-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, g98MmaftqPmdwPAwV3KDHRtDtByOf5y0WAwcolUK45oZdHGIWrsEzTsS8mM4Iw/N OKJ3W4MNA4+JNqGLyLRQ0g== 0000009466-94-000018.txt : 19940815 0000009466-94-000018.hdr.sgml : 19940815 ACCESSION NUMBER: 0000009466-94-000018 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19940630 FILED AS OF DATE: 19940812 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BALTIMORE GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000009466 STANDARD INDUSTRIAL CLASSIFICATION: 4931 IRS NUMBER: 520280210 STATE OF INCORPORATION: MD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-01910 FILM NUMBER: 94543750 BUSINESS ADDRESS: STREET 1: GAS & ELECTRIC BLDG STREET 2: CHARLES CTR CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4107835920 10-Q 1 JUNE 30, 1994 FORM 10-Q FORM 10-Q SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Quarterly Period Ended June 30, 1994 Commission file number 1-1910 BALTIMORE GAS AND ELECTRIC COMPANY - ----------------------------------------------------------------- (Exact name of registrant as specified in its charter) Maryland 52-0280210 - ----------------------------------------------------------------- (State of incorporation) (IRS Employer Identification No.) Gas and Electric Building, Charles Center, Baltimore, Maryland 21201 - ----------------------------------------------------------------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code 410-783-5920 Not Applicable - ----------------------------------------------------------------- (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes X No Common Stock, without par value - 147,442,204 shares outstanding on July 31, 1994. Page of BALTIMORE GAS AND ELECTRIC COMPANY PART I. FINANCIAL INFORMATION CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Quarter Ended June 30, Six Months Ended June 30, 1994 1993 1994 1993 (In Thousands, Except Per-Share Amounts) Revenues Electric ............................................... $ 500,177 $ 469,741 $ 1,017,325 $ 945,170 Gas ....................................................... 67,885 75,930 273,071 257,710 Diversified businesses .................................... 62,289 19,050 88,230 45,666 Total revenues ............................................ 630,351 564,721 1,378,626 1,248,546 Expenses Other Than Interest and Income Taxes Electric fuel and purchased energy ........................ 120,960 109,677 247,513 244,048 Gas purchased for resale .................................. 31,582 39,059 158,507 149,459 Operations ................................................ 135,932 127,595 285,481 259,676 Maintenance ............................................... 43,544 58,778 88,991 100,555 Diversified businesses - selling, general, and administrati 51,787 16,383 66,904 32,821 Depreciation and amortization ............................. 67,934 61,893 137,713 123,267 Taxes other than income taxes ............................. 43,734 43,949 96,529 95,239 Total expenses other than interest and income taxes ....... 495,473 457,334 1,081,638 1,005,065 Income From Operations ...................................... 134,878 107,387 296,988 243,481 Other Income Allowance for equity funds used during construction ....... 5,542 3,621 10,616 7,157 Equity in earnings of Safe Harbor Water Power Corporation . 1,088 1,068 2,178 2,136 Net other income and deductions ........................... 1,495 709 2,551 984 Total other income ........................................ 8,125 5,398 15,345 10,277 Income Before Interest and Income Taxes ..................... 143,003 112,785 312,333 253,758 Interest Expense Interest charges .......................................... 53,569 52,633 105,769 105,367 Capitalized interest ...................................... (3,010) (5,032) (5,811) (9,097) Allowance for borrowed funds used during construction ..... (2,998) (2,004) (5,739) (4,083) Net interest expense ...................................... 47,561 45,597 94,219 92,187 Income Before Income Taxes .................................. 95,442 67,188 218,114 161,571 Income Taxes Current ................................................... 10,742 (8,573) 23,886 21,108 Deferred .................................................. 20,033 21,974 49,456 23,044 Investment tax credit adjustments ......................... (2,041) (2,089) (4,081) (4,253) Total income taxes ........................................ 28,734 11,312 69,261 39,899 Net Income .................................................. 66,708 55,876 148,853 121,672 Preferred and Preference Stock Dividends .................... 10,021 10,576 20,052 21,095 Earnings Applicable to Common Stock ...................... $ 56,687 $ 45,300 $ 128,801 $ 100,577 Average Shares of Common Stock Outstanding ................. 146,947 144,757 146,692 144,471 Total Earnings Per Share of Common Stock .................... $0.39 $0.31 $0.88 $0.70 Dividends Declared Per Share of Common Stock ................ $0.3 $0.37 $0.75 $0.74 Certain prior-year amounts have been restated to conform with the current year's presentation.
See Notes to Consolidated Financial Statements. PART I. FINANCIAL INFORMATION (Continued) CONSOLIDATED BALANCE SHEETS June 30, December 31,
1994* 1993 (In Thousands) ASSETS Current Assets Cash and cash equivalents ................................... $ 49,672 $ 84,236 Accounts receivable (net of allowance for uncollectibles).... 427,585 401,853 Fuel stocks ................................................... 66,060 70,233 Materials and supplies ........................................ 144,855 145,130 Prepaid taxes other than income taxes ......................... 2,706 54,237 Other ......................................................... 31,365 38,971 Total current assets .......................................... 722,243 794,660 Investments and Other Assets Real estate projects .......................................... 470,913 487,397 Power generation systems ...................................... 298,006 298,514 Financial investments ......................................... 224,771 213,315 Nuclear decommissioning trust fund ............................ 62,806 56,207 Safe Harbor Water Power Corporation ........................... 34,156 34,138 Senior living facilities ...................................... 10,839 2,005 Other ........................................................ 60,643 65,355 Total investments and other assets ............................ 1,162,134 1,156,931 Utility Plant Plant in service Electric .................................................... 5,791,670 5,713,259 Gas ......................................................... 578,106 557,942 Common ...................................................... 501,013 487,740 Total plant in service ...................................... 6,870,789 6,758,941 Accumulated depreciation ......................................(2,212,205) (2,161,984) Net plant in service .......................................... 4,658,584 4,596,957 Construction work in progress ................................. 482,659 436,440 Nuclear fuel (net of amortization) ............................ 153,508 139,424 Plant held for future use ..................................... 24,070 24,066 Net utility plant ............................................. 5,318,821 5,196,887 Deferred Charges Regulatory Assets Income taxes recoverable through future rates ................ 262,720 259,856 Deferred fuel costs (net of reserve for possible disallowance) 133,024 130,052 Deferred termination benefit costs (net of amortization)...... 88,455 96,793 Deferred nuclear expenditures (net of amortization) .......... 88,744 86,726 Deferred postemployment benefit costs ........................ 67,900 62,892 Deferred cost of decommissioning federal uranium enrichment facilities (net of amortization) ................. 53,567 49,562 Deferred energy conservation expenditures (net of amortizatio 37,669 38,655 Deferred environmental costs (net of amortization) ........... 36,298 32,966 Other ........................................................ (3,286) 10,623 Total regulatory assets ...................................... 765,091 768,125 Other ......................................................... 70,612 70,436 Total deferred charges ........................................ 835,703 838,561 TOTAL ASSETS .................................................. $ 8,038,901 $ 7,987,039
* Unaudited See Notes to Consolidated Financial Statements. PART I. FINANCIAL INFORMATION (Continued) CONSOLIDATED BALANCE SHEETS June 30, December 31,
