalized projects by the Constellation Companies. -21- Income tax expense increased for the quarter ended September 30, 1995 due primarily to higher taxable income from utility operations and diversified businesses. Income tax expense increased for the nine months ended September 30, 1995 due primarily to higher taxable income from the Constellation Companies. Diversified Businesses Earnings Earnings per share from diversified businesses were: Quarter Ended Nine Months Ended September 30 September 30 1995 1994 1995 1994 Constellation Holdings, Inc. Power generation systems $ .07 $ .05 $ .11 $ .06 Financial investments .02 .00 .06 .02 Real estate development and senior living facilities (.01) (.01) (.03) (.02) Total Constellation Holdings, Inc. .08 .04 .14 .06 BGE Home Products & Services, Inc. .00 .00 .00 .00 Total diversified businesses $ .08 $ .04 $ .14 $ .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 increased for the quarter and nine months ended September 30, 1995 due primarily to higher equity earnings from the Constellation Companies' energy projects. In addition, earnings during the quarter ended September 30, 1995 increased due to the gain on the sale of certain operating and maintenance contracts. The Constellation Companies' investment in wholesale power generating projects includes $194 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 -22- 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 $29 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 higher for the quarter ended September 30, 1995 due to favorable earnings on the Companies' investment portfolio. Financial investment earnings were higher for the nine months ended September 30, 1995 due to favorable earnings on the Companies' investment portfolio and realized gains from a financial 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 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 quarter and nine months ended September 30, 1995 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 -23- 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 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. 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 8, 9, and 28 of this Report. LIQUIDITY AND CAPITAL RESOURCES Liquidity For the twelve months ended September 30, 1995, the Company's ratio of earnings to fixed charges and ratio of earnings to combined fixed charges and preferred and preference dividend requirements were 3.16 and 2.50, respectively. -24- 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, 1995, along with estimated annual amounts for the years 1995 through 1997, are reflected below. Nine Months Ended September 30 Calendar Year Estimate 1995 1995 1996 1997 (In millions) Utility Business: Construction expenditures (excluding AFC) Electric $159 $230 $219 $206 Gas 48 67 71 84 Common 32 53 50 35 Total construction expenditures 239 350 340 325 AFC 19 23 13 10 Nuclear fuel (uranium purchases and processing charges) 45 50 50 52 Deferred energy conservation expenditures 30 40 34 25 Retirement of long-term debt and redemption of preference stock 18 279 98 164 Total utility business 351 742 535 576 Diversified Businesses: Retirement of long-term debt 39 57 46 141 Investment requirements 54 86 70 40 Total diversified businesses 93 143 116 181 Total $444 $885 $651 $757 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, one of which was placed in service in June, 1995 and the second is scheduled to be placed in service in 1996; the construction of a 140-megawatt combustion turbine at Perryman, which was placed in service in June, 1995; 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 September 30, 1995, the internal generation of cash from utility operations provided 95% of the funds required for BGE's capital requirements exclusive of retirements and redemptions of debt and preference stock. During the three-year period 1995 through 1997, the Company expects to -25- provide through utility operations 100% of the funds 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. The amount and timing of issuances and redemptions depends upon market conditions and BGE's actual capital requirements. From January 1, 1995 through the date of this Report, BGE issued $27 million principal amount of debt and $60 million par value of preference stock. During the same period, BGE redeemed $206 million principal amount of debt and $73 million par value of preference stock. 