Item 1 -- Business Overview of Consolidated Business .......... 1 Electric Business Electric Regulatory Matters and Competition ................................ 3 Electric Rate Matters ...................... 4 Nuclear Operations ......................... 5 Electric Load Management, Energy, and Capacity Purchases ..................... 5 Fuel for Electric Generation ............... 6 Electric Operating Statistics .............. 8 Gas Business Gas Regulatory Matters and Competition ................................ 9 Gas Operations ............................. 9 Gas Rate Matters ........................... 10 Gas Operating Statistics ................... 11 Franchises ................................. 12 Diversified Businesses ..................... 12 Consolidated Capital Requirements .......... 14 Environmental Matters ...................... 14 Employees .................................. 17 Item 2
ITEM 2. PROPERTIES
We describe our electric and gas business properties separately below. None of the properties used in connection with the operation of our diversified businesses are considered material to BGE.
ELECTRIC
Our principal electric generating plants are shown below:
- ---------------------- (A) These totals reflect BGE's proportionate interest and entitlement to capacity from Keystone and Conemaugh, which are 2 megawatts of diesel capacity for Keystone and 1 megawatt of diesel capacity for Conemaugh.
We also own two-thirds of the outstanding capital stock of Safe Harbor Water Power Corporation, and are currently entitled to 277 megawatts of the rated capacity of the Safe Harbor Hydroelectric Project. Safe Harbor is operated under a Federal Energy Regulatory Commission license which expires in 2030.
GAS
We own the following propane air and liquefied natural gas facilities:
o a liquefied natural gas facility for the liquefication and storage of natural gas with a total storage capacity of 1,000,000 DTH and a planned daily capacity of 287,988 DTH, and o a propane air facility with a mined cavern and refrigerated storage facilities with a total storage capacity of 1,000,000 DTH and a planned daily capacity of 85,000 DTH.
We expect to close our refrigerated storage facilities with approximately 500,000 DTH of storage capacity during the summer of 1999. We believe our remaining storage facilities are sufficient to supplement our gas supply during heavy winter demands and temporary emergencies.
GENERAL INFORMATION
We own our principal plants and other important units that are located in Maryland including our principal headquarters building in downtown Baltimore. We also lease several properties in our service area which are used for various offices and services. We have electric transmission and electric and gas distribution lines located:
o in public streets and highways pursuant to franchises, and o on permanent rights-of-way secured for the most part by grants from owners of the property and for a relatively small part by condemnation.
We also have rights-of-way to maintain 26-inch natural gas mains across certain Baltimore City owned property (principally parks) which expire in 2004. These rights-of-way can be renewed during their last year for an additional period of 25 years based on a fair revaluation. Conditions of the grants are satisfactory.
We share the ownership of the properties for the Keystone and Conemaugh plants in Pennsylvania. There are minor liens and easements on the Keystone and Conemaugh properties, but these encumbrances do not materially interfere with our use of the properties.
All of our property referred to above is subject to the lien of our mortgage securing our mortgage bonds.
We believe that our operating properties are adequately maintained and are in good operating condition.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
ASBESTOS
Since 1993, we have been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that we knew of and exposed individuals to an asbestos hazard. The actions relate to two types of claims.
The first type is direct claims by individuals exposed to asbestos. We described these claims in a Report on Form 8-K filed August 20, 1993. We are involved in these claims with approximately 70 other defendants. Approximately 520 individuals that were never employees of BGE each claim $6 million in damages ($2 million compensatory and $4 million punitive). These claims were filed in the Circuit Court for Baltimore City, Maryland in the summer of 1993. We do not know the specific facts necessary to estimate our potential liability for these claims. The specific facts we do not know include:
o the identity of our facilities at which the plaintiffs allegedly worked as contractors, o the names of the plaintiff's employers, and o the date on which the exposure allegedly occurred.
To date, seven of these cases were settled before trial for amounts that were immaterial. One trial is currently scheduled for August 1999.
The second type is claims by one manufacturer -- Pittsburgh Corning Corp. -- against us and approximately eight others, as third-party defendants. These claims relate to approximately 1,500 individual plaintiffs and were filed in the Circuit Court for Baltimore City, Maryland in the fall of 1993. We do not know the specific facts necessary to estimate our potential liability for these claims. The specific facts we do not know include:
o the identity of our facilities containing asbestos manufactured by the manufacturer, o the relationship (if any) of each of the individual plaintiffs to us, o the settlement amounts for any individual plaintiffs who are shown to have had a relationship to us, and o the dates on which/places at which the exposure allegedly occurred.
Until the relevant facts for both types of claims are determined, we are unable to estimate what our liability, if any, might be. Although insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions, our potential liability could be material.
NOX EMISSIONS LITIGATION
On June 19, 1998, we filed a lawsuit against the MDE in Baltimore City Circuit Court challenging regulations that require major NOx sources to reduce emissions up to 65% by May 1999. While we were already taking steps to control NOx emissions at out generating plants, we communicated to MDE that we could not install the required technology at our Brandon Shores plant in time to meet the 1999 deadline. On February 9, 1999, the court ordered MDE to reissue the regulations with a new compliance date, indicating it was impossible for utilities to meet the May 1999 deadline. We do not anticipate that MDE will appeal the court's decision.
See ITEM 1. BUSINESS -- ELECTRIC RATE MATTERS, NUCLEAR OPERATIONS, FUEL FOR ELECTRIC GENERATION, GAS RATE MATTERS, ENVIRONMENTAL MATTERS, and NOTE 10 TO CONSOLIDATED FINANCIAL STATEMENTS for other information about our legal or regulatory proceedings.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
Executive Officers of BGE at the date of this report are:
- ---------- (A) Chief Executive Officer, Director, and member of the Executive Committee.
(B) Director and member of the Executive Committee.
Officers of BGE are elected by, and hold office at the will of, the Board of Directors and do not serve a "term of office" as such. There is no arrangement or understanding between any director or officer and any other person pursuant to which the director or officer was selected.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
STOCK TRADING
Our common stock is traded under the ticker symbol BGE. It is listed on the New York, Chicago, and Pacific stock exchanges. It has unlisted trading privileges on the Boston, Cincinnati, and Philadelphia exchanges.
As of February 26, 1999, there were 69,305 common shareholders of record.
DIVIDEND POLICY
We pay dividends on our common stock after our Board of Directors declares them. There is no limitation on our paying common stock dividends unless:
o we elect to defer interest payments on the 7.16% Deferrable Interest Subordinated Debentures due June 30, 2038, and any deferred interest remains unpaid; or
o all dividends (and any redemption payments) due on our preference stock have not been paid.
Dividends have been paid on the common stock continuously since 1910. Future dividends depend upon future earnings, our financial condition, and other factors. Quarterly dividends were declared on the common stock during 1998 and 1997 in the amounts set forth below.
COMMON STOCK DIVIDENDS AND PRICE RANGES
- ---------- * Based on New York Stock Exchange Composite Transactions as reported in THE WALL STREET JOURNAL.
Item 6.
Item 6. Selected Financial Data
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT YEAR'S PRESENTATION.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Introduction In Management's Discussion and Analysis, we explain the general financial condition and the results of operations for BGE(R) and its diversified business subsidiaries including:
o what factors affect our businesses, o what our earnings and costs were in 1998 and 1997, o why earnings and costs changed from the year before, o where our earnings came from, o how all of this affects our overall financial condition, o what our expenditures for capital projects were in 1996 through 1998, and what we expect them to be in 1999 through 2001, and o where we will get cash for future capital expenditures.
As you read Management's Discussion and Analysis, it may be helpful to refer to our Consolidated Statements of Income which present the results of our operations for 1998, 1997, and 1996. In Management's Discussion and Analysis, we analyze and explain the annual changes in the specific line items in the Consolidated Statements of Income.
The electric utility industry is undergoing rapid and substantial change. Competition in the generation part of our business is increasing. The regulatory environment (federal and state) is shifting toward customer choice. These matters are discussed briefly in the "Competition and Response to Regulatory Change" section and in Item 1. Business--Electric Regulatory Matters and Competition.
In response to this change, we regularly reevaluate our strategies with two goals in mind: to improve our competitive position, and to anticipate and adapt to regulatory change. These strategies might include one or more of the following:
o the complete or partial separation of our generation, transmission, and distribution functions, o purchase or sale of generation assets, o mergers or acquisitions of utility or non-utility businesses, o spin-off or sale of one or more businesses, and o growth of earnings from nonregulated businesses.
We cannot predict whether any of the strategies described above may actually occur, or what their effect on our financial condition or competitive position might be. Please refer to the "Forward Looking Statements" section.
Results of Operations In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, then separately discuss earnings for the utility business and for diversified businesses.
OVERVIEW Total Earnings per Share of Common Stock 1998 1997 1996 - -------------------------------------------------------------------------------- Utility business $ 1.93 $ 1.94 $ 1.96 Diversified businesses (subsidiaries) .27 .34 .31 - -------------------------------------------------------------------------------- Total earnings per share from operations 2.20 2.28 2.27 Write-off of merger costs (see Note 2) -- (.25) -- Write-downs of real estate investments (see Note 3) (.10) (.31) -- Disallowed replacement energy costs (see Note 10) -- -- (.42) Write-off of energy services investment (see Note 2) (.04) -- -- - -------------------------------------------------------------------------------- Total earnings per share $ 2.06 $ 1.72 $ 1.85 ================================================================================
Our 1998 total earnings increased $51.8 million, or $.34 per share, compared to 1997. Our total earnings increased mostly because 1997 results reflect our write-off of merger costs, and our real estate and senior-living facilities business' write-down of its investments in two real estate projects, as discussed in the 1997 section below. Our 1998 earnings would have been higher except:
o our real estate and senior-living facilities business wrote down its investment in a real estate project, and o we wrote off an energy services investment.
In 1998, utility earnings from operations were about the same compared to 1997. We discuss our utility earnings in more detail in the "Utility Business" section.
In 1998, diversified business earnings from operations decreased compared to 1997 mostly because of lower earnings from our real estate and senior-living facilities and financial investments
businesses. However, we had higher earnings from our power projects and power marketing and trading businesses. We discuss our diversified business earnings in more detail in the "Diversified Businesses" section.
We discuss the real estate write-down in the "Other Diversified Businesses" section and the write-off of the energy services investment in the "Other Energy Services" section.
Our 1997 total earnings decreased $18.2 million, or $.13 per share, compared to 1996. Our total earnings decreased because:
o we wrote off costs associated with the terminated merger with Potomac Electric Power Company, and o our real estate and senior-living facilities business wrote down its investments in two real estate projects.
We discuss the write-off of merger costs in the "Write-Off of Merger Costs" section, and the real estate write-downs in the "Other Diversified Businesses" section.
In 1997, utility earnings from operations decreased compared to 1996 mostly because we sold less electricity and gas due to milder weather.
In 1997, diversified business earnings from operations increased compared to 1996 mostly because of higher earnings from our power projects and financial investments businesses.
Utility Business Before we go into the details of our electric and gas operations, we believe it is important to discuss factors that have a strong influence on our utility business performance: regulation, the weather, other factors including the condition of the economy in our service territory, and competition.
Regulation by the Maryland Public Service Commission (Maryland PSC) The Maryland PSC determines the rates we can charge our customers. Our rates consist of a "base rate" and a "fuel rate." The base rate is the rate the Maryland PSC allows us to charge our customers for the cost of providing them service, plus a profit. We have both an electric base rate and a gas base rate. Higher electric base rates apply during the summer when the demand for electricity is the highest. Gas base rates are not affected by seasonal changes.