1994* 1993 (In Thousands) LIABILITIES AND CAPITALIZATION Current Liabilities Short-term borrowings ....................................... $ 94,800 $ 0 Current portions of long-term debt and preference stock ....... 45,032 44,516 Accounts payable .............................................. 144,347 195,534 Customer deposits ............................................. 24,275 22,345 Accrued taxes ................................................. 3,317 20,623 Accrued interest .............................................. 61,397 58,541 Dividends declared ............................................ 65,863 63,966 Accrued vacation costs ........................................ 37,771 35,546 Other ......................................................... 17,886 38,716 Total current liabilities ..................................... 494,688 479,787 Deferred Credits and Other Liabilities Deferred income taxes ......................................... 1,118,778 1,067,611 Deferred investment tax credits ............................... 153,419 157,426 Pension and postemployment benefits ........................... 134,215 183,043 Decommissioning of federal uranium enrichment facilities ...... 48,249 46,858 Other ......................................................... 52,464 56,974 Total deferred credits and other liabilities .................. 1,507,125 1,511,912 Capitalization Long-term Debt First refunding mortgage bonds of BGE ......................... 1,763,599 1,802,148 Other long-term debt of BGE ................................... 544,550 482,550 Long-term debt of Constellation Companies ..................... 579,409 597,716 Unamortized discount and premium .............................. (18,698) (17,754) Current portion of long-term debt ............................. (42,032) (41,516) Total long-term debt .......................................... 2,826,828 2,823,144 Preferred Stock ................................................. 59,185 59,185 Redeemable Preference Stock ..................................... 344,000 345,500 Current portion of redeemable preference stock ................ (3,000) (3,000) Total redeemable preference stock ............................. 341,000 342,500 Preference Stock Not Subject to Mandatory Redemption ............ 150,000 150,000 Common Shareholders' Equity Common stock .................................................. 1,414,426 1,391,464 Retained earnings ............................................. 1,269,882 1,251,140 Pension liability adjustment ................................ (22,093) (22,093) Net unrealized loss on available-for-sale securities ........ (2,140) 0 Total common shareholders' equity ............................. 2,660,075 2,620,511 Total capitalization .......................................... 6,037,088 5,995,340 TOTAL LIABILITIES AND CAPITALIZATION ......... ................. $ 8,038,901 $ 7,987,039
* Unaudited See Notes to Consolidated Financial Statements. PART I. FINANCIAL INFORMATION (Continued) CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1994 1993 (In Thousands) Cash Flows From Operating Activities Net income ................................................... $ 148,853 $ 121,672 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization .............................. 161,641 146,898 Deferred income taxes ...................................... 49,456 23,044 Investment tax credit adjustments .......................... (4,081) (4,253) Deferred fuel costs ........................................ (2,972) 42,033 Accrued pension and postemployment benefits ................ (53,833) 4,866 Allowance for equity funds used during construction......... (10,616) (7,157) Equity in earnings of affiliates and joint ventures (1,697) 5,300 Changes in current assets ......................... 36,880 27,639 Changes in current liabilities, other than short-te......... (80,522) (40,790) Other ...................................................... 17,672 (2,108) Net cash provided by operating activities .................... 260,781 317,144 Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings (net) ................................ 94,800 (10,400) Long-term debt ............................................. 203,018 702,794 Preference stock ........................................... 0 39,650 Common stock ............................................... 22,945 26,133 Reacquisition of long-term debt .............................. (213,319) (680,366) Redemption of preference stock ............................... (1,500) 0 Common stock dividends paid .................................. (108,234) (103,684) Preferred and preference stock dividends paid ................ (19,964) (21,040) Other ........................................................ (36) (261) Net cash used in financing activities ........................ (22,290) (47,174) Cash Flows From Investing Activities Utility construction expenditures ............................ (227,091) (202,864) Allowance for equity funds used during construction .......... 10,616 7,157 Nuclear fuel expenditures .................................... (35,078) (10,458) Deferred nuclear expenditures ................................ (4,066) (5,408) Deferred energy conservation expenditures .................... (18,661) (12,063) Contributions to nuclear decommissioning trust fund .......... (4,890) (4,450) Purchases of marketable equity securities .................... (31,076) (19,795) Sales of marketable equity securities ........................ 20,146 20,778 Other financial investments .................................. (676) 1,682 Real estate projects ......................................... 25,090 (14,252) Power generation systems ..................................... (5,066) (18,738) Other ........................................................ (2,303) (730) Net cash used in investing activities ........................ (273,055) (259,141) ......... Net Increase (Decrease) in Cash and Cash Equivalents ........... (34,564) 10,829 Cash and Cash Equivalents at Beginning of Period ...... 84,236 27,122 ......... Cash and Cash Equivalents at End of Period ............ $ 49,672 $ 37,951 Other Cash Flow Information Cash paid during the period for: ......... Interest (net of amounts capitalized) ...................... $ 89,395 $ 90,404 Income taxes ............................................... $ 41,025 $ 35,304 Certain prior-year amounts have been restated to conform with the current year's presentation.
See Notes to Consolidated Financial Statements. PART I. FINANCIAL INFORMATION (Continued) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Results for interim periods, which can be largely influenced by weather conditions, are not necessarily indicative of results to be expected for the year. The preceding interim financial statements of Baltimore Gas and Electric Company (BGE) and Subsidiaries (collectively, the Company) reflect all adjustments which are, in the opinion of Management, necessary for the fair presentation of the Company's financial position and results of operations for such interim periods. These adjustments are of a normal recurring nature. Statement of Financial Accounting Standards No. 115 The Company adopted Statement of Financial Accounting Standards No. 115 (Statement No. 115), "Accounting for Certain Investments in Debt and Equity Securities", effective January 1, 1994. As of June 30, 1994, marketable equity securities totaling $40.7 million, which are included in financial investments in the consolidated balance sheets, and the nuclear decommissioning trust fund have been classified as available-for-sale in accordance with the requirements of Statement No. 115. Changes in the fair value of these securities are included in common shareholders' equity. Long-term Debt of BGE The following is a summary of issuances and early redemptions of long-term debt that have occurred or have been announced during the period January 1, 1994 through the date of this Report. The net proceeds from the new issuances were used for general corporate purposes relating to BGE's utility business, including the redemptions. Gains and losses on the reacquisition of debt are amortized over the remaining original lives of the issuances. Principal Amount Issue Net Issuances Issued Date Proceeds (Amounts in Thousands) First Refunding Mortgage Bonds Floating Rate Series due 4/15/99 $125,000 3/21/94 $124,438 6.00% Pollution Control Revenue Refunding Loan due 4/1/24 75,000 4/14/94 73,971 6 PART I. FINANCIAL INFORMATION (Continued) Redemption Price as a Principal % of the Amount Redemption Principal Early Redemptions Redeemed Date Amount (Amounts in Thousands) First Refunding Mortgage Bonds: 7 1/4% Series due 4/15/01 $59,911 3/11/94 101.88% 6.80% Series due 9/15/04 20,000 4/14/94 101.00 6.90% Installment Series due 9/15/09 55,000 4/14/94 101.00 7% Series due 1998 28,638 4/18/94 101.11 In addition, in connection with the annual sinking fund required by BGE's mortgage, on August 1, 1994, the following principal amounts of First Refunding Mortgage Bonds were redeemed: $11,986,000 of the 9-1/8% Series due October 15, 1995, $3,775,000 of the 8.40% Series due October 15, 1999, $2,550,000 of the 8-3/8% Series due August 15, 2001, and $473,000 from various other series. Diversified Business Financing