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+ Preferred Stock A "a1" 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. As of September 30, 1995, one of the Constellation Companies had invested about $10 million for an investment in Bolivia. Constellation's 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 -26- 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 22 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 has a $50 million revolving credit agreement of which $35 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 1995 through 1997 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 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 510 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 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. -28- PART II. OTHER INFORMATION (Continued) ITEM 6. Exhibits and Reports on Form 8-K (a) Exhibit No. 3 Articles Supplementary, dated as of September 5, 1995, to the Charter of Baltimore Gas and Electric Company. 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. (b) Reports on Form 8-K for the quarter ended September 30, 1995: Date Filed Items Reported September 27, 1995 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 November 13, 1995 /s/ C. W. Shivery C. W. Shivery, Vice President on behalf of the Registrant and as Principal Financial Officer -29- EXHIBIT INDEX Exhibit Number 3 Articles Supplementary, dated as of September 5, 1995, to the Charter of Baltimore Gas and Electric Company. 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. -30- EX-3 2 Exhibit 3 ARTICLES SUPPLEMENTARY TO THE CHARTER OF BALTIMORE GAS AND ELECTRIC COMPANY BALTIMORE GAS AND ELECTRIC COMPANY, a Maryland corporation (the "corporation") having its principal office in Baltimore City, Maryland, hereby certifies that: FIRST: The Board of Directors of the corporation on September 17, 1993 and its Executive Committee on September 5, 1995, acting pursuant to the power contained in paragraph 18 of the Charter of the corporation, classified 600,000 shares of the authorized but unissued preference stock into a series of preference stock to be designated as 6.99% Cumulative Preference Stock, 1995 Series ($100 par value). SECOND: The preferences, rights, voting powers, restrictions, and qualifications of the authorized preference stock are set forth in the Charter of the corporation, as restated. The following is a further description of the 6.99% Cumulative Preference Stock, 1995 Series ($100 par value), containing the preferences, restrictions, limitations as to dividends, qualifications thereof, and the times and prices of redemption thereof, as fixed by the Board of Directors and its Executive Committee: "32.(a). The 6.99% Cumulative Preference Stock, 1995 Series ($100 par value), shall entitle the holders thereof to receive, when and as declared, from the surplus or net profits of the corporation remaining after the preferential dividend requirements for the outstanding preferred stock have been provided for, yearly dividends at the rate of six and ninety-nine hundredths per cent per annum and no more, payable quarterly on the first days of January, April, July, and October in each year commencing October 1, 1995. The dividends on the 6.99% Cumulative Preference Stock, 1995 Series ($100 par value), shall be cumulative and shall be payable before any dividend on the common stock shall be paid or set apart; so that, if in any year or years dividends amounting to six and ninety-nine hundredths per cent shall not have been paid thereon, the deficiency shall be payable before any dividends shall be paid upon or set apart for the common stock. Dividends on the 6.99% Cumulative Preference Stock, 1995 Series ($100 par value), will accrue from and include September 7, 1995. (b). The 6.99% Cumulative Preference Stock, 1995 Series ($100 par value), or any portion thereof, may whenever the Board of Directors shall so determine, be redeemed by the payment to the holders thereof of the sum hereinafter specified as the redemption price at the time of redemption, in cash, for each share thereof, together with all accrued dividends. The applicable redemption prices shall be: Twelve Month Period Redemption Price Beginning October 1, Per Share 2005 $ 103.50 2006 103.15 2007 102.80 2008 102.45 2009 102.10 2010 101.75 2011 101.40 2012 101.05 2013 100.70 2014 100.35 2015 and thereafter 100.00 provided, however, that prior to October 1, 2005, the corporation will not redeem any shares of the 6.99% Cumulative Preference Stock, 1995 Series ($100 par value). In case less than all of the preference stock of this series at the time being outstanding is so redeemed, the shares to be redeemed shall be, as nearly as is reasonably practicable without creating fractional shares, a proportionate part of the holdings of each holder of preference stock of this series, or shall be selected, in whole or in part, by lot. At least