The Maryland PSC allows us to include in base rates a component to recover money spent on conservation programs. This component is called a "conservation surcharge." However, under this surcharge the Maryland PSC limits what our profit can be. If, at the end of the year, we have exceeded our allowed profit, we defer the excess in that year and we lower the amount of future surcharges to our customers to correct the amount of overage, plus interest.
In addition, we charge our electric customers separately for the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil) and for the net cost of purchases and sales of electricity (primarily with other utilities). We charge the actual cost of these items to the customer with no profit to us. If these fuel costs go up, the Maryland PSC permits us to increase the fuel rate. If these costs go down, our customers benefit from a reduction in the fuel rate. The fuel rate is impacted most by the amount of electricity generated at our Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) because the cost of nuclear fuel is cheaper than coal, gas, or oil.
We discuss this in more detail in the "Electric Fuel Rate Clause" section and in Note 1 of the Notes to Consolidated Financial Statements.
Changes in the fuel rate normally do not affect earnings. However, if the Maryland PSC disallows recovery of any part of the fuel costs, our earnings are reduced. In 1996, the Maryland PSC disallowed certain fuel costs as discussed in the "Disallowed Replacement Energy Costs" section and in Note 10.
We also charge our gas customers separately for the natural gas they purchase from us. The price we charge for the natural gas is based on a market based rates incentive mechanism approved by the Maryland PSC. We discuss market based rates in more detail in the "Gas Cost Adjustments" section and in Note 1.
From time to time, when necessary to cover increased costs, we ask the Maryland PSC for base rate increases. The Maryland PSC holds hearings to determine whether to grant us all or a portion of the amount requested. The Maryland PSC historically has allowed us to increase base rates to recover increased utility plant asset costs, plus a profit, beginning at the time of replacement. Generally, rate increases improve our utility earnings because they allow us to collect more revenue. However, rate increases are normally granted based on historical data, and those increases may not always keep pace with increasing costs.
Other parties may petition the Maryland PSC to lower our base rates. We discuss this in more detail in the "Competition and Response to Regulatory Change" section.
Weather Weather affects the demand for electricity and gas. Very hot summers and very cold winters increase demand. Mild weather reduces demand. Weather impacts residential sales more than commercial and industrial sales, which are mostly affected by business needs for electricity and gas.
We measure the weather's effect using "degree days." A degree day is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Cooling degree days result when the average daily actual temperature exceeds the 65 degree baseline. Heating degree days result when the average daily actual temperature is less than the baseline.
During the cooling season, hotter weather is measured by more cooling degree days and results in greater demand for electricity to operate cooling systems. During the heating season, colder weather is measured by more heating degree days and results in greater demand for electricity and gas to operate heating systems.
Effective March 1, 1998, the Maryland PSC allowed us to implement a monthly adjustment to our gas business revenues to eliminate the effect of abnormal weather patterns. We discuss this further in the "Weather Normalization" section.
We show the number of cooling and heating degree days in 1998 and 1997, the percentage changes in the number of degree days from the prior year, and the number of degree days in a "normal" year as represented by the 30-year average in the following table.
30-year 1998 1997 average - --------------------------------------------------------------- Cooling degree days 915 746 836 Percentage change from prior year 22.7% (5.1)% Heating degree days 4,119 4,822 4,783 Percentage change from prior year (14.6)% (6.2)%
Other Factors Other factors, aside from weather, impact the demand for electricity and gas. These factors include the "number of customers" and "usage per customer" during a given period. We use these terms later in our discussions of electric and gas operations. In those sections, we discuss how these and other factors affected electric and gas sales during 1998 and 1997.
The number of customers in a given period is affected by new home and apartment construction and by the number of businesses in our service territory.
Usage per customer refers to all other items impacting customer sales which cannot be measured separately. These factors include the strength of the economy in our service territory. When the economy is healthy and expanding, customers tend to consume more electricity and gas. Conversely, during an economic downtrend, our customers tend to consume less electricity and gas.
Competition and Response to Regulatory Change Our electric and gas businesses are also affected by competition and regulatory changes. We discuss these items for both of our regulated businesses below.
Electric Business Electric utilities are facing competition on various fronts, including:
o the construction of generating units to meet increased demand for electricity, o the sale of electricity in bulk power markets, o competing with alternative energy suppliers, and o electric sales to retail customers.
On July 1, 1998, BGE and all other Maryland investor-owned electric utilities filed with the Maryland PSC their individual proposals for the transition from a regulated electric supply system to one where generation is priced based on a competitive retail electric market. In our plan, we proposed that:
o all customers would be able to choose other suppliers or our service, o we would guarantee our service at rates frozen until July 2002. Prices would then be adjusted for inflation until the transition is complete, but not beyond 2008, o customers who choose an alternate supplier would receive a shopping credit. This credit would reduce their BGE bill by the market value of capacity, energy, and other services that we no longer provide those customers, o we would attempt to reduce potentially stranded investments by lowering operating costs and applying all earnings in excess of our authorized rate of return to accelerate the recovery of generation assets. This would lower the generation asset book values toward their competitive market values thereby reducing any potentially stranded investment, o market value of generation assets would be determined by annual independent appraisals beginning in 2002 and continuing through the transition period, o when the difference between the book value and market value of generation assets is within 10%, the transition period would end and a non-bypassable surcharge would be applied to customers' bills to recover the remaining stranded investments over a two- to three-year period, and o net regulatory assets and nuclear decommissioning costs would continue to be collected from customers through the regulated transmission and distribution business.
On December 22, 1998, other parties filed their positions in response to our proposal. The counter-proposals contain provisions which, if adopted by the Maryland PSC, could negatively impact our electric business. The Maryland PSC will hold hearings to examine our electric restructuring transition proposal and the counter-proposals of other parties. In the meantime, settlement negotiations are ongoing. Absent settlement, the Maryland PSC is scheduled to issue an order by October 1, 1999.
On September 3, 1998, the Office of People's Counsel (OPC) filed a petition requesting the Maryland PSC to lower our electric base rates. At our request, the Maryland PSC agreed to consolidate any such review of our electric base rates with its review of our electric restructuring transition proposal discussed above. We filed testimony and exhibits with the Maryland PSC supporting our position that our current electric base rates are justified. On February 5, 1999, other parties, including the OPC, filed testimonies to lower our base rates by as much as $131 million. As a condition of the Maryland PSC's consolidation of these matters, we agreed to make our rates subject to refund effective July 1, 1999 should the Maryland PSC issue a rate reduction order after that date.
We cannot predict the ultimate effect competition or regulatory change will have on our earnings.
We discuss competition in our electric business in Item 1. Business--Electric Regulatory Matters and Competition.
Gas Business Regulatory change in the natural gas industry is well under way. We discuss competition in our gas business in Item 1. Business--Gas Regulatory Matters and Competition.
Effective November 1, 1998, the Maryland PSC allowed us to begin collecting a Delivery Service Realignment Charge to recover certain costs associated with the introduction of competition in our gas business. This is not expected to significantly impact our earnings.
UTILITY Business Earnings per Share of Common Stock 1998 1997 1996 - -------------------------------------------------------------------------------- Electric business $ 1.75 $ 1.77 $ 1.75 Gas business .18 .17 .21 - -------------------------------------------------------------------------------- Total utility earnings per share from operations 1.93 1.94 1.96 Write-off of merger costs (see Note 2) -- (.25) -- Disallowed replacement energy costs (see Note 10) -- -- (.42) - -------------------------------------------------------------------------------- Total utility earnings per share $ 1.93 $ 1.69 $ 1.54 ================================================================================
Utility Business Earnings per Share of Common Stock Our 1998 total utility earnings increased $36.1 million, or $.24 per share, from 1997. Our 1997 total utility earnings increased $24.0 million, or $.15 per share, from 1996. We discuss the factors affecting utility earnings below.
Electric Operations
Electric Revenues The changes in electric revenues in 1998 and 1997 compared to the respective prior year were caused by:
1998 1997 - ------------------------------------------------------------ (In millions) Electric system sales volumes $50.8 $(15.5) Base rates (6.6) 29.2 Fuel rates (8.1) (4.3) - ------------------------------------------------------------ Total change in electric revenues from electric system sales 36.1 9.4 Interchange and other sales (13.2) (23.2) Other 4.6 (3.2) - ------------------------------------------------------------ Total change in electric revenues $27.5 $(17.0) ==========================================================
Electric System Sales Volumes "Electric system sales volumes" are sales to customers in our service territory at rates set by the Maryland PSC. These sales do not include interchange sales and other sales.
The percentage changes in our electric system sales volumes, by type of customer, in 1998 and 1997 compared to the respective prior year were:
1998 1997 - -------------------------------------------- Residential 1.5% (3.9)% Commercial 3.9 1.0 Industrial 0.2 (0.4)
In 1998, we sold more electricity to residential customers mostly because:
o the number of customers increased, o we had hotter summer weather, and o usage per customer increased.
We would have sold even more electricity to residential customers except we had milder winter weather in 1998. We sold more electricity to commercial customers mostly because usage per customer increased. We sold about the same amount of electricity to industrial customers as we did in 1997.
In 1997, we sold less electricity to residential customers mostly for two reasons: lower usage per customer and milder weather. We sold more electricity to commercial customers mostly because usage per customer increased. We would have sold even more electricity to commercial customers except for milder weather during the year. We sold about the same amount of electricity to industrial customers as we did in 1996.
Base Rates In 1998, base rate revenues decreased compared to 1997. Although we sold more electricity in 1998, our base rate revenues decreased because of lower conservation surcharge revenues.
In 1997, base rate revenues increased compared to 1996 because of higher conservation surcharge revenues. During 1996, we exceeded our profit limit under the conservation surcharge. As a result, we excluded $28.5 million of our 1996 surcharge billings from revenue. To correct the overage, we lowered the surcharge on our customers' bills over a twelve- month period beginning July 1997 through June 1998.
Fuel Rates In 1998, fuel rate revenues decreased compared to 1997. Although we sold more electricity, the fuel rate was lower mostly because we were able to use a less-costly mix of generating plants and electricity purchases.
In 1997, fuel rate revenues decreased compared to 1996 mostly because we sold less electricity.
Interchange and Other Sales "Interchange and other sales" are sales in the PJM (Pennsylvania-New Jersey-Maryland) Interconnection energy market and to others. The PJM is a regional power pool with members that include many wholesale market participants, as well as BGE and seven other utility companies. We sell energy to PJM members and to others after we have satisfied the demand for electricity in our own system.
In 1998 and 1997, interchange and other sales revenues decreased compared to the respective prior year mostly because of lower sales volumes.
Electric Fuel and Purchased Energy Expenses 1998 1997 1996 - ----------------------------------------------------------------- (In millions) Actual costs $514.7 $504.5 $539.2 Net recovery (deferral) of costs under electric fuel rate clause (see Note 1) (9.0) 15.2 8.2 Disallowed replacement energy costs (including carrying charges) (see Note 10) -- -- 95.4 - ----------------------------------------------------------------- Total electric fuel and purchased energy expenses $505.7 $519.7 $642.8 - -----------------------------------------------------------------
Actual Costs In 1998, our actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil) and electricity we bought from others increased compared to 1997 mostly because we settled a capacity contract with PECO Energy Company.