Matters See Management's Discussion and Analysis of Financial Condition and Results of Operations - Diversified Businesses Capital Requirements for additional information about the debt of the Constellation Company and its subsidiaries. Environmental Matters The Clean Air Act of 1990 (the Act) contains provisions designed to reduce sulfur dioxide and nitrogen oxide emissions from electric generating stations in two separate phases. Under Phase I of the Act, which must be implemented by 1995, BGE expects to incur expenditures of approximately $55 million, most of which is attributable to its portion of the cost of installing a flue gas desulfurization system at the Conemaugh generating station, in which BGE owns a 10.56% interest. BGE is currently examining what actions will be required in order to comply with Phase II of the Act, which must be implemented by 2000. However, BGE anticipates that compliance will be attained by some combination of fuel switching, flue gas desulfurization, unit retirements, or allowance trading. At this time, plans for complying with nitrogen oxide (NOx) control requirements under the Act are less certain because all implementation regulations have not yet been finalized by the government. It is expected that by the year 2000 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 7 PART I. FINANCIAL INFORMATION (Continued) prior to the issuance of such regulations. Based on existing and proposed ozone nonattainment regulations, BGE currently estimates that the NOx controls at BGE's generating plants will cost approximately $70 million. BGE is currently unable to predict the cost of compliance with the additional requirements at other BGE facilities. BGE has been notified by the Environmental Protection Agency and several state agencies that it is being considered a potentially responsible party with respect to the cleanup of certain environmentally contaminated sites owned and operated by third parties. Although the cleanup costs for certain environmentally contaminated sites could be significant, BGE believes that the resolution of these matters will not have a material effect on its financial position or results of operations. Also, BGE is coordinating investigation of several former gas manufacturing plant sites, including exploration of corrective action options to remove coal tar. However, no formal legal proceedings have been instituted. As of June 30, 1994, BGE has an accrual of approximately $27.8 million for estimated future environmental costs at these sites. Based on previous actions of the Public Service Commission of Maryland (PSC), BGE has deferred these estimated future costs, as well as actual costs which have been incurred to date, as a regulatory asset. The technology for cleaning up such sites is still developing, and potential remedies for these sites have not been identified. Cleanup costs in excess of the amounts recognized, which could be significant in total, cannot presently be estimated. Nuclear Insurance An accident or an extended outage at either unit of the Calvert Cliffs Nuclear Power Plant could have a substantial adverse effect on BGE. The primary contingencies resulting from an incident at the Calvert Cliffs plant would involve the physical damage to the plant, the recoverability of replacement power costs, and BGE's liability to third parties for property damage and bodily injury. Although BGE maintains the various insurance policies currently available to provide coverage for portions of these contingencies, BGE does not consider the available insurance to be adequate to cover the costs that could result from a major accident or an extended outage at either of the Calvert Cliffs units. In addition, in the event of an incident at any commercial nuclear power plant in the country, BGE could be assessed for a portion of any third party claims associated with the incident. Under the provisions of the Price Anderson Act, the limit for third party claims from a nuclear incident is $9.2 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. 8 PART I. FINANCIAL INFORMATION (Continued) BGE and other operators of commercial nuclear power plants in the United States are required to purchase insurance to cover claims of certain nuclear workers. Other non-governmental commercial nuclear facilities may also purchase such insurance. Coverage of up to $400 million is provided for claims against BGE or others insured by these policies for radiation injuries. If certain claims were made under these policies, BGE and all policyholders could be assessed, with BGE's share being up to $6.2 million in any one year. For physical damage to Calvert Cliffs, BGE has $2.75 billion of property insurance, including $1.4 billion from an industry mutual insurance company. If accidents at any insured plants cause a shortfall of funds at the industry mutual, BGE and all policyholders could be assessed, with BGE's share being up to $14.6 million. If an outage at Calvert Cliffs is caused by an insured physical damage loss and lasts more than 21 weeks, BGE has up to $426 million per unit of insurance, provided by a different industry mutual insurance company for replacement power costs. This amount can be reduced by up to $85 million per unit if an outage to both units at Calvert Cliffs is caused by a singular insured physical damage loss. If an outage at any insured plant causes a shortfall of funds at the industry mutual, BGE and all policyholders could be assessed, with BGE's share being up to $9.4 million. Recoverability of Electric Fuel Costs By statute, actual electric fuel costs are recoverable so long as the PSC finds that BGE demonstrates that, among other things, it has maintained the productive capacity of its generating plants at a reasonable level. The PSC and Maryland's highest appellate court have interpreted this as permitting a subjective evaluation of each unplanned outage at BGE's generating plants to determine whether or not BGE had implemented all reasonable and cost-effective maintenance and operating control procedures appropriate for preventing the outage. Effective January 1, 1987, the PSC authorized the establishment of a Generating Unit Performance Program (GUPP) to measure, annually, utility compliance with maintaining the productive capacity of generating plants at reasonable levels by establishing a system-wide generating performance target and individual performance targets for each base load generating unit. In future fuel rate hearings, actual generating performance after adjustment for planned outages will be compared to the system-wide target and, if met, should signify that BGE has complied with the requirements of Maryland law. Failure to meet the system-wide target will result in review of each unit's adjusted actual generating performance versus its performance 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 9 PART I. FINANCIAL INFORMATION (Continued) respect to any given generating plant outage, which could result in the disallowance of replacement energy costs by the PSC. Since the two units at BGE's Calvert Cliffs Nuclear Power Plant utilize BGE's lowest cost fuel, replacement energy costs associated with outages at these units can be significant. BGE cannot estimate the amount of replacement energy costs that could be challenged or disallowed in future fuel rate proceedings, but such amounts could be material. In October 1988, BGE filed its first fuel rate application for a change in its electric fuel rate under GUPP. The resultant case before the PSC covers BGE's operating performance in calendar year 1987, and BGE's filing demonstrated that it met the system- wide and individual nuclear plant performance targets for 1987. In November 1989, testimony was filed on behalf of the Maryland People's Counsel (People's Counsel) alleging that seven outages at the Calvert Cliffs plant in 1987 were due to management imprudence and that the replacement energy costs associated with those outages should be disallowed by the Commission. Total replacement energy costs associated with the 1987 outages were approximately $33 million. In May 1989, BGE filed its fuel rate case in which 1988 performance was examined. BGE met the system-wide and nuclear plant performance targets in 1988. People's Counsel alleged that BGE imprudently managed several outages at Calvert Cliffs, and BGE estimates that the total replacement energy costs associated with these 1988 outages were approximately $2 million. On November 14, 1991, a Hearing Examiner at the PSC issued a proposed Order, which became final on December 17, 1991 and concluded that no disallowance was warranted. The Hearing Examiner found that BGE maintained the productive capacity of the Plant at a reasonable level, noting that it produced a near record amount of power and exceeded the GUPP standard. Based on this record, the Order concluded there was sufficient cause to excuse any avoidable failures to maintain productive capacity at higher levels. During 1989, 1990, and 1991, BGE experienced extended outages at its Calvert Cliffs Nuclear Power Plant. In the Spring of 1989, a leak was discovered around the Unit 2 pressurizer heater sleeves during a refueling outage. BGE shut down Unit 1 as a precautionary measure on May 6, 1989, to inspect for similar leaks and none were found. However, Unit 1 was out of service for the remainder of 1989 and 285 days of 1990 to undergo maintenance and modification work to enhance the reliability of various safety systems, to repair equipment, and to perform required periodic surveillance tests. Unit 2, which returned to service on May 4, 1991, remained out of service for the remainder 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. 