thirty (30) days' written notice of the election of the corporation to redeem the preference stock of this series (or any part thereof, in which case the notice shall specify the particular shares to be redeemed) shall be given to each holder of the preference stock of this series so to be redeemed by mailing the same, postage prepaid, and addressed to him at his address as it appears upon the books of the corporation. When such notice shall have been so given and the funds for payment of the redemption price plus accrued dividends shall have been provided and set apart, the dividends on the shares of preference stock of this series so called for redemption and all other rights of the holders thereof, except the right to receive the redemption price plus accrued dividends, shall cease." THIRD: The Board of Directors of the corporation on September 17, 1993, and its Executive Committee on September 5, 1995, duly adopted resolutions classifying the said 600,000 shares of the authorized but unissued preference stock into 600,000 shares of 6.99% Cumulative Preference Stock, 1995 Series ($100 par value), setting forth the foregoing description of such shares as classified, and authorizing the execution and filing of these Articles Supplementary to the Charter of this corporation. FOURTH: Such shares have been duly classified by the Board of Directors of the corporation and its Executive Committee pursuant to authority contained in the Charter of the corporation. - 2 - IN WITNESS WHEREOF, Baltimore Gas and Electric Company has caused these Articles Supplementary to its Charter to be signed in its name and on its behalf by its President, or one of its Vice Presidents, and its corporate seal to be hereto affixed, duly attested by its Secretary, or one of its Assistant Secretaries, on September 5, 1995. BALTIMORE GAS AND ELECTRIC COMPANY By:__/s/ E. A. Crooke______________ President BALTIMORE GAS AND SEAL: ELECTRIC COMPANY, INCORPORATED JUNE 20, 1906 Attest: _/s/ R. M. Bange, Jr.________ Assistant Secretary - 3 - STATE OF MARYLAND: } SS: COUNTY OF BALTIMORE: I HEREBY CERTIFY that on September 5, 1995, before me, the subscriber, a Notary Public of the State of Maryland, in and for the County of Baltimore, personally appeared E. A. Crooke, President of Baltimore Gas and Electric Company, a Maryland corporation, and in the name and on behalf of said corporation, acknowledged the foregoing Articles Supplementary to its Charter to be the corporate act of said corporation and at the same time personally appeared R. M. Bange, Jr., and made oath in due form of law that he is a duly elected Assistant Secretary of said corporation and he verified the matters and facts with respect to authorization and approval that are set forth in said Articles Supplementary. AS WITNESS my hand and notarial seal the day and year first above written. ___/s/_Ann M. Patek_______ Notary Public My commission expires: 1/29/96 SEAL: NOTARY PUBLIC BALTIMORE, MD - 4 - EX-12 3 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 1995 1994 1993 1992 1991 1990 (In Thousands of Dollars) Net Income $333,226 $323,617 $309,866 $264,347 $233,681 $175,446 Taxes on Income 165,900 156,702 140,833 105,994 88,041 22,818 Adjusted Net Income $499,126 $480,319 $450,699 $370,341 $321,722 $198,264 Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $208,237 $204,206 $199,415 $200,848 $213,616 $194,656 Capitalized Interest 14,131 12,427 16,167 13,800 20,953 25,748 Interest Factor in Rentals 2,017 2,010 2,144 2,033 1,801 1,840 Total Fixed Charges $224,385 $218,643 $217,726 $216,681 $236,370 $222,244 Preferred and Preference Dividend Requirements: (1) Preferred and Preference Dividends $ 40,103 $ 39,922 $ 41,839 $ 42,247 $ 42,746 $ 40,261 Income Tax Required 19,712 19,074 18,763 16,729 15,916 5,166 Total Preferred and Preference Dividend Requirements $ 59,815 $ 58,996 $ 60,602 $ 58,976 $ 58,662 $ 45,427 Total Fixed Charges and Preferred and Preference Dividend Requirements $284,200 $277,639 $278,328 $275,657 $295,032 $267,671 Earnings (2) $709,380 $686,535 $652,258 $573,222 $537,139 $394,760 Ratio of Earnings to Fixed Charges 3.16 3.14 3.00 2.65 2.27 1.78 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements 2.50 2.47 2.34 2.08 1.82 1.47
(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 4
UT 9-MOS DEC-31-1995 SEP-30-1995 PER-BOOK 5,473,722 1,220,999 725,389 703,475 0 8,123,585 1,424,993 0 1,396,467 2,808,610 253,500 269,185 2,509,119 0 0 13,800 329,046 87,500 0 0 1,852,825 8,123,585 2,209,087 143,303 1,640,201 1,783,504 425,583 7,950 433,533 148,455 285,078 30,135 254,943 169,656 165,746 530,457 1.73 1.73
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