In 1997, our actual costs decreased compared to 1996 mostly for two reasons: we bought less electricity from others as a result of being able to meet demand using the electricity we generated, and we were able to use a less-costly mix of generating plants mostly because we generated more electricity at Calvert Cliffs.
Electric Fuel Rate Clause Under the electric fuel rate clause, we defer (include as an asset or liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) the difference between our actual costs of fuel and energy and what we collect from customers under the fuel rate in a given period. We either bill or refund our customers that difference in the future. We discuss the calculation of the fuel rate in Note 1.
In 1998, our actual costs of fuel and energy were higher than the fuel rate revenues we collected from our customers.
In 1997, our actual costs of fuel and energy were lower than the fuel rate revenues we collected from our customers.
Disallowed Replacement Energy Costs In December 1996, we settled fuel rate proceedings about extended outages that occurred at Calvert Cliffs from 1989 through 1991. We agreed not to bill our customers for $118 million of electric replacement energy costs associated with the outages. We wrote off a portion of the costs in 1990 and wrote off the remainder in 1996. We discuss this further in Note 10.
Gas Operations
Gas Revenues The changes in gas revenues in 1998 and 1997 compared to the respective prior year were caused by:
1998 1997 - ----------------------------------------------- (In millions) Gas system sales volumes $(10.8) $(7.3) Base rates 14.2 0.6 Weather normalization 10.1 -- Gas cost adjustments (87.6) (0.2) - ----------------------------------------------- Total change in gas revenues from gas system sales (74.1) (6.9) Off-system sales 1.8 10.9 Other 0.1 0.3 - ----------------------------------------------- Total change in gas revenues $(72.2) $ 4.3 ===============================================
Gas System Sales Volumes The percentage changes in our gas system sales volumes, by type of customer, in 1998 and 1997 compared to the respective prior year were:
1998 1997 - ----------------------------------------------- Residential (11.6)% (8.3)% Commercial (9.5) (0.2) Industrial (11.3) 4.4
In 1998, we sold less gas to residential and commercial customers mostly for two reasons: milder weather and lower usage per customer. We would have sold even less gas to residential and commercial customers except the number of customers increased. We sold less gas to industrial customers mostly because usage by Bethlehem Steel (our largest customer) and other industrial customers decreased.
In 1997, we sold less gas to residential customers mostly for two reasons: lower usage per customer and milder weather. We sold about the same amount of gas to commercial customers as we did in 1996. We sold more gas to industrial customers mostly for two reasons: milder weather caused fewer service interruptions and Bethlehem Steel used more gas. Sometimes we need to interrupt service during periods with the highest demand. Some industrial customers pay reduced rates in exchange for our right to interrupt their service during these periods. We would have sold even more gas to industrial customers except gas usage by industrial customers other than Bethlehem Steel decreased.
Base Rates In 1998, base rate revenues increased compared to 1997. Although we sold less gas during 1998, our base rate revenues increased mostly because the Maryland PSC authorized an increase in our base rates effective March 1, 1998. The change in rates will increase our base rate revenues over the twelve-month period from March 1998 through February 1999 by approximately $16 million.
In 1997, base rate revenues increased compared to 1996. Although we sold less gas in 1997, our base rate revenues increased because of higher conservation surcharge revenues during the last six months of the year.
Weather Normalization Effective March 1, 1998, the Maryland PSC allowed us to implement a monthly adjustment to our gas base rate revenues to eliminate the effect of abnormal weather patterns on our gas system sales volumes. This means our monthly gas base rate revenues will be based on weather that is considered "normal" for the month and, therefore, will not be affected by actual weather conditions.
Gas Cost Adjustments We charge our gas customers for the natural gas they purchase from us using gas cost adjustment clauses set by the Maryland PSC. These clauses operate similar to the electric fuel rate clause described in the "Electric Fuel Rate Clause" section.
However, effective October 1996, the Maryland PSC approved a modification of these gas clauses to provide a market based rates incentive mechanism. Under market based rates, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers, and does not significantly impact earnings. We also discuss this in Note 1.
Delivery service customers, including Bethlehem Steel, are not subject to the gas cost adjustment clauses because we are not selling gas to them. We charge these customers fees to recover the fixed costs for the transportation service we provide. These fees are essentially the same as the base rate charged for gas sales and are included in gas system sales volumes.
In 1998 and 1997, gas cost adjustment revenues decreased compared to the respective prior year mostly because we sold less gas.
Off-System Sales Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas outside our service territory. Off-system gas sales, which occur after we have satisfied our customers' demand, are not subject to gas cost adjustments. The Maryland PSC approved an arrangement for part of the margin from off-system sales to benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits shareholders). Changes in off-system sales do not significantly impact earnings.
In 1998, off-system gas sales revenues increased compared to 1997 mostly because we sold more gas off-system.
In 1997, off-system gas sales revenues increased compared to 1996 mostly because we first began off-system sales of gas in February 1996.
Gas Purchased for Resale Expenses
1998 1997 1996 - ------------------------------------------------------------------- (In millions) Actual costs $212.2 $291.6 $295.4 Net recovery (deferral) of costs under gas adjustment clauses (see Note 1) (3.6) 0.5 (11.0) - ------------------------------------------------------------------- Total gas purchased for resale expenses $208.6 $292.1 $284.4 ===================================================================
Actual Costs Actual costs include the cost of gas purchased for resale to our customers and for off-system sales. Actual costs do not include the cost of gas purchased by delivery service customers.
In 1998 and 1997, actual gas costs decreased compared to the respective prior year mostly because we sold less gas.
Gas Adjustment Clauses We charge customers for the cost of gas sold through gas adjustment clauses (determined by the Maryland PSC), as discussed under "Gas Cost Adjustments" earlier in this section.
In 1998, actual gas costs were higher than the revenues we collected from our customers.
In 1997, actual gas costs were lower than the revenues we collected from our customers.
Other Operating Expenses
Operations and Maintenance Expenses In 1998, operations and maintenance expenses increased $34.8 million compared to 1997 mostly because of:
o higher nuclear costs, o higher employee benefit costs, and o a $6.0 million write-off of contributions to a third party for a low-level radiation waste facility that was never completed.
In 1997, operations and maintenance expenses were slightly lower than they were in 1996.
Depreciation and Amortization Expenses We describe depreciation and amortization expenses in Note 1.
In 1998, depreciation and amortization expenses increased $34.2 million compared to 1997 mostly because:
o in October, 1998, the Maryland PSC authorized us to implement new electric depreciation rates retroactive to January 1, 1998, which increased depreciation expense by approximately $13.9 million, o we had more utility plant in service (as our level of plant in service changes, the amount of our depreciation and amortization expense changes), and o we reduced the amortization period for certain computer software beginning in the first quarter of 1998 from five years to three years.
In 1997, depreciation and amortization expenses increased $12.7 million compared to 1996 mostly because we had more plant in service.
Other Income and Expenses
Write-Off of Merger Costs In September 1995, we signed an agreement with Potomac Electric Power Company to merge together into a new company, Constellation Energy (R) Corporation, after all necessary regulatory approvals were received. In December 1997, both companies mutually terminated the merger agreement. Accordingly, in 1997, we wrote off $57.9 million of costs related to the merger. This write-off reduced after-tax earnings by $37.5 million, or $.25 per share.
Interest Charges Interest charges represent the interest on our outstanding debt.
In 1998, interest charges increased $6.7 million compared to 1997 mostly because we had more debt outstanding. Interest charges would have been higher except interest rates were lower than they were in 1997.
In 1997, interest charges increased $23.6 million compared to 1996 mostly for two reasons: we had more debt outstanding and interest rates were higher.
Income Taxes In 1998, income taxes increased $20.2 million compared to 1997 because we had higher taxable income from both our utility operations and our diversified businesses.
In 1997, income taxes decreased $8.3 million compared to 1996 because we had lower taxable income from both our utility operations and our diversified businesses.
Diversified Businesses Our diversified businesses engage primarily in energy services. Our energy services businesses include certain subsidiaries of Constellation(R) Enterprises, Inc. and the District Chilled Water General Partnership (ComfortLink(R)), a general partnership in which BGE is a partner. They are:
o Constellation Power Source,(TM) Inc.--our wholesale power marketing and trading business, o Constellation Power,(TM) Inc. and Subsidiaries--our power projects business, o Constellation Energy Source,(TM) Inc.--our energy products and services business, o BGE Home Products & Services,(TM) Inc. and Subsidiaries--our home products, commercial building systems, and residential and small commercial gas retail marketing business, and o ComfortLink--our cooling services business for commercial customers in Baltimore.
Constellation Enterprises, Inc. also has two other subsidiaries:
o Constellation Investments,(TM) Inc.--our financial investments business, and o Constellation Real Estate Group,(TM) Inc.--our real estate and senior-living facilities business.
We describe our diversified businesses in more detail in Item 1. Business-- Diversified Businesses.
DIVERSIFIED Business Earnings per Share of Common Stock 1998 1997 1996 - ------------------------------------------------------------------------ Energy services Power marketing and trading $.05 $.00 $-- Power projects .30 .25 .18 Other (.01) (.05) .02 - ------------------------------------------------------------------------ Total energy services earnings per share from operations .34 .20 .20 Other diversified businesses earnings per share from operations (.07) .14 .11 - ------------------------------------------------------------------------ Total diversified business earnings per share from operations .27 .34 .31 Write-downs of real estate investments (see Note 3) (.10) (.31) -- Write-off of energy services investment (.04) -- -- - ------------------------------------------------------------------------ Total earnings per share $ .13 $ .03 $ .31 ========================================================================
Diversified Business Earnings per Share of Common Stock Our 1998 diversified business earnings increased $15.7 million, or $.10 per share, compared to 1997. Our 1997 diversified business earnings decreased $42.2 million, or $.28 per share, compared to 1996.
We discuss factors affecting the earnings of our diversified businesses below.
Energy Services
Power Marketing and Trading In 1998, earnings from our power marketing and trading business increased compared to 1997 mostly because of increased trading activities in 1998 which was Constellation Power Source's first full year of operations.
Constellation Power Source uses the mark-to-market method of accounting for its trading activities. We discuss the mark-to-market method of accounting and Constellation Power Source's trading activities in Note 1.
As a result of the nature of its trading activities, Constellation Power Source's revenue and earnings will fluctuate. We cannot predict these fluctuations, but the effect on our revenues and earnings could be material. The primary factors that cause these fluctuations are:
o the number and size of new transactions, o the magnitude and volatility of changes in commodity prices and interest rates, and o the number and size of open commodity and derivative positions Constellation Power Source holds or sells.
Constellation Power Source's management uses its best estimates to determine the fair value of commodity and derivative positions it holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. However, it is possible that future market prices could vary from those used in recording assets and liabilities from trading activities, and such variations could be material. In 1998, assets and liabilities from energy trading activities increased because of greater trading activity compared to 1997.
In March 1998, Constellation Power Source and Goldman, Sachs Capital Partners II L.P., an affiliate of Goldman, Sachs & Co., formed Orion Power Holdings, Inc. (Orion) to acquire electric generating plants in the United States and Canada. Constellation Power Source has a commitment to fund its investment in Orion as discussed further in Note 10.
Power Projects In 1998, earnings from our power projects business increased compared to 1997 mostly because Constellation Power recorded a $10.4 million after-tax gain for its share of earnings in a partnership. The partnership recognized a gain on the sale of its ownership interest in a power sales contract.