10 PART I. FINANCIAL INFORMATION (Continued) In a December 1990 order issued by the PSC in a BGE base rate proceeding, the PSC found that certain operations and maintenance expenses incurred at Calvert Cliffs during the test year should not be recovered from ratepayers. The PSC found that this work, which was performed during the 1989-1990 Unit 1 outage and fell within the test year, was avoidable and caused by BGE actions which were deficient. The PSC noted in the order that its review and findings on these issues pertain to the reasonableness of BGE's test-year operations and maintenance expenses for purposes of setting base rates and not to the responsibility for replacement power costs associated with the outages at Calvert Cliffs. The PSC stated that its decision in the base rate case will have no res judicata (binding) effect in the fuel rate proceeding examining the 1989- 1991 outages. The work characterized as avoidable significantly increased the duration of the Unit 1 outage. Despite the PSC's statement regarding no binding effect, BGE recognizes that the views expressed by the PSC make the full recovery of all of the replacement energy costs associated with the Unit 1 outage doubtful. Therefore, in December 1990, BGE recorded a provision of $35 million against the possible disallowance of such costs. BGE cannot determine whether replacement energy costs may be disallowed in the present fuel rate proceeding in excess of the provision, but such amounts could be material. 11 PART I. FINANCIAL INFORMATION (Continued) MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The financial condition and results of operations of Baltimore Gas and Electric Company (BGE) and its subsidiaries (collectively, the Company) are set forth in the Consolidated Financial Statements and Notes to Consolidated Financial Statements (Notes) sections of this Report. Factors significantly affecting results of operations, liquidity, and capital resources are discussed below. RESULTS OF OPERATIONS FOR THE QUARTER AND SIX MONTHS ENDED JUNE 30, 1994 COMPARED WITH THE CORRESPONDING PERIODS OF 1993 Earnings per Share of Common Stock Consolidated earnings per share for the quarter and six months ended June 30, 1994 were $.39 and $.88, respectively, which represent increases of $.08 and $.18 compared to the earnings for the corresponding periods of 1993. These increases in earnings per share reflect a higher level of earnings applicable to common stock, offset slightly by the larger number of common shares outstanding. The earnings per share are summarized as follows: Quarter Ended Six Months Ended June 30 June 30 1994 1993 1994 1993 Utility operations............. $.38 $.28 $.86 $.66 Diversified businesses......... .01 .03 .02 .04 Total.......................... $.39 $.31 $.88 $.70 Earnings Applicable to Common Stock Earnings applicable to common stock increased $11.4 million during the quarter and $28.2 million during the six months ended June 30, 1994. These increases reflect significantly higher earnings from the utility operations, offset slightly by lower earnings from diversified businesses. Earnings from utility operations increased during the second quarter of 1994 primarily as a result of increased electric sales and lower maintenance expenses compared to the second quarter of 1993. Two principal factors produced the increase in sales of electricity: the spring and early summer of 1994 were significantly hotter than 1993; and the number of customers increased moderately. The effect of weather on utility sales is discussed on pages 13 and 14. 12 PART I. FINANCIAL INFORMATION (Continued) In addition to the factors noted above for the second quarter of 1994, earnings from utility operations during the six months ended June 30, 1994 also reflect increased electric system sales and gas sales caused by colder winter weather and a moderate increase in the number of customers during the first quarter of 1994 as compared to the first quarter of 1993. These increases were offset partially by higher operations expense, depreciation and amortization expenses, and the effect of the Omnibus Budget Reconciliation Act of 1993 (1993 Tax Act), which increased the federal corporate income tax rate to 35% from 34%. The following factors influence BGE's utility operations earnings: regulation by the Public Service Commission of Maryland (PSC), the effect of weather and economic conditions on sales, and competition in the generation and sale of electricity. The base rate increases authorized by the PSC in April 1993 favorably affected utility earnings through April 1994. Several electric fuel rate cases now pending before the PSC discussed in Notes 1 and 13 of the Form 10-K for the year ended December 31, 1993 (Form 10- K) could also affect future years' earnings. Electric utilities presently face competition in the construction of generating units to meet future load growth and in the sale of electricity in the bulk power markets. Electric utilities also face the future prospect of competition for electric sales to retail customers. It is not possible to predict currently the ultimate effect competition will have on BGE's earnings in future years. Earnings from diversified businesses, which primarily represent the operations of Constellation Holdings, Inc. and its subsidiaries (collectively, the Constellation Companies), were slightly lower during the quarter and six months ended June 30, 1994. Diversified businesses' earnings are discussed on pages 21 through 23. Effect of Weather on Utility Sales Weather conditions affect BGE's utility sales. BGE measures weather conditions using degree days. A degree day is the difference between the average daily actual temperature and the baseline temperature of 65 degrees. Colder weather during the winter, as measured by greater heating degree days, results in greater demand for electricity and gas to operate heating systems. Conversely, warmer weather during the winter, measured by fewer heating degree days, results in less demand for electricity and gas to operate heating systems. Hotter weather during the summer, measured by more cooling degree days, results in greater demand for electricity to operate cooling systems. Conversely, cooler weather during the summer, measured by fewer cooling degree days, results in less demand for electricity to operate cooling systems. The degree-days chart below presents information regarding heating and cooling degree days for the quarter and six months ended June 30, 1994 and 1993. 13 PART I. FINANCIAL INFORMATION (Continued) Quarter Ended Six Months Ended June 30 June 30 1994 1993 1994 1993 Heating degree days............ 444 5413,196 3,104 Percent change compared to prior period.................. (17.9)% 3.0% Cooling degree days............ 320 213 320 213 Percent change compared to prior period.................. 50.2% 50.2% BGE Utility Revenues and Sales Electric revenues changed during 1994 because of the following factors: Quarter Ended Six Months Ended June 30 June 30 1994 vs. 1993 1994 vs. 1993 (In millions) System sales volumes.......... $17.7 $53.9 Base rates.................... 3.1 15.4 Fuel rates.................... 0.3 (9.4) Revenues from system sales.... 21.1 59.9 Interchange sales............. 9.8 13.6 Other revenues................ (0.5) (1.3) Total......................... $30.4 $72.2 Electric system sales represent volumes sold to customers within BGE's service territory at rates determined by the PSC. These amounts exclude interchange sales, discussed separately later. As of December 31, 1993, BGE changed its classification of commercial and industrial customers to present this information on a basis which is more consistent with predominant industry practices. Prior-period amounts have been reclassified to conform to the current period's presentation. Below is a comparison of the changes in electric system sales volumes. 14 PART I. FINANCIAL INFORMATION (Continued) Quarter Ended Six Months Ended June 30 June 30 1994 vs. 1993 1994 vs. 1993 Residential................... 2.7% 8.4% Commercial.................... 2.9 1.6 Industrial.................... 29.5 18.1 Total......................... 6.9 6.7 Sales to all classes of electric customers reflect the positive impact of hotter spring and early summer weather and moderate customer growth during the second quarter of 1994 as compared to the second quarter of 1993. Sales to industrial customers also reflect an increase in the sale of electricity to Bethlehem Steel which purchased more electricity from BGE due to increased steel production and the fact that Bethlehem Steel is now purchasing its full electricity requirements from BGE. Bethlehem Steel is still producing power with its own generating facility, but is now selling the output from this facility to BGE rather than using the power to reduce its requirements. In addition to the factors noted above for the second quarter of 1994, electric system sales for the six months ended June 30, 1994 reflect severe winter weather conditions during the first quarter of 1994. The increase in sales to commercial customers was partially offset by lower usage-per-customer. Base rates increased in 1994 for two principal reasons: the PSC's April 1993 rate order and an increased recovery of eligible electric conservation program costs through the energy conservation surcharge. The April 1993 rate order provided for an annualized electric base rate increase of $84.9 million including a return on BGE's higher level of electric rate base. The order also reduced the authorized rate of return to 9.40% from the previous rate of 9.94%. Base rate revenues are expected to increase during the remainder of 1994 as a result of recovering a higher level of electric conservation program costs under the energy conservation surcharge. However, 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. BGE has been earning in excess of its authorized rate of return on electric operations since September 30, 1993. As a result, BGE has deferred the portion of electric energy conservation revenues subject to refund beginning in December 1993. The deferral of these billings is expected to average approximately $1.7 million each month these deferrals continue. The amounts deferred during a surcharge year will begin to be refunded to customers with interest in the ensuing July when the annual 15 PART I. FINANCIAL INFORMATION (Continued) resetting of the conservation surcharge rates occurs. The deferral will continue as long as BGE exceeds its authorized rate of return on electric operations, as determined by the PSC. Changes in fuel rate revenues result from the operation of the electric fuel rate formula. The fuel rate formula is designed to recover the actual cost of fuel, net of revenues from interchange sales. (See Notes 1 and 13 of the Form 10-K.) Changes in fuel rate revenues and interchange sales normally do not affect earnings. However, if the PSC was to disallow recovery of any part of these costs, earnings would be reduced as discussed in Note 13 of the Form 10-K. Fuel rate revenues were essentially flat during the second quarter of 1994 as the effect of increased electric system sales volumes offset the lower fuel rate. Fuel rate revenues decreased during the six months ended June 30, 1994 due to a lower fuel rate, offset partially by increased electric system sales volumes. The fuel rate was lower because of a less costly twenty-four month generation mix due to greater generation at the Calvert Cliffs Nuclear Power Plant compared to 1993. BGE expects electric fuel rate revenues will decrease during 1994 because of a less-costly generation mix. Interchange sales are sales of BGE's energy to the Pennsylvania - New Jersey - Maryland Interconnection (PJM), a regional power pool of eight member companies including BGE. Interchange sales occur after BGE has satisfied the demand for its own system sales of electricity if BGE's available generation is the least costly available to PJM utilities. Interchange sales increased during the quarter and six months ended June 30, 1994 because BGE had a less costly generation mix than other PJM utilities. The less costly mix relative to other PJM companies during 1994 reflects greater generation from the Brandon Shores Power Plant and continued operation of the Calvert Cliffs Nuclear Power Plant. Gas revenues changed during 1994 because of the following factors: Quarter Ended Six Months Ended June 30 June 30 1994 vs. 1993 1994 vs. 1993 (In millions) Sales volumes................. $(1.2) $5.0 Base rates.................... 0.5 1.2 Gas cost adjustment revenues.. (6.9) 10.1 Other revenues................ (0.4) (0.9) Total......................... $(8.0) $15.4 16 PART I. FINANCIAL INFORMATION (Continued) As of December 31, 1993, BGE changed its classification of commercial and industrial customers to present this information on a basis which is more consistent with predominant industry practices. Prior-period amounts have been reclassified to conform to the current period's presentation. Below is a comparison of the changes in gas sales volumes: Quarter Ended Six Months Ended June 30 June 30 1994 vs. 1993 1994 vs. 1993 Residential................... 0.7% 6.4% Commercial.................... (10.8) (3.9) Industrial.................... 4.7 (5.6) Total......................... (1.0) (0.3) Total gas sales for the second quarter of 1994 decreased slightly compared to last year as the lower sales to commercial customers offset the higher sales to residential and industrial customers. Sales to commercial customers were affected negatively by warmer weather conditions and lower usage-per-customer. The increase in sales to industrial customers reflects primarily the greater usage of natural gas by Bethlehem Steel in its production process. Total gas sales for the six months ended June 30, 1994 were essentially flat compared to 1993 because higher sales to residential customers were offset by lower sales to commercial and industrial customers. The increase in sales to residential customers reflects the colder winter weather during the first quarter of 1994 as compared to 1993, and to a lesser extent customer growth. Sales to commercial and industrial customers decreased primarily because delivery service customers either voluntarily switched their fuel source from natural gas to alternate fuels, or were involuntarily interrupted by BGE as a result of the extreme winter weather conditions. Interruptible customers maintain alternate fuel sources and pay reduced rates in exchange for BGE's right to interrupt service during periods of peak demand. Base rates increased slightly during 1994 due to an increased recovery of eligible gas conservation program costs through the energy conservation surcharge. The continued recovery of gas conservation program costs under the energy conservation surcharge will continue to increase base rate revenues in 1994. Changes in gas cost adjustment revenues result primarily from the operation of the purchased gas adjustment clause, commodity charge adjustment clause, and the actual cost adjustment clause which are designed to recover actual gas costs. (See Note 1 of the 17 PART I. FINANCIAL INFORMATION (Continued) Form 10-K.) Changes in gas cost adjustment revenues normally do not affect earnings. Gas cost adjustment revenues decreased during the second quarter of 1994 because of lower sales volumes subject to gas cost adjustment clauses and decreased prices of purchased gas. During the six months ended June 30, 1994, gas cost adjustment revenues increased over last year due to the combination of higher sales volumes subject to gas cost adjustment clauses and increased prices of purchased gas during the first quarter. Delivery service sales volumes are not subject to gas cost adjustment clauses because these customers purchase their gas directly from third parties. BGE Utility Fuel and Energy Expenses Electric fuel and purchased energy expenses were as follows: Quarter Ended Six Months Ended June 30 June 30 1994 1993 1994 1993 (In millions) Actual costs.................. $119.9 $105.0 $273.2 $227.8 Net (deferral) recovery of costs under electric fuel rate clause (see Note 1 of the Form 10-K)............... 1.1 4.7 (25.7) 16.2 Total......................... $121.0 $109.7 $247.5 $244.0 Electric fuel and purchased energy expenses increased during the quarter and six months ended June 30, 1994 because of significant increases in actual fuel costs, offset partially by changes in deferred fuel costs as a result of the operation of the electric fuel rate clause. Actual electric fuel and purchased energy costs increased during the quarter ended June 30, 1994 as a result of higher net output of electricity generated to meet the demand of BGE's system and the PJM system and a more costly generation mix. Actual electric fuel and purchased energy costs increased during the six months ended June 30, 1994 primarily due to the higher cost of BGE's generation mix. The cost of the generation mix increased due to refueling and maintenance outages at Calvert Cliffs Nuclear Power Plant and higher purchased energy costs during the first quarter. 