In 1997, earnings increased compared to 1996 mostly because of improved performance of various energy projects. Also, 1996 earnings included $14.6 million (after-tax) for Constellation Power's percentage share of earnings in a partnership. The partnership recognized a gain on the sale of a power purchase agreement. These increases were offset by $16.2 million of after-tax write-offs of investments in certain power projects.
We describe our earnings in the partnerships and the write-offs further in Note 3.
California Power Purchase Agreements Constellation Power and subsidiaries and Constellation Investments have $310.6 million invested in 15 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. In 1998, earnings from these projects were $41.3 million, or $.28 per share.
Under these agreements, the electricity rates change from fixed rates to variable rates beginning in 1996 and continuing through 2000. The projects which already have had rate changes have lower revenues under variable rates than they did under fixed rates. When the remaining projects transition to variable rates, we expect their revenues also to be lower than they are under fixed rates.
Our power projects business is pursuing alternatives for some of these projects including:
o repowering the projects to reduce operating costs, o changing fuels to reduce operating costs, o renegotiating the power purchase agreements to improve the terms, o restructuring financing to improve existing terms, and o selling its ownership interests in the projects.
The California projects that make the highest revenues will transition in 1999 and 2000. The projects which transition in 1999 contributed $10.7 million, or $.07 per share to 1998 earnings, while those changing over in 2000 contributed $24.0 million, or $.16 per share to 1998 earnings. We expect earnings to ultimately decrease by similar amounts beginning in 1999 as these projects transition.
We describe these projects in more detail in Note 10.
International Projects At December 31, 1998, Constellation Power had invested about $183.4 million in 15 power projects in Latin America compared to $23.5 million invested in Latin America in 1997. These investments include:
o the purchase of a 51% interest in a Panamanian electric distribution company for approximately $90 million in 1998 by an investment group in which subsidiaries of Constellation Power hold an 80% interest, and o approximately $98 million for the purchase of existing electric generation facilities and the construction of an electric generation facility in Guatemala.
In the future, Constellation Power expects to expand its power projects business further in both domestic and international projects.
Other Energy Services In 1998, earnings from our remaining energy services businesses increased compared to 1997 due to improved results from our energy products and services business. Earnings would have been higher except we recorded a $5.5 million after-tax, or $.04 per share, write-off of our investment in, and certain of our product inventory from, an automated electric distribution equipment company. We recorded this write-off because of that company's inability to raise capital and sell its products.
In 1997, earnings from our remaining energy services businesses decreased compared to 1996 mostly because of lower earnings from our energy products and services business.
Other Diversified Businesses In 1998, earnings from our other diversified businesses decreased compared to 1997 mostly for two reasons: lower earnings from our real estate and senior-living facilities and financial investments businesses. Earnings from our real estate and senior-living facilities business decreased compared to 1997 mostly due to:
o a $15.4 million after-tax write-down of its investment in Church Street Station--an entertainment, dining, and retail complex in Orlando, Florida, o lower earnings from various real estate and senior-living facilities projects, and o a $4 million after-tax gain on the sale of two senior- living facilities projects reflected in 1997 results.
In addition, in 1998, our real estate and senior-living facilities business exchanged certain assets and liabilities in return for a 41.9% equity interest in Corporate Office Properties Trust (COPT), a real estate investment trust.
Earnings from our financial investments business decreased compared to 1997 mostly because of:
o better market performance for our investments in 1997, and o a $6 million after-tax gain on the sale of stock held by a financial limited partnership reflected in 1997 results.
In 1997, earnings from our other diversified businesses increased compared to 1996 mostly because of increased earnings in our financial investments business from better earnings in trading securities and increased gains from marketable securities. Earnings would have been higher except we had a decrease in earnings from our real estate and senior-living facilities business mostly due to:
o a $14.1 million after-tax write-down of the investment in Church Street Station, and o a $31.9 million after-tax write-down of the investment in Piney Orchard--a mixed-use, planned-unit development.
We discuss our real estate projects, the write-downs of our real estate projects, the COPT transaction, and our financial investments further in Note 3.
We consider market demand, interest rates, the availability of financing, and the strength of the economy in general when making decisions about our real estate projects. If we were to decide to sell our real estate projects, we could have write-downs. In addition, if we were to sell our real estate projects in the current market, we would have losses which could be material, although the amount of the losses is hard to predict. Depending on market conditions, we could also have material losses on any future sales.
Management's current real estate strategy is to hold each real estate project until we can realize a reasonable value for it except for Church Street Station which we intend to sell. Management evaluates strategies for all its businesses, including real estate, on an ongoing basis. We anticipate that competing demands for our financial resources and changes in the utility industry will cause us to evaluate thoroughly all diversified business strategies on a regular basis so we use capital and other resources in a manner that is most beneficial.
Financial Condition
Cash Flows 1998 1997 1996 - ----------------------------------------------------------- (In millions) Cash provided by (used in): Operating Activities $820.8 $726.0 $701.9 Investing Activities (625.0) (520.8) (567.0) Financing Activities (184.7) (109.3) (91.6)
In 1998 and 1997, cash provided by operations increased compared to the respective prior year mostly because of changes in working capital requirements.
In 1998, net cash used in investing activities increased compared to 1997 mostly because of the additional investment in international power projects. Cash used in investing would have been higher except for a $33.8 million decrease in utility construction expenditures.
In 1997, net cash used in investing activities decreased mostly because of the $79.5 million cash inflow from the sale of real estate properties and the increase in loans collected from real estate projects compared to 1996. Cash used in investing activities would have been lower except for a $12.7 million increase in utility construction expenditures, and $46.5 million increase for our investments in power projects and financial limited partnerships.
Total utility construction expenditures, including the allowance for funds used during construction, were $339.4 million in 1998 as compared to $373.2 million in 1997 and $360.5 million in 1996.
In 1998, cash used in financing activities increased compared to 1997 mostly because of the repayment of short-term borrowings that matured, sinking fund requirements, and early redemption of higher cost securities. Net cash used would have been higher except we issued more long-term debt and common stock in 1998 compared to 1997.
In 1997, cash used in financing activities increased from 1996 mostly because of the repayment of long-term debt and short-term borrowings that matured, sinking fund requirements, and early redemptions of higher cost securities. Net cash used would have been higher except we issued more long-term debt in 1997 compared to 1996.
Security Ratings Independent credit-rating agencies rate our fixed-income securities. The ratings indicate the agencies' assessment of our ability to pay interest, distributions, dividends, and principal on these securities. These ratings affect how much it will cost us to sell these securities. The better the rating, the lower the cost of the securities to us when we sell them. Our securities ratings at the date of this report are shown in the following table.
Standard Moody's Duff & Phelps' & Poors' Investors Credit Rating Group Service Rating Co. - ----------------------------------------------------------------------- Mortgage Bonds AA- A1 AA- Unsecured Debt A A2 A+ Trust Originated Preferred Securities & Preference Stock A- "a2" A
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Capital Resources Our business requires a great deal of capital. Our actual capital requirements for the years 1996 through 1998, along with estimated annual amounts for the years 1999 through 2001, are shown in the table on page 33. For the year ended December 31, 1998, our ratio of earnings to fixed charges was 2.94 and our ratio of earnings to combined fixed charges and preferred and preference dividend requirements was 2.60.
Investment requirements for 1999 through 2001 include estimates of funding for existing and anticipated projects. We continuously review and modify those estimates. Actual investment requirements may vary from the estimates included in the table on page 33 because of a number of factors including:
o regulation, legislation, and competition, o load growth, o environmental protection standards, o the type and number of projects selected for development, o the effect of market conditions on those projects, o the cost and availability of capital, and o the availability of cash from operations.
Our estimates are also subject to additional factors. Please see "Forward Looking Statements" section.
Capital Requirements of Our Utility Business Our estimates of future electric construction expenditures do not include costs to build more generating units. Electric construction expenditures include improvements to generating plants and to our transmission and distribution facilities. They also include estimated costs for replacing the steam generators and extending the operating licenses at Calvert Cliffs. The operating licenses expire in 2014 for Unit 1 and in 2016 for Unit 2. We estimate these Calvert Cliffs costs to be:
o $34 million in 1999, o $44 million in 2000, and o $58 million in 2001.
We estimate that during the two-year period 2002 through 2003, we will spend an additional $151 million to complete the replacement of the steam generators and extend the operating licenses at Calvert Cliffs. We discuss the license extension process further in the "Calvert Cliffs License Extension" section.
If we do not replace the steam generators, we estimate that Calvert Cliffs could not operate for the full term of its current operating licenses. We expect the steam generator replacements to occur during the 2002 refueling outage for Unit 1 and during the 2003 refueling outage for Unit 2.
Additionally, our estimates of future electric construction expenditures include the costs of complying with Environmental Protection Agency (EPA) and State of Maryland 65% nitrogen oxides emissions (NOx) reduction regulations as follows:
o $29 million in 1999, o $28 million in 2000, o $33 million in 2001, and o $14 million in 2002.
We discuss the NOx regulations further in Note 10.
Our utility operations provided about 108% in 1998, 105% in 1997, and 96% in 1996 of the cash needed to meet our capital requirements, excluding cash needed to retire debt and redeem preference stock.
We will continue to have cash requirements for:
o working capital needs including the payments of interest, distributions, and dividends, o capital expenditures, and o the retirement of debt and redemption of preference stock.
During the three years from 1999 through 2001, we expect utility operations to provide about 115% of the cash needed to meet our capital requirements, excluding cash needed to retire debt and redeem preference stock.
When we cannot meet our utility capital requirements internally, we sell debt and equity securities. We also sell securities when market conditions permit us to refinance existing debt or preference stock at a lower cost. The amount of cash we need and market conditions determine when and how much we sell.
Future funding for capital expenditures, the retirement of debt, redemption of preference stock, and payments of interest and dividends is expected to be provided by internally generated funds, commercial paper issuances, available capacity under credit facilities, and/or the issuance of long-term debt, trust securities, or equity.
At December 31, 1998, we have the authority from the Federal Energy Regulatory Commission to issue up to $700 million of short-term borrowings. In addition, we maintain $113 million in committed bank lines of credit and we have $100 million in bank revolving credit agreements to support the commercial paper program as discussed in Note 6.
Capital Requirements of Our Diversified Businesses Certain of our diversified businesses expect to expand their businesses which will require additional investments. These investment requirements include funding for:
o growing our power marketing and trading business, o the development and acquisition of power projects, as well as loans to project entities, o investments in financial limited partnerships, and o funding for construction of cooling system projects.
The investment requirements exclude BGE's commitment to contribute up to $175 million in equity to Constellation Power Source, Inc. to fund its investment in Orion Power Holdings, Inc.
Our diversified businesses have met their capital requirements in the past through borrowing, cash from their operations, and from time to time equity contributions from BGE. Our diversified businesses plan to raise the cash needed to meet capital requirements in the future through these same methods. BGE Home Products & Services may also meet capital requirements through sales of receivables.
If we can get a reasonable value for our real estate projects, additional cash may be obtained by selling real estate projects. The ability to sell or liquidate assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made. We discuss the real estate business and market in the "Other Diversified Businesses" section and in the Notes to Consolidated Financial Statements.
Our diversified businesses also have revolving credit agreements totaling $270 million to provide additional liquidity for short-term financial needs, including the issuance of up to $135 million of letters of credit.
In 1998, a subsidiary of Constellation Enterprises, Inc. issued $157 million of two- and three-year notes to several institutional investors in a private placement offering.
In 1997, our diversified businesses issued $289 million of three- and four-year notes.
We discuss our short-term borrowings in Note 6 and long-term debt in Note 7.
- -------------------------------------------------------------------------------- Market Risk We are exposed to market risk, including changes in interest rates, certain commodity prices, equity prices, and foreign currency. To manage our market risk, we may enter into various derivative instruments including swaps, forward contracts, futures contracts, and options. Please refer to the "Forward Looking Statements" section. We discuss our market risk and the related use of derivative instruments in this section.
Interest Rate Risk We are exposed to changes in interest rates as a result of financing through our issuance of variable-rate debt, fixed-rate debt, and preferred and preference securities. The following table provides information about our obligations that are sensitive to interest rate changes.
Principal Payments and Interest Rate Detail by Contractual Maturity Date
Commodity Price Risk We are exposed to the impact of market fluctuations in the price and transportation costs of natural gas, electricity, and other trading commodities. Currently, our gas business and energy services businesses use derivative instruments to manage changes in their respective commodity prices.
Gas Business Our gas business may enter into gas futures, options, and swaps to hedge its price risk under our market based rates incentive mechanism and our off-system gas sales program. We discuss this further in Note 1. At December 31, 1998, our exposure to commodity price risk for our gas business was not material.
Energy Services Businesses With respect to our energy services businesses, Constellation Power Source manages its commodity price risk inherent in its energy trading activities on a portfolio basis, subject to established trading and risk management policies. Commodity price risk arises from the potential for changes in the value of energy commodities and related derivatives due to: changes in commodity prices, volatility of commodity prices, and fluctuations in interest rates. A number of factors associated with the structure and operation of the electricity market significantly influence the level and volatility of prices for electricity and related derivative products. These factors include:
o seasonal changes in the demand for electricity, o hourly fluctuations in demand due to weather conditions, o available generation resources, o transmission availability and reliability within and between regions, and o procedures used to maintain the integrity of the physical electricity system during extreme conditions.
These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country and result from regional differences in:
o weather conditions, o market liquidity, o capability and reliability of the physical electricity system, and o the nature and extent of electricity deregulation.
Constellation Power Source uses various methods, including a value at risk model, to measure its exposure to market risk from energy trading activities. Value at risk is a statistical model that attempts to predict risk of loss based on historical market price and volatility data. Constellation Power Source calculates value at risk using a variance/covariance technique that models option positions using a linear approximation of their value. Additionally, Constellation Power Source estimates variances and correlation using historical market movements over the most recent rolling three-month period.
The value at risk amount represents the potential loss in the fair value of assets and liabilities from trading activities over a one-day holding period with a 99.6% confidence level. Using this confidence level, Constellation Power Source would expect a one-day change in fair value greater than or equal to the daily value at risk at least once per year. As of December 31, 1998, Constellation Power Source's value at risk was $6.0 million.
Constellation Power Source's calculation includes all assets and liabilities from trading activities, including energy commodities and derivatives that do not require cash settlements. We believe that this represents a more complete calculation of our value at risk from energy trading activities.
Due to the relative immaturity of the competitive market for electricity and related derivatives and the seasonality of changes in market prices, the value at risk calculation may not reflect the full extent of our commodity price risk exposure. Additionally, actual changes in the value of options may differ from the value at risk calculated using a linear approximation inherent in our calculation method.
We discuss Constellation Power Source's trading business in the "Power Marketing and Trading" section and in Note 1.
The commodity price risk for our remaining energy services businesses was not material.
Equity Price Risk We are exposed to price fluctuations in equity markets primarily through our financial investments business and our nuclear decommissioning trust fund. We are required by the Nuclear Regulatory Commission (NRC) to maintain a trust to fund the costs of decommissioning Calvert Cliffs. At December 31, 1998, equity price risk was not material. We discuss our nuclear decommissioning trust fund in more detail in Note 1. We also describe our financial investments in more detail in Note 3.
Foreign Currency Risk We are exposed to foreign currency risk primarily through our power projects business. Our power projects business has $183.4 million invested in 15 international power generation and distribution projects as of December 31, 1998. To manage our exposure to foreign currency risk, the majority of our contracts are denominated in or indexed to the U.S. dollar. At December 31, 1998, foreign currency risk was not material. We discuss our international projects in the "Power Projects" section.
Other Matters
Calvert Cliffs License Extension In 1998, we filed an application for a 20-year license extension for Calvert Cliffs with the NRC to extend its license beyond 2014 for Unit 1 and 2016 for Unit 2. License renewal evaluations focus on age-related issues in long-lived passive components (passive components include buildings, the reactor vessel, piping, ventilation ducts, electric cables, etc.). We must demonstrate that we can ensure that these passive components will continue to perform their intended functions through the renewal period. The NRC will also consider the impact of the 20-year license extension on the environment.
We began the license extension process in 1998 because the NRC may not rule on our application until 2002 or 2003. If the NRC denies our application, we must have adequate time to begin replacement power source planning. We cannot predict the timing of, or impact, if any, of the NRC's decision on our financial results. If our application is denied, it could have a material effect on our financial results.
Environmental Matters You will find details of our environmental matters in Note 10 and in Item 1. Business--Environmental Matters. These details include financial information. Some of the information is about environmental costs that may be material to our financial results.
Year 2000 Readiness Disclosure We have not experienced any significant year 2000 problems to date and we do not expect any significant problems to impair our operations as we transition to the new century. However, due to the magnitude and complexity of the year 2000 issue, even the most conscientious efforts cannot guarantee that every problem will be found and corrected prior to January 1, 2000. We are focusing on critical operating and business systems and expect to have contingency plans in place to deal with any problems, if they should occur. Please refer to "Forward Looking Statements" section.
Utility Business We established a year 2000 Program Management Office (PMO). Based on a work plan developed by the PMO, we have targeted the following six key areas:
o digital systems (devices with embedded microprocessors such as power instrumentation, controls, and meters), o telecommunications systems, o major suppliers, o information technology applications (our customer, business, and human resources information systems), o computer hardware and software infrastructure, and o contingency plans.
Of these areas, digital systems have the most impact on our ability to provide electric and gas service. Telecommunications, major suppliers, and certain information technology applications also impact our ability to provide electric and gas service.
Year 2000 Project Phases Our year 2000 project is divided into two phases:
o Phase I--initial assessment and detailed analysis, and o Phase II--testing, remediation, certification, and contingency planning.
Phase I involves conducting an inventory of all systems and identifying appropriate resources. We have identified the following appropriate resources for each system or piece of equipment:
o BGE employees familiar with each system or piece of equipment, o specialized contractors, and o specific vendors.
Phase I also includes developing action plans to ensure that the key areas identified above are year 2000 ready. The action plans for each system or piece of equipment include:
o our budget, o schedules for Phase I and II, and o our remediation approach--repair, upgrade, replace or retire.
In evaluating our risks and estimating our costs, we utilized employees with expertise in each line of business to perform the activities under Phase I. We believe our employees are the most familiar with their systems or equipment and therefore will provide a reliable estimate of our risks and costs.
Phase II includes converting and testing all of our systems. Each system will be tested by those employees used in Phase I following formal guidelines developed by the PMO. Each system or piece of equipment will then be certified by a tester and the PMO, following testing guidelines developed with the help of outside consultants. We are currently evaluating whether we will have our year 2000 testing independently certified. Phase II also includes identifying our major suppliers and developing contingency plans. We have identified our major suppliers and have assessed their year 2000 readiness through surveys. We are currently following-up with our major suppliers via interviews.
Contingency Planning Year 2000 operational contingency planning is underway. Staffing and initial planning was completed in 1998. Contingency plans are expected to be completed, including company-wide training, by September 1999. We are developing contingency plans using the contingency guidelines issued by the Nuclear Energy Institute (which are endorsed by the NRC), the contingency guidelines issued by the North American Electric Reliability Council (NERC), and guidance from consultants.
We are also addressing the impact of electric power grid problems that may occur outside of our own electric system. We have started year 2000 electric power grid impact planning through our various electric interconnection affiliations. The PJM interconnection has drafted year 2000 operational preparedness plans and restoration scenarios and will continue to develop these plans during the first half of 1999 in cooperation with NERC. The NERC has started monthly assessments of the electric utility industry to communicate the readiness of the national electric grid for year 2000. The NERC has scheduled two industry-wide tests for 1999.
Through the Electric Power Research Institute (EPRI), an industry-wide effort has been established to deal with year 2000 problems affecting digital systems and equipment used by the nation's electric power companies. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans. The assessment was shared by the industry as a whole to facilitate year 2000 problem solving.
BGE has joined the American Gas Association (AGA) in an initiative similar to the one with EPRI to facilitate year 2000 problem solving among gas utilities. The AGA and its affiliates has initiated quarterly assessments of the gas utility industry to communicate the readiness of its members for the year 2000.
Current Status The most reasonably likely worst case scenario faced by our utility business is any interruption in providing electric and gas service to our customers. We cannot predict the impact of any interruption on our results of operations, but the impact could be material. The following table shows our estimate as of the date of this report of the percentage completed for Phases I and II and our expected year 2000 readiness target dates for the six key areas:
Year 2000 readiness Phase I Phase II target date - ---------------------------------------------------------- (approximate % complete)
Digital systems 100% 65% June 1999 Telecommunications systems 100% 90% June 1999 Major suppliers 100% 90% June 1999 Information technology applications 100% 70% June 1999 Computer hardware and software infrastructure 100% 85% June 1999 Contingency plans -- 30% September 1999
The completion percentages listed above are reviewed by our PMO in monthly status meetings with the personnel responsible for each project and their supervision. Monthly progress is also monitored by senior BGE management.
Costs In the following table, we show the breakdown of our total costs between normal system replacements that will be capitalized (included in the Consolidated Balance Sheets) and the costs that will be expensed (included in our Consolidated Statements of Income) through operations and maintenance (O&M) cost. We also show the breakdown of non-incremental (previously included in our information technology budget) and incremental O&M cost:
Actual Estimated Cost Costs Total 1996 1997 1998 1999 2000 Costs - -------------------------------------------------------------------------------- (In millions) Total Cost $ 0.1 $1.7 $18.9 $19.5 $2.0 $ 42.2 Less: Capital cost -- -- 7.3 5.7 -- 13.0 - -------------------------------------------------------------------------------- O&M cost 0.1 1.7 11.6 13.8 2.0 29.2 Less: non- incremental O&M cost 0.1 1.7 4.6 7.0 1.0 14.4 - -------------------------------------------------------------------------------- Incremental O&M cost $ -- $ -- $ 7.0 $ 6.8 $1.0 $ 14.8 ================================================================================
The costs incurred in 1996 and 1997 were for Phase I. The costs incurred in 1998 were for Phases I and II. Costs incurred in 1999 and 2000 will be for Phases I and II.
In 1998 and 1999, we had and expect to have the equivalent of approximately 110 full-time employees assigned to our year 2000 project.
Diversified Businesses Overview Our diversified businesses have established year 2000 task forces to address their year 2000 issues and are completing their initial assessments. As the initial assessments are completed, the businesses have developed, and will be developing, action plans to prepare their systems for the year 2000. Outside consultants have been retained by several of our diversified businesses to help complete the initial assessment and detailed analysis phase, and to assist in the testing, remediation, and certification phase of their year 2000 projects. The action plans developed are similar to those used by our utility business, including a test certification process. All systems are expected to be certified by December 1999. Our diversified businesses are evaluating whether they will have their year 2000 testing independently certified.