18 PART I. FINANCIAL INFORMATION (Continued) Purchased gas expenses were as follows: Quarter Ended Six Months Ended June 30 June 30 1994 1993 1994 1993 (In millions) Actual costs.................. $30.5 $44.5 $153.2 $141.5 Net (deferral) recovery of costs under purchased gas adjustment clause (see Note 1 of the Form 10-K).......... 1.1 (5.4) 5.3 8.0 Total......................... $31.6 $39.1 $158.5 $149.5 Actual purchased gas costs decreased during the quarter ended June 30, 1994 as a result of lower output associated with the reduced demand for BGE gas and, to a lesser extent, lower gas prices. The lower gas prices primarily reflect $6.5 million of take-or-pay refunds and other market conditions. Actual purchased gas costs increased during the six months ended June 30, 1994 due to higher gas prices and, to a lesser extent, the higher output associated with the increased demand for BGE gas during the first quarter. The higher gas prices reflect primarily higher reservation charges, greater transition costs related to the implementation of Federal Energy Regulatory Commission (FERC) Order No. 636, and market conditions, offset partially by the take-or-pay and other supplier refunds. The take-or-pay refunds represent a $16.6 million refund received during the second quarter of 1994 from Columbia Gas Transmission Corporation (Columbia Gas). The refund resulted from a FERC action regarding the reallocation of take-or-pay amounts charged to BGE by Columbia Gas between September 1988 and December 1990. A portion of this refund was returned to customers during June, 1994. The remainder of the refund will be returned to BGE's gas customers over the next three quarters pursuant to an agreement with the PSC. Purchased gas costs exclude gas purchased by delivery service customers, including Bethlehem Steel, who obtain gas directly from third parties. Future purchased gas costs are expected to continue to increase due to additional transition costs incurred by BGE gas pipeline suppliers. These transition costs, if approved by FERC, will be passed on to BGE customers through the purchased gas adjustment clause. 19 PART I. FINANCIAL INFORMATION (Continued) Other Operating Expenses Operations expense increased during the quarter and six months ended June 30, 1994 because the quarter ended June 30, 1993 reflected a reduction in utility operations expense equivalent to the $9.8 million cost of termination benefits associated with the Company's 1992 Voluntary Special Early Retirement Program (VSERP). Excluding this factor, operations expense for the second quarter of 1994 was approximately $1.5 million lower than last year as the labor savings achieved from employee reduction programs exceeded the higher amortization of the deferred VSERP costs (See Note 7 of the Form 10-K), higher uncollectible expenses, and increased pension costs and postretirement benefit expenses resulting from the implementation of Statement of Financial Accounting Standards No. 106 (see Note 6 of the Form 10-K). In addition to the factors noted above for the second quarter of 1994, operations expense for the six months ended June 30, 1994 reflects a one-time bonus paid to employees during the first quarter of 1994 in lieu of a general wage increase. In June 1994, BGE reclassified the amortization of deferred energy conservation expenditures and deferred nuclear expenditures from operations expense to depreciation and amortization expense. In addition, BGE reclassified diversified businesses' expenses from operations expense to diversified businesses - selling, general, and administrative expense. Prior-period amounts have been restated to conform with the current presentation. Operations expense is expected to be reduced during the remainder of 1994 due to continued cost savings realized from the 1993 employee reduction programs and the absence of the December 1993 one-time cost of employee reduction programs. These lower costs are expected to exceed the continued increase in the amortization of deferred VSERP costs and other increases in operations expenses. Maintenance expense decreased during the quarter and six months ended June 30, 1994 primarily because of lower costs at the Calvert Cliffs Nuclear Power Plant. Depreciation and amortization expense increased during the second quarter of 1994 because of a higher level of energy conservation program costs, higher depreciable plant in service, and amortization of deferred environmental costs for certain Company-owned sites beginning in October 1993. (See Environmental Matters on page 23.) The increase in depreciable plant in service resulted from the addition of electric transmission and distribution plant and certain capital additions at the Calvert Cliffs Nuclear Power Plant during 1994 and 1993. 20 PART I. FINANCIAL INFORMATION (Continued) Other Income and Expenses The allowance for funds used during construction (AFC) increased during the quarter and six months ended June 30, 1994 because of a higher level of construction work in progress which was offset partially by the lower AFC rate established by the PSC in the April 1993 rate order. Interest charges increased slightly during both periods of 1994 as the impact of a higher level of outstanding debt was offset substantially by a decline in the level of interest rates and the redemption of higher cost coupon debt of BGE. Capitalized interest decreased during the quarter and six months ended June 30, 1994 due to lower capitalized interest on the Constellation Companies' power generation systems projects. The decrease during the six month period was offset partially by BGE beginning to accrue carrying charges on electric deferred fuel costs excluded from rate base. (See Note 5 of the Form 10-K.) Income tax expense increased during both periods of 1994 because of higher pre-tax earnings and the effect of the 1993 Tax Act, which increased the federal corporate income tax rate to 35% from 34%. Diversified Businesses Earnings Earnings per share from diversified businesses were: Quarter Ended Six Months Ended June 30 June 30 1994 1993 1994 1993 Power generation systems...... $.00 $.03 $.01 $.04 Financial investments......... .01 .01 .02 .02 Real estate development and senior living facilities..... .00 (.01) (.01) (.02) Total......................... $.01 $.03 $.02 $.04 The Constellation Companies' power generation systems business includes the development, ownership, management, and operation of wholesale power generating projects in which the Constellation Companies hold ownership interests, as well as the provision of services to power generation projects under operation and maintenance contracts. Power generation systems earnings were lower for both periods of 1994 as the second quarter of 1993 included the recognition of $8 million of energy tax credits related to the Puna geothermal plant, offset partially by a $4 million after-tax charge related to fuel supply problems at the Panther Creek waste-coal project. 21 PART I. FINANCIAL INFORMATION (Continued) The Constellation Companies' investment in wholesale power generating projects includes $161 million representing ownership interests in 16 projects that sell electricity in California under Interim Standard Offer No. 4 power purchase agreements. Under these agreements, the projects supply electricity to purchasing utilities at a fixed rate for the first ten years of the agreements and at variable rates based on the utilities' avoided cost for the remaining term of the agreements. Avoided cost generally represents a utility's next lowest cost generation to service the demands on its system. These power generation projects are scheduled to convert to supplying electricity at avoided cost rates in various years beginning in late 1996 through the end of 2000. As a result of declines in purchasing utilities' avoided costs subsequent to the inception of these agreements, revenues at these projects based on current avoided cost levels would be substantially lower than revenues presently being realized under the fixed price terms of the agreements. If current avoided cost levels were to continue into 1996 and beyond, the Constellation Companies could experience reduced earnings or incur losses associated with these projects, which could be significant. The Constellation Companies are investigating 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. The Company cannot predict the impact these matters 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 unchanged in 1994. 