In evaluating their risks and estimating their costs, our diversified businesses utilized employees with expertise in each line of business to perform initial assessments. We believe our diversified businesses' employees are the most familiar with their systems or equipment and therefore will provide a reliable estimate of our risks and costs.
The progress of our diversified businesses' year 2000 projects are reviewed by their year 2000 task forces in monthly status meetings with the personnel responsible for each project and their supervision. Monthly progress is also monitored by senior management for each business and periodic updates are provided to BGE senior management.
Contingency Planning Each of our diversified businesses will develop contingency plans, which are expected to be completed by December 1999.
Current Status The most reasonably likely worst case scenarios faced by our energy services businesses and our other diversified businesses are discussed below. However, if any of these scenarios actually occurred, the impact is not expected to be material to our consolidated financial results.
Energy Services - --------------- The most reasonably likely worst case scenarios for any one of our power projects would be:
o a shutdown of the plant's systems (most of which can be manually overridden), o inability of the purchasing utility to take the plant's power, or o lack of fuel.
Personnel at each plant are currently assessing their particular year 2000 issues and certain plants have started the testing, remediation, and certification phase of their year 2000 project.
For our power marketing and trading business and our energy products and services business, the most reasonably likely worst case scenario would be encountering any Internet access problems with trading partners, transmission service providers, independent operators, power exchanges, and various electronic bulletin boards. Each of these businesses have two Internet service providers and are contracting with a third provider for alternate routing to critical Internet sites necessary to perform day-to-day business functions. Both are currently assessing their year 2000 issues.
For our home products and commercial building systems business, the most reasonably likely worst case scenarios would be any interruption in billing customers or renewing maintenance contracts. This business has substantially completed the assessment and detailed analysis phase and has started the testing, remediation, and certification phase of its year 2000 project.
Other Diversified Businesses - ---------------------------- The most reasonably likely worst case scenarios for our financial investments business would be a breakdown in the systems of the brokers or safekeeping banks which it uses to trade, or the failure of its investment managers' computer programs that set investment strategy. This business is currently surveying and monitoring the year 2000 readiness of its banks, brokers, and investment managers.
For our real estate and senior-living facilities business, the most reasonably likely worst case scenario is a failure of the systems that support the health, safety, and welfare of residents in the senior-living facilities. Personnel at each facility are involved in assessing their particular year 2000 issues.
Costs We estimate our total year 2000 costs for our power projects business to be approximately $4.2 million, of which $1.2 million is related to our year 2000 efforts for our Panamanian electric distribution company. The total estimated year 2000 costs for our remaining diversified businesses are approximately $2.8 million.
Accounting Standards Issued and Adopted We discuss recently issued and adopted accounting standards in Note 1.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The information required by this item with respect to market risk is set forth in Item 7 of Part II of this Form 10-K under the heading "Market Risk".
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of Baltimore Gas and Electric Company
We have audited the consolidated financial statements and the financial statement schedule of Baltimore Gas and Electric Company and Subsidiaries listed in Item 14(a) of this Form 10-K. These financial statements and the financial statement schedule are the responsibility of the Company's Management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by Management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Baltimore Gas and Electric Company and Subsidiaries as of December 31, 1998 and 1997, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein.
We have also previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheets and statements of capitalization at December 31, 1996, 1995, and 1994, and the related consolidated statements of income, cash flows, common shareholders' equity, and income taxes for each of the two years in the period ended December 31, 1995 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Summary of Operations and Summary of Financial Condition included in the Selected Financial Data for each of the five years in the period ended December 31, 1998, appearing on page 22 is fairly stated in all material respects in relation to the financial statements from which it has been derived.
/s/ PRICEWATERHOUSECOOPERS LLP - -------------------------------------------------------------------------------- PRICEWATERHOUSECOOPERS LLP
Baltimore, Maryland January 15, 1999
Consolidated Statements of Income Baltimore Gas and Electric Company and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Baltimore Gas and Electric Company and Subsidiaries
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation.
Consolidated Balance Sheets Baltimore Gas and Electric Company and Subsidiaries
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation.
Consolidated Balance Sheets Baltimore Gas and Electric Company and Subsidiaries
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation.
Consolidated Statements of Cash Flows Baltimore Gas and Electric Company and Subsidiaries
Noncash Investing and Financing Activities In 1998, Corporate Office Properties Trust (COPT) assumed approximately $62 million of Constellation Real Estate Group's (CREG) debt and issued to CREG 7.0 million common shares and 985,000 convertible preferred shares. In exchange, COPT received 14 operating properties and two properties under development from CREG.
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT YEAR'S PRESENTATION.
Consolidated Statements of Common Shareholders' Equity
Baltimore Gas and Electric Company and Subsidiaries
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT YEAR'S PRESENTATION. CONTINUED ON PAGE 46
Consolidated Statements of Capitalization Baltimore Gas and Electric Company and Subsidiaries
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT YEAR'S PRESENTATION.
Consolidated Statements of Income Taxes Baltimore Gas and Electric Company and Subsidiaries
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation.
Notes to Consolidated Financial Statements
Baltimore Gas and Electric Company and Subsidiaries
Note 1 Significant Accounting Policies
Nature of Our Business Baltimore Gas and Electric Company (BGE) is the parent company and conducts our primary business--the electric and gas utility business. That business serves Baltimore City and all or part of 10 Central Maryland counties. We also conduct various diversified businesses in subsidiary companies. We describe our operating segments in Note 2.
Consolidation Policy We use three different accounting methods to report our investments in our subsidiaries or other companies: consolidation, the equity method, and the cost method.
Consolidation We use consolidation when we own a majority of the voting stock of the subsidiary. This means the accounts of our subsidiaries are combined with our accounts. We eliminate intercompany balances and transactions when we consolidate these accounts. Our consolidated financial statements include the accounts of:
o BGE, o Constellation Enterprises, Inc. and Subsidiaries, o District Chilled Water General Partnership (ComfortLink), and o BGE Capital Trust I (See Note 7).
The Equity Method We usually use the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies (including power projects) where we hold a 20% to 50% voting interest. Under the equity method, we report:
o our interest in the entity as an investment in our Consolidated Balance Sheets, and o our percentage share of the earnings from the entity in our Consolidated Statements of Income.
The only time we do not use this method is if we can exercise control over the operations and policies of the company. If we have control, accounting rules require us to use consolidation.
We report our investment in Safe Harbor Water Power Corporation (Safe Harbor) under the equity method. Safe Harbor is a producer of hydroelectric power. BGE owns two-thirds of Safe Harbor's total capital stock, including one-half of the voting stock, and a two-thirds interest in its retained earnings.
The Cost Method We usually use the cost method if we hold less than a 20% voting interest in an investment. Under the cost method, we report our investment at cost in our Consolidated Balance Sheets. The only time we do not use this method is when we can exercise significant influence over the operations and policies of the company. If we have significant influence, accounting rules require us to use the equity method.
Regulation of Utility Business The Maryland Public Service Commission (Maryland PSC) regulates our utility business. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under generally accepted accounting principles. However, sometimes the Maryland PSC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers. When this happens, we must defer certain utility expenses and income in our Consolidated Balance Sheets as regulatory assets and liabilities. We have recorded these regulatory assets and liabilities in our Consolidated Balance Sheets in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. We summarize and discuss our regulatory assets and liabilities further in Note 4.
In 1997, the Financial Accounting Standards Board (FASB) through its Emerging Issues Task Force (EITF) issued EITF 97-4, Deregulation of the Pricing of Electricity--Issues Related to the Application of FASB Statements No. 71 and 101. The EITF concluded that a company should cease to apply SFAS No. 71 when either legislation is passed or a regulatory body issues an order that contains sufficient detail to determine how the transition plan will affect the deregulated portion of the business. Additionally, a company would continue to recognize regulated assets and liabilities in the Consolidated Balance Sheets to the extent that the transition plan provides for their recovery.
At December 31, 1998, we met the requirements of SFAS No. 71. We discuss our transition proposal for electric utility competition filed with the Maryland PSC in the "Competition and Response to Regulatory Change" section of Management's Discussion and Analysis.
Utility Revenues We record utility revenues in our Consolidated Statements of Income when we provide service to customers.
Fuel and Purchased Energy Costs We incur costs for:
o the fuel we use to generate electricity, o purchases of electricity from others, and o natural gas that we resell.
These costs are shown in our Consolidated Statements of Income as "Electric fuel and purchased energy" and "Gas purchased for resale." We discuss each of these separately below.
Fuel Used to Generate Electricity and Purchases of Electricity From Others Under the electric fuel rate clause set by the Maryland PSC, we charge our electric customers for:
o the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil), and o the net cost of purchases and sales of electricity (primarily with other utilities).
We charge the actual costs of these items to customers with no profit to us. To do this, we must keep track of what we spend and what we collect from customers under the fuel rate in a given period. Usually these two amounts are not the same because there is a difference between the time we spend the money and the time we collect it from our customers.
Under the electric fuel rate clause, we defer (include as an asset or liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) the difference between our actual costs of fuel and energy and what we collect from customers under the fuel rate in a given period. We either bill or refund our customers that difference in the future. We discuss this further in Note 4.
We calculate the electric fuel rate using three factors:
o the mix of generating plants we used over the last 24 months, o the latest three-month average fuel cost for each generating unit, and o the net cost of purchases and sales of electricity over the last 24 months.
We may change the fuel rate only if the calculated rate is more than 5% above or below the rate in effect. The fuel rate is affected most by the amount of electricity generated at our Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) because the cost of nuclear fuel is cheaper than coal, gas, or oil.
We also report two other items as "Electric fuel and purchased energy" in our Consolidated Statements of Income:
o amortization of nuclear fuel (described under "Utility Plant" later in this note). We amortize nuclear fuel based on the energy produced over the life of the fuel. We pay quarterly fees to the Department of Energy for the future disposal of spent nuclear fuel, and accrue these fees based on the kilowatt-hours of electricity sold. We bill our customers for nuclear fuel as described earlier in this note, and o amortization of deferred costs of decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. We discuss these costs further in Note 4.
Extended outages at Calvert Cliffs increase fuel costs and may result in fuel rate proceedings before the Maryland PSC. In these proceedings, the Maryland PSC would consider whether any portion of the extra fuel costs should be paid by BGE instead of passed on to customers. We discuss the financial impact of past extended outages in Note 10.
Natural Gas We charge our gas customers for the natural gas they purchase from us using "gas cost adjustment clauses" set by the Maryland PSC. These clauses operate similarly to the electric fuel rate clause described earlier in this note. However, effective October 1996, the Maryland PSC approved a modification of the gas cost adjustment clauses to provide a market based rates incentive mechanism. Under market based rates our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers.
Risk Management We engage in risk management activities in our gas business and in our diversified businesses. We separately describe these activities for each business below.
Gas Business We use basis swaps in the winter months (November through March) to hedge our price risk associated with natural gas purchases under our market based rates incentive mechanism. We also use fixed-to-floating and floating-to-fixed swaps to hedge our price risk associated with our off-system gas sales. The fixed portion represents a specific dollar amount that we will pay or receive and the floating portion represents a fluctuating amount based on a published index that we will receive or pay.
Our gas business internal guidelines do not permit the use of swap agreements for any other purpose than to hedge price risk.
We defer, as unrealized gains or losses, the net amount we are due (unrealized gains) or owe (unrealized losses) under the swap agreements in our Consolidated Balance Sheets.
When amounts are paid under the agreements, we report the payments as gas costs in our Consolidated Statements of Income.
Diversified Businesses Our subsidiary, Constellation Power Source, engages in power marketing activities, which include trading electricity, other energy commodities, and related derivatives (such as futures, forwards, options, and swaps). Constellation Power Source uses the mark-to-market method of accounting for its trading activities.
Under the mark-to-market method of accounting, we report:
o commodity positions and derivatives at fair value as "Assets from energy trading activities" or "Liabilities from energy trading activities" in our Consolidated Balance Sheets, and o changes in fair value as components of "Diversified business revenues" in our Consolidated Statements of Income.
Taxes We summarize our income taxes in our Consolidated Statements of Income Taxes. As you read this section, it may be helpful to refer to those statements.
Income Tax Expense We have two categories of income taxes in our Consolidated Statements of Income--current and deferred. We describe each of these below.
Our current income tax expense consists solely of regular tax less applicable tax credits. Our 1996 current income tax expense amount includes alternative minimum tax credits of $30 million. The alternative minimum tax can be carried forward indefinitely and used as tax credits in years when our regular tax liability exceeds the alternative minimum tax liability. We do not have any remaining alternative minimum tax credits.
Our deferred income tax expense is equal to the changes in the net deferred income tax liability, excluding amounts charged or credited to common shareholders' equity. Our deferred income tax expense is increased or reduced for changes to the net regulatory asset (described later in this note) during the year.
Investment Tax Credits We have deferred the investment tax credit associated with our regulated utility business in our Consolidated Balance Sheets. The investment tax credit is amortized evenly to income over the life of each property. We reduce income tax expense in our Consolidated Statements of Income for the investment tax credit and other tax credits associated with our diversified businesses, other than leveraged leases.
Deferred Income Tax Assets and Liabilities We must report some of our revenues and expenses differently for our financial statements than we do for income tax purposes. The tax effects of the differences in these items are reported as deferred income tax assets or liabilities in our Consolidated Balance Sheets. We measure the assets and liabilities using income tax rates that are currently in effect.
A portion of our total deferred income tax liability relates to our utility business, but has not been reflected in the rates we charge our customers. We refer to this portion of the liability as "Income taxes recoverable or payable through future rates." We have recorded that portion of the net liability as a regulatory asset in our Consolidated Balance Sheets. We discuss this further in Note 4.
Franchise Taxes We pay Maryland public service company franchise tax instead of state income tax on our utility revenue from sales in Maryland. We include the franchise tax in "Taxes other than income taxes" in our Consolidated Statements of Income.
Inventory We report the majority of our fuel stocks and materials and supplies at average cost.
Real Estate Projects and Investments In Note 3, we summarize the real estate projects and investments that are in our Consolidated Balance Sheets. The projects and investments consist of:
o land under development in the Baltimore-Washington corridor, o an entertainment, dining, and retail complex in Orlando, Florida, o a mixed-use planned-unit development, o senior-living facilities, and o beginning in 1998, a 41.9% equity interest in Corporate Office Properties Trust, a real estate investment trust.
The costs incurred to acquire and develop properties are included as part of the cost of the properties.
Evaluation of Assets for Impairment SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, applies particular requirements to some of our assets that have long lives. (Some examples are utility property and equipment and real estate.) We determine if those assets are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting records. We recognize an impairment loss if the undiscounted expected future cash flows are less than the carrying amount of the asset.
Financial Investments and Trading Securities In Note 3, we summarize the financial investments that are in our Consolidated Balance Sheets.
SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, applies particular requirements to some of our investments in debt and equity securities. We report those investments at fair value, and we use specific identification to determine their cost for computing realized gains or losses. We classify these investments as either trading securities or available-for-sale securities, which we describe separately below. We report investments that are not covered by SFAS No. 115 at their cost.
Trading Securities Our diversified businesses classify some of their investments in marketable equity securities and financial limited partnerships as trading securities. We include any unrealized gains or losses on these securities in "Diversified business revenues" in our Consolidated Statements of Income.
Available-for-Sale Securities We classify our investments in the nuclear decommissioning trust fund as available-for-sale securities. We include any unrealized gains or losses on the trust assets as a change in the decommissioning reserve. We describe the nuclear decommissioning trust and the reserve under the heading "Decommissioning Costs" later in this note.
In addition, our diversified businesses classify some of their investments in marketable equity securities as available-for-sale securities. We include any unrealized gains or losses on these securities in "Accumulated other comprehensive income" in our Consolidated Statements of Common Shareholders' Equity and in the Consolidated Statements of Capitalization. We also include our diversified businesses' portion of unrealized gains or losses on securities of equity-method (described earlier in this note) investees in our Consolidated Statements of Common Shareholders' Equity.
Utility Plant, Depreciation, Amortization, and Decommissioning Utility Plant Utility plant is the term we use to describe our utility business property and equipment that is in use, being held for future use, or under construction. We summarize utility plant in our Consolidated Balance Sheets. We report our utility plant at its original cost, which includes:
o material and labor, o contractor costs, o construction overhead costs (where applicable), and o an allowance for funds used during construction (described later in this note).
We charge retired or otherwise-disposed-of utility plant to accumulated depreciation.
We own an undivided interest in the Keystone and Conemaugh electric generating plants in Western Pennsylvania, as well as in the transmission line that transports the plants' output to the joint owners' service territories. Our ownership interests in these plants are 20.99% in Keystone and 10.56% in Conemaugh. These ownership interests represented a net investment of $152 million at December 31, 1998 and 1997. We report these properties in the same accounts we use for our other utility plant (described above).
Depreciation Expense Generally, we compute depreciation by applying composite, straight-line rates (approved by the Maryland PSC) to the average investment in classes of depreciable property. We depreciate vehicles based on their estimated useful lives.
Amortization Expense Amortization is an accounting process of reducing an amount in our Consolidated Balance Sheets evenly over a period of time. When we reduce amounts in our Consolidated Balance Sheets, we increase amortization expense in our Consolidated Statements of Income. An amount is considered fully amortized when it has been reduced to zero.
Decommissioning Costs We must accumulate a reserve for the costs that we expect to incur in the future to decommission the radioactive portion of Calvert Cliffs. We do this based on a sinking fund methodology. The Maryland PSC authorized us to record decommissioning expense based on a facility-specific cost estimate so we can accumulate a decommissioning reserve of $521.0 million in 1993 dollars by the end of Calvert Cliffs' service life in 2016, adjusted to reflect expected inflation. We have reported the decommissioning reserve in "Accumulated depreciation" in our Consolidated Balance Sheets. The total reserve was $244.0 million at December 31, 1998 and $201.6 million at December 31, 1997.
To fund the costs we expect to incur to decommission the plant, we established an external decommissioning trust in accordance with Nuclear Regulatory Commission (NRC) regulations. We report the assets in the trust in "Nuclear decommissioning trust fund" in our Consolidated Balance Sheets. The NRC requires utilities to provide financial assurance that they will accumulate sufficient funds to pay for the cost of nuclear decommissioning based upon either a generic NRC formula or a facility-specific decommissioning cost estimate. We use the facility-specific cost estimate for funding these costs and providing the required financial assurance.
Allowance for Funds Used During Construction and Capitalized Interest Allowance for Funds Used During Construction (AFC) We finance construction projects with borrowed funds and equity funds. We are allowed by the Maryland PSC to record the costs of these funds as part of the cost of construction projects in our Consolidated Balance Sheets. We do this through the AFC, which we calculate using a rate authorized by the Maryland PSC. We bill our customers for the AFC plus a return after the utility plant is placed in service.
The AFC rates are 9.04% for gas plant, 9.36% for common plant, and 9.40% for electric plant. We compound AFC annually.
Capitalized Interest Our diversified businesses capitalize interest costs incurred to finance real estate developed for internal use and certain power projects.
Long-Term Debt We defer (include as an asset or liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) all costs related to the issuance of long-term debt. These costs include underwriters' commissions, discounts or premiums, and other costs such as legal, accounting and regulatory fees, and printing costs. We amortize these costs over the life of the debt.
When we incur gains or losses on debt that we retire prior to maturity, we amortize those gains or losses over the remaining original life of the debt.
Cash Flows For the purpose of reporting our cash flows, we define cash equivalents as highly liquid investments that mature in three months or less.
Use of Accounting Estimates Management makes estimates and assumptions when preparing financial statements under generally accepted accounting principles. These estimates and assumptions affect various matters, including:
o our reported amounts of assets and liabilities in our Consolidated Balance Sheets at the dates of the financial statements, o our disclosure of contingent assets and liabilities at the dates of the financial statements, and o our reported amounts of revenues and expenses in our Consolidated Statements of Income during the reporting periods.
These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. As a result, actual amounts could differ from these estimates.
Reclassifications We have reclassified certain prior-year amounts for comparative purposes. These reclassifications did not affect consolidated net income for the years presented.
Accounting Standards Adopted We adopted SFAS No. 130, Reporting Comprehensive Income, effective January 1, 1998. Comprehensive income includes net income plus all changes in shareholders' equity for the period, excluding shareholder transactions (some examples are stock issuances and dividend payments). Our comprehensive income includes net income plus the effect of unrealized gains or losses on available-for-sale securities. We have presented comprehensive income in the Consolidated Statements of Comprehensive Income, and accumulated other comprehensive income in the Consolidated Statements of Common Shareholders' Equity and in the Consolidated Statements of Capitalization.
We adopted SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, effective January 1, 1998. SFAS No. 131 establishes standards for the way that we report information about operating segments in annual financial statements and requires that we report selected information about operating segments in interim financial reports. SFAS No. 131 also establishes standards for related disclosures about products and services, geographic areas, and major customers. The adoption of this statement did not affect results of operations or financial position, but did affect the disclosure of segment information. See Note 2.
We adopted SFAS No. 132, Employers' Disclosures about Pensions and Other Postretirement Benefits, effective January 1, 1998. SFAS No. 132 establishes standards for the way that we report our pension and postretirement benefits as well as requiring additional information on changes in the benefit obligations and fair values of plan assets. The adoption of this statement did not affect results of operations or financial position, but did affect the disclosure of pension and postretirement benefits information. See Note 5.
Accounting Standards Issued In March 1998, the American Institute of Certified Public Accountants (AICPA) issued Statement of Position (SOP) 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. SOP 98-1 establishes the accounting for the costs of computer software developed or obtained for internal use. We must adopt the requirements of this statement in our financial statements for the year ending December 31, 1999.
In April 1998, the AICPA issued SOP 98-5, Reporting on the Costs of Start-up Activities. SOP 98-5 establishes the accounting for the costs of start-up activities. We must adopt the requirements of this statement in our financial statements for the year ending December 31, 1999.
We do not expect the adoption of these statements to have a material impact on our financial results.
In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 133 establishes the accounting and disclosure standards for derivative financial instruments and hedging Activities. We must adopt the requirements of this standard beginning with our financial statements for the quarter ending March 31, 2000. We have not determined the effects of SFAS No. 133 on our financial results.
In November 1998, the EITF reached a consensus on EITF 98-10, Accounting for Energy Trading and Risk Management Activities, requiring that energy trading activities be accounted for on a mark-to-market basis. We must adopt the requirements of this consensus in our financial statements for the year ending December 31, 1999. We do not expect the adoption of this consensus to have a material impact on our financial results.