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 six months ended June 30, 1994 improved slightly due to gains recognized from the sale of two retail centers, an office building and Constellation's interests in two senior living facilities. The increases in diversified businesses' revenues and in selling, general and administrative expenses for both periods reflect the proceeds of these sales and the cost of the facilities sold, respectively. The Constellation Companies' real estate portfolio has experienced continuing carrying costs and depreciation. During 1991, the Constellation Companies began expensing rather than 22 PART I. FINANCIAL INFORMATION (Continued) capitalizing interest on certain undeveloped land where development activities were at minimal levels. These factors have affected earnings negatively during 1994 and 1993 and are expected to continue to do so until current market conditions improve. Cash flow from real estate operations has been insufficient to cover the debt service requirements of certain of these projects. Resulting cash shortfalls have been satisfied through cash infusions from Constellation Holdings, Inc., which obtained the funds through a combination of cash flow generated by other Constellation Companies and its corporate borrowings. Until the real estate market shows sustained improvement, earnings from real estate activities are expected to remain depressed. The Constellation Companies continued investment in real estate projects is a function of market demand, interest rates, credit availability, and the strength of the economy in general. The Constellation Companies' Management believes that although the real estate market is beginning to show signs of improvement, until the economy reflects sustained growth and the excess inventory in the market in the Baltimore-Washington corridor goes down, real estate values will not improve significantly. If the Constellation Companies were to sell their real estate projects in the current depressed market, losses would occur in amounts difficult to determine. Depending upon market conditions, future sales could also result in losses. In addition, were the Constellation Companies to change their intent about any project from an intent to hold until market conditions improve to an intent to sell, applicable accounting rules would require a write-down of the project to market value at the time of such change in intent if market value is below book value. 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 June 30, 1994, the Company's ratio of earnings to fixed charges and ratio of earnings to combined fixed charges and preferred and preference dividend requirements were 3.27 and 2.55, respectively. 23 PART I. FINANCIAL INFORMATION (Continued) Capital Requirements The Company's capital requirements reflect the capital- intensive nature of the utility business. Actual capital requirements for the six months ended June 30, 1994, along with estimated annual amounts for the years 1994 through 1996, are reflected below. Six Months Ended June 30 Calendar Year Estimate 1994 1994 1995 1996 (In millions) Utility Business: Construction expenditures (excluding AFC) Electric........................ $173 $345 $241 $223 Gas............................. 24 52 53 69 Common.......................... 14 53 56 48 Total construction expenditures. 211 450 350 340 AFC............................. 16 34 34 20 Deferred nuclear expenditures... 4 13 - - Deferred energy conservation expenditures.................... 19 48 45 40 Nuclear fuel (uranium purchases and processing charges)......... 35 49 56 59 Retirement of long-term debt and redemption of preference stock .......................... 180 203 268 98 Total utility business.......... 465 797 753 557 Diversified Businesses: Retirement of long-term debt.... 34 37 88 60 Investment requirements......... 26 59 65 19 Total diversified businesses.... 60 96 153 79 Total............................ $525 $893 $906 $636 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 the Calvert Cliffs Nuclear Power Plant, scheduled to be placed in service in 1995; the construction of a 140-megawatt combustion turbine at Perryman, scheduled to be placed in service in 1995, which the PSC authorized in an order dated March 25, 1993; and improvements in BGE's existing generating plants and its transmission and distribution facilities. Future electric construction expenditures do not include additional generating units in light of the competitive bidding process established by the PSC. The Company estimates currently that expenditures for compliance with the sulfur dioxide provisions of the Clean Air Act of 1990 will total approximately $55 million through 1995. During the twelve months ended June 30, 1994, the internal generation of cash from utility operations provided 66% of the funds required for BGE's capital requirements exclusive of retirements and redemptions of debt and preference stock. During the three-year period 1994 through 1996, the Company expects to provide through utility operations approximately 70% of the funds 24 PART I. FINANCIAL INFORMATION (Continued) required for BGE's capital requirements, exclusive of retirements and redemptions. Utility capital requirements not met through the internal generation of cash are met through the issuance of debt and equity securities. From January 1, 1994 through the date of this Report, BGE's issuances of long-term debt and common stock were $200 million and $34 million, respectively. During the same period, retirements and redemptions of BGE's long-term debt and preference stock totaled $196 million and $3 million, respectively, exclusive of any redemption premiums or discounts. The amount and timing of future issuances and redemptions will depend upon market conditions and BGE's actual capital requirements. The Constellation Companies' capital requirements are discussed below in the section titled "Diversified Businesses Capital Requirements - Debt and Liquidity." The Constellation Companies plan to meet their capital requirements with a combination of debt and internal generation of cash from their operations. Additionally, from time to time, BGE may make loans to Constellation Holdings, Inc., or contribute equity to enhance the capital structure of Constellation Holdings, Inc. Diversified Businesses Capital Requirements Debt and Liquidity The Constellation Companies intend to meet capital requirements by refinancing debt as it comes due and through internally generated cash. These internal sources include cash that may be generated from operations, sale of assets, and cash generated by tax benefits earned by the Constellation Companies. In the event the Constellation Companies can obtain reasonable value for real estate properties, additional cash may become available through the sale of projects (for additional information see the discussion of the real estate business and market on pages 21 to 23 under the heading "Diversified Businesses Earnings"). The ability of the Constellation Companies to sell or liquidate assets described above will depend on market conditions, and no assurances can be given that such sales or liquidations can be made. Also, to provide additional liquidity to meet interim financial needs, CHI may enter into additional credit facilities. 25 PART I. FINANCIAL INFORMATION (Continued) Investment Requirements The investment requirements of the Constellation Companies include its portion of equity funding to committed projects under development, as well as net loans made to project partnerships. Investment requirements for the years 1994 through 1996 reflect the Constellation Companies' estimate of funding for ongoing and anticipated projects and are subject to continuous review and modification. Actual investment requirements may vary significantly from the estimates on page 24 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. 26 PART II. OTHER INFORMATION (Continued) ITEM 1. Legal Proceedings Puna Project As discussed in previous filings made by the Company under the Securities Exchange Act of 1934, the Constellation Companies have a 50% ownership interest in a joint venture, Puna Geothermal Venture (PGV). PGV developed and is operating a 25-megawatt geothermal energy project on the island of Hawaii (the Big Island) in the State of Hawaii (the Puna project). Construction of the Puna project was scheduled to be completed during 1991; however, it began generating electricity on April 22, 1993. PGV sells the electricity it generates to Hawaii Electric Light Company, Inc. ("Hawaii Electric") under a power purchase agreement that calls for the supply by PGV of at least 22 megawatts. Through the date of this Report, the Constellation Companies' investment in the Puna project was $81.1 million. In addition, the Constellation Companies had loaned $5.5 million (including accrued interest) to the other partner in PGV for use in funding venture costs but such loan has been repaid. PGV has outstanding a $93.4 million construction loan. In connection with the construction loan, Constellation Investments, Inc. (CII) provided a guarantee to the lending institution that requires CII to put up to $15 million of equity into the Puna project in certain events. The lender has the right to call the guarantee but has not done so. Negotiations are ongoing with the project lenders to convert the construction loan to permanent financing. The diversified businesses section of the capital requirements chart on page 24 includes $11 million for the year 1994 and $14 million for the year 1995 relating to the Puna project. Of this amount, approximately $11 million is additional costs to deal with the problems with the production wells described below and approximately $14 million is additional equity that the Constellation Companies will be required to contribute to PGV under the CII guarantee. The Company cannot predict the impact that the matters involving the Puna project discussed below may have on the Constellation Companies or the Company, but such impact could be material. PGV currently has two production wells that provide steam to power the project. During November 1993, one of the production wells changed from a steam dominated resource to a brine dominated resource. The result is that the well produces considerably more fluid to inject back into the ground. As a result certain modifications to the brine handling system have recently been completed. In addition, during April 1994, an obstruction in the well casing was detected in the other production well during routine testing. PGV is in the process of removing the obstruction in the casing. Until certain of the 27 PART II. OTHER INFORMATION (Continued) above-mentioned actions are completed, along with the possible drilling of additional wells, if required, the project is not expected to operate at its full capacity. On April 13, 1993, Hawaii Electric filed suit, Hawaii Electric Light Company, Inc. v. Puna Geothermal Venture Company, Inc., Civil No. 93-234 (3rd Circuit Vt., Hawaii), seeking to require PGV to pay contractual penalties of $7.5 million (for delays in the scheduled delivery of power to Hawaii Electric) and seeking to require PGV to pay consequential damages. PGV asserts that the delay was caused by a "force majeure" event. A tentative settlement has been agreed to which requires no additional capital contributions from the Constellation Companies. PGV intervened in Wao Kele O Puna, et al. v. Waihee, et al., Civil No. 91-3553-10 (1st Circuit Court, Hawaii) on the grounds that plaintiffs improperly are seeking to include the Puna project in an existing suit against the State of Hawaii and the County regarding an unrelated project. If plaintiffs succeed, the State and the County could be enjoined from any further permit review and issuance and from monitoring activity for the Puna project, effectively shutting down the Puna project. The Constellation Companies understand that the unrelated project has been cancelled, but the effect, if any, on this lawsuit are uncertain. Asbestos During 1993, BGE was served in several actions concerning asbestos. BGE was served with more actions during 1994. The actions are collectively titled In re Baltimore City Personal Injuries Asbestos Cases in the Circuit Court for Baltimore City, Maryland. The actions are based upon the theory of "premises liability," alleging that BGE knew of and exposed individuals to an asbestos hazard. The actions relate to two types of claims. The first type, direct claims by individuals exposed to asbestos, were described in a Report on Form 8-K filed August 20, 1993. BGE and approximately 70 other defendants are involved. Approximately 500 non-employee plaintiffs each claim $6 million in damages ($2 million compensatory and $4 million punitive). BGE does not know the specific facts necessary for BGE to assess its potential liability for these type claims, such as the identity of the BGE facilities at which the plaintiffs allegedly worked as contractors, the names of the plaintiffs' employers, and the date on which the exposure allegedly occurred. The second type are claims by two manufacturers - Owens Corning Fiberglas and Pittsburgh Corning Corp. - against BGE and approximately eight others, as third-party defendants. These relate to approximately 1,500 individual plaintiffs who have settled with the manufacturers. BGE does not know the specific facts necessary for BGE to assess its potential liability for 28 PART II. OTHER INFORMATION (Continued) 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. During the second quarter of 1994, an additional environmental action was instituted. On May 3, 1994 Constellation Energy was named as a defendant in Republic Imperial Acquisition v. Stockmar Energy, Inc., et al. Civil No. 940120R(LSP) (Dist. Ct., So. Dist. California). The plaintiffs are owners of a non-hazardous waste landfill located in Imperial County, California. The plaintiffs allege that defendants delivered hazardous materials consisting of spent geothermal filters containing certain metals used in the operation of four geothermal projects. The claims are made under the Federal Comprehensive Environmental Response, Compensation and Liability Act (Superfund statute) and state and common law against the operators, project owners and others. Certain Constellation Energy subsidiaries have ownership interests in three of the projects. These Constellation Companies have indemnification rights from project lessees and operators. There are approximately 45 other potentially responsible parties in addition to the Constellation Companies. The Constellation Companies are currently evaluating the claims and site investigation is at a preliminary stage. As a result, total investigation and clean up costs, as well as the Constellation Companies' share of such costs, cannot presently be estimated. 29 Item 4. Submission of Matters to a Vote of Security Holders On April 20, 1994, BGE held its annual meeting of shareholders. At that meeting, the following matters were voted upon: 1. All of the Directors nominated by BGE were elected as follows: COMMON SHARES CAST: FOR AGAINST ABSTAIN H. F. Baldwin 121,153,040 757,152 1,401,613 B. B. Byron 120,740,613 1,169,579 1,401,613 J. O. Cole 121,287,153 623,039 1,401,613 D. A. Colussy 121,276,540 633,652 1,401,613 E. A. Crooke 121,009,627 900,565 1,401,613 J. R. Curtiss 121,169,009 741,183 1,401,613 J. W. Geckle 121,289,166 621,026 1,401,613 F. A. Hrabowski,III 121,010,751 899,441 1,401,613 N. Lampton 121,013,321 896,871 1,401,613 G. V. McGowan 120,998,755 911,437 1,401,613 P. G. Miller 121,045,351 864,841 1,401,613 C. H. Poindexter 119,359,874 2,550,318 1,401,613 G. L. Russell, Jr. 121,088,049 822,143 1,401,613 M. D. Sullivan 118,142,899 3,767,292 1,401,613 2. Coopers and Lybrand was reelected as auditor, and with respect to holders of common stock, the number of affirmative votes cast were 121,517,116. The number of negative votes cast were 958,416, and the number of abstentions were 1,244,814. 30 ITEM 6. Exhibits and Reports on Form 8-K A) Exhibit No. 12 Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. B) Form 8-K None SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. BALTIMORE GAS AND ELECTRIC COMPANY (Registrant) Date August 12, 1994 /s/ C. W. Shivery C. W. Shivery, Vice President on behalf of the Registrant and as Principal Financial Officer 31 EXHIBIT INDEX Exhibit Number 12 Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. 32 EX-12 2 PART I. FINANCIAL INFORMATION (Continued) 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 June December December December December December 1994 1993 1992 1991 1990 1989 (In Thousands of Dollars) Net Income $337,047 $309,866 $264,347 $233,681 $175,446 $276,291 Taxes on Income 170,242 140,833 105,994 88,041 22,818 84,704 Adjusted Net Income $507,289 $450,699 $370,341 $321,722 $198,264 $360,995 Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $202,934 $199,415 $200,848 $213,616 $194,656 167,503 Capitalized Interest 12,881 16,167 13,800 20,953 25,748 5,842 Interest Factor in Rentals 1,975 2,144 2,033 1,801 1,840 2,388 Total Fixed Charges $217,790 $217,726 $216,681 $236,370 $222,244 $175,733 Preferred and Preference Dividend Requirements: (1) Preferred and Preference Dividends $ 40,795 $ 41,839 $ 42,247 $ 42,746 $ 40,261 $ 32,381 Income Tax Required 20,344 18,763 6,729 15,916 5,166 9,779 Total Preferred and Preference Dividend Requirements $ 61,139 $ 60,602 $ 58,976 $ 58,662 $ 45,427 $ 42,160 Total Fixed Charges and Preferred and Preference Dividend Requirements $278,929 $278,328 $275,657 $295,032 $267,671 $217,893 Earnings (2) $712,198 $652,258 $573,222 $537,139 $394,760 $530,886 Ratio of Earnings to Fixed Charges 3.27 3.00 2.65 2.27 1.78 3.02 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements 2.55 2.34 2.08 1.82 1.47 2.44 (1) Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings that would be required to meet dividend requirements on preferred stock and preference stock. (2) Earnings are deemed to consist of net income that includes earnings of BGE's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest.
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