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Note 2 Information by Operating Segment We have three reportable operating segments: Electric, Gas, and Energy Services:
o our Electric business generates, purchases, and sells electricity, o our Gas business purchases, transports, and sells natural gas, and o our Energy Services businesses consist of certain diversified businesses that: -- engage in power projects, -- provide marketing and risk management services, -- sell natural gas through mass marketing efforts, sell and service electric and gas appliances, heating and air conditioning systems, and engage in home improvements, and -- provide cooling services to commercial customers in Baltimore.
Our remaining diversified businesses: o engage in financial investments, and o develop, own, and manage real estate and senior-living facilities.
These reportable segments are strategic businesses based principally upon regulations, products, and services that require different technology and marketing strategies. The segments have the same accounting policies as those described in the summary of significant accounting policies in Note 1. We evaluate the performance of these segments based on net income. We account for intersegment revenues using market prices.
A summary of information by operating segment is shown on page 54.
(A) A holding company for our diversified businesses does not allocate the items presented in the table to our Energy Services and Other Diversified businesses. (B) Our Energy Services and our Other Diversified businesses record their equity in earnings of equity-method investees in their unaffiliated revenues. (C) Our Energy Services businesses recorded $10.4 million for its share of earnings in a partnership as discussed in Note 3 and a $5.5 million write-off of an energy services investment as discussed in the "Other Energy Services" section of Management's Discussion and Analysis. In addition, our Other Diversified businesses recorded a $15.4 million write-down of a real estate project as discussed in Note 3. (D) Our Electric business recorded a $37.5 million write-off related to the terminated merger with Potomac Electric Power Company as discussed in the "Write-Off of Merger Costs" section of Management's Discussion and Analysis. In addition, our Other Diversified businesses recorded a $46.0 million write-down of two real estate projects as discussed in Note 3. (E) Our Electric business recorded a $62.1 million write-off of electric replacement energy costs as discussed in Note 10. In addition, our Energy Services businesses recorded $14.6 million for its share of earnings in a partnership and $16.2 million of write-offs of several power projects as discussed in Note 3.
Note 3 Investments
Real Estate Projects and Investments Real estate projects and investments held by Constellation Real Estate Group (CREG), consist of the following:
At December 31, 1998 1997 - --------------------------------------------------------- (In millions) Properties under development $210.6 $220.8 Rental and operating properties (net of accumulated depreciation) 38.9 225.6 Equity interest in real estate investment trust 104.0 -- Other real estate ventures 0.4 0.4 - --------------------------------------------------------- Total real estate projects and investments $353.9 $446.8 =========================================================
In 1998, CREG recorded a $15.4 million after-tax write-down of the investment in Church Street Station--an entertainment, dining, and retail complex in Orlando, Florida--which occurred because the fair value of the project has declined based upon recent competitive bids. CREG is attempting to sell this complex during 1999.
In 1998, CREG entered into an agreement with Corporate Office Properties Trust (COPT), a real estate investment trust based in Philadelphia.
Under the terms of the agreement, COPT assumed approximately $62 million of CREG's outstanding debt, paid CREG approximately $22.8 million in cash, and issued to CREG approximately 7.0 million common shares, representing a 41.9% equity interest in COPT, and 985,000 convertible preferred shares. Each convertible preferred share yields 5.5% per year, and is convertible after two years into 1.8748 common shares.
In exchange, COPT received 14 operating properties and two properties under development from CREG as well as certain other assets, options, and first refusal rights. These options and first refusal rights are related to approximately 91 acres of identified properties which are adjacent to operating properties being acquired by COPT. These options and first refusal rights have terms that range from 2-5 years.
By July 1999, COPT is expected to acquire one retail property from CREG for approximately $3.5 million in cash, unless that property is sold to another party prior to that time.
In 1997, CREG recorded the following write-downs of real estate projects:
o a $14.1 million after-tax write-down of the investment in Church Street Station--which occurred because CREG decided to sell rather than keep the project, and o a $31.9 million after-tax write-down of the investment in Piney Orchard--a mixed-use, planned-unit development--which occurred because the expected future cash flow from the project was less than CREG's investment in the project.
Power Projects Power projects held by our diversified businesses consist of the following:
At December 31, 1998 1997 - ---------------------------------------------- (In millions) Domestic East $ 39.8 $ 41.3 West 426.2 377.7 International South America 21.6 18.3 Central America 161.8 5.2 Other 7.4 9.2 - ---------------------------------------------- Total power projects $656.8 $451.7 ==============================================
Our Domestic-West power projects include investments of $310.6 million in 1998 and $261.4 million in 1997 that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. We discuss these projects further in Note 10.
In 1998, our power projects business recorded a $10.4 million after-tax gain for its share of earnings in a partnership. The partnership recognized a gain on the sale of its ownership interest in a power sales contract.
In 1996, our power projects business recorded a $14.6 million after-tax gain for its share of earnings in a partnership. The partnership recognized a gain on the sale of a power purchase agreement. In addition, our power projects business had the following write-offs:
o a $7.0 million after-tax write-off of an investment in two geothermal wholesale power generating projects that sell electricity under California power purchase agreements. These projects were written off because the expected future cash flow from the projects were less than the investments in the projects, o a $3.0 million after-tax write-off of development costs for a coal-fired power project when development efforts on the project were terminated, and
o a $6.2 million after-tax write-off of a portion of an investment in a solar power project to reflect a settlement with the project's lender.
Financial Investments Financial investments consist of the following:
At December 31, 1998 1997 - ----------------------------------------------- (In millions) Insurance company $102.5 $ 88.8 Marketable equity securities 25.3 33.3 Financial limited partnerships 41.9 43.6 Leveraged leases 28.3 30.8 - ----------------------------------------------- Total financial investments $198.0 $196.5 ===============================================
Investments Classified as Available-for-Sale We classify our investments in the nuclear decommissioning trust fund as available-for-sale. In addition, we classify some of our diversified businesses' marketable equity securities as available-for-sale. This means we do not expect to hold them to maturity and we do not consider them trading securities.
We show the fair values, gross unrealized gains and losses, and amortized cost bases for all of our available-for-sale securities, exclusive of $6.2 million in 1998 and $3.5 million in 1997 of unrealized net gains on securities of equity-method investees, in the following tables:
Amortized Unrealized Unrealized Fair At December 31, 1998 Cost Basis Gains Losses Value - ------------------------------------------------------------------------ (In millions) Marketable Equity Securities $ 82.9 $24.2 $(0.4) $106.7 U.S. Government agency 12.7 0.4 -- 13.1 State municipal bonds 64.8 2.7 -- 67.5 - ------------------------------------------------------------------------ Totals $160.4 $27.3 $(0.4) $187.3 ========================================================================
Amortized Unrealized Unrealized Fair At December 31, 1997 Cost Basis Gains Losses Value - ------------------------------------------------------------------------ (In millions) Marketable Equity Securities $ 77.3 $12.0 $(0.5) $ 88.8 U.S. Government agency 14.9 0.2 -- 15.1 State municipal bonds 65.5 2.2 -- 67.7 - ------------------------------------------------------------------------ Totals $157.7 $14.4 $(0.5) $171.6 ========================================================================
These tables include $23.9 million in 1998 and $10.0 million in 1997 of unrealized net gains associated with the nuclear decommissioning trust fund which are reflected as a change in the nuclear decommissioning trust fund on the Consolidated Balance Sheets.
Gross and net realized gains and losses on available-for-sale securities were as follows:
1998 1997 1996 - ----------------------------------------------- (In millions) Gross realized gains $4.2 $ 9.3 $ 4.3 Gross realized losses (0.7) (0.6) (0.2) - ----------------------------------------------- Net realized gains $3.5 $ 8.7 $ 4.1 ===============================================
The U.S. Government agency obligations and state municipal bonds mature on the following schedule:
At December 31, 1998 Amount - -------------------------------------------------- (In millions) Less than 1 year $ -- 1-5 years 33.5 5-10 years 29.9 More than 10 years 17.2 - -------------------------------------------------- Total maturities of debt securities $ 80.6 ==================================================
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Note 4 Regulatory Assets (net) As discussed in Note 1, the Maryland PSC regulates our utility business. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under generally accepted accounting principles. However, sometimes the Maryland PSC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers. When this happens, we must defer certain utility expenses and income in our Consolidated Balance Sheets as regulatory assets and liabilities. We then record them in our Consolidated Statements of Income (using amortization) when we include them in the rates we charge our customers.
We summarize our regulatory assets and liabilities in the following table, and we discuss each of them separately on page 57.
At December 31, 1998 1997 - ------------------------------------------------------------ (In millions) Income taxes recoverable through future rates (net) $252.6 $256.5 Deferred postretirement and postemployment benefit costs 90.0 96.4 Deferred nuclear expenditures 73.3 77.7 Deferred conservation expenditures 53.4 55.8 Deferred costs of decommissioning federal uranium enrichment facilities 38.5 42.4 Deferred environmental costs 33.4 38.8 Deferred fuel costs (net) 12.7 4.4 Deferred termination benefit costs 2.2 21.0 Other (net) 9.6 4.3 - ------------------------------------------------------------ Total regulatory assets (net) $565.7 $597.3 ============================================================
Income Taxes Recoverable Through Future Rates (net) As described in Note 1, income taxes recoverable through future rates are the portion of our net deferred income tax liability that is applicable to our utility business, but has not been reflected in the rates we charge our customers. These income taxes represent the tax effect of temporary differences in depreciation and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on deferred investment tax credits. We amortize these amounts as the temporary differences reverse.
Deferred Postretirement and Postemployment Benefit Costs Deferred postretirement and postemployment benefit costs are the costs we recorded under SFAS No. 106 (for postretirement benefits) and SFAS No. 112 (for postemployment benefits) in excess of the costs we included in the rates we charge our customers. We began amortizing these costs over a 15-year period in 1998. We discuss these costs further in Note 5.
Deferred Nuclear Expenditures Deferred nuclear expenditures are the net unamortized balance of certain operations and maintenance costs at Calvert Cliffs. These expenditures consist of:
o costs incurred from 1979 through 1982 for inspecting and repairing seismic pipe supports, o expenditures incurred from 1989 through 1994 associated with nonrecurring phases of certain nuclear operations projects, and o expenditures incurred during 1990 for investigating leaks in the pressurizer heater sleeves.
We are amortizing these costs over the remaining life of the plant in accordance with the Maryland PSC's orders.
Deferred Conservation Expenditures Deferred conservation expenditures include two components:
o operations costs (labor, materials, and indirect costs) associated with conservation programs approved by the Maryland PSC, which we are amortizing over periods of four to five years in accordance with the Maryland PSC's orders, and o revenues we collected from customers in 1996 in excess of our profit limit under the conservation surcharge.
The Maryland PSC allows us to collect from customers money spent on conservation programs under a "conservation surcharge." However, under this surcharge the Maryland PSC limits what our profit can be. If, at the end of the year, we have exceeded our allowed profit, we defer the excess in that year and we lower the amount of future surcharges to our customers to correct the amount of overage, plus interest.
During 1996, we exceeded our profit limit under the conservation surcharge. As a result, we deferred $28.5 million of our 1996 revenue from surcharge billings as a regulatory liability. To correct the overage, we lowered the surcharge on our customers' bills over a 12-month period beginning July 1997 through June 1998.
Deferred Costs of Decommissioning Federal Uranium Enrichment Facilities Deferred costs of decommissioning federal uranium enrichment facilities are the unamortized portion of our required contributions to a fund for decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. We are required, along with other domestic utilities, by the Energy Policy Act of 1992 to make contributions to the fund. The contributions are generally payable over 15 years with escalation for inflation and are based upon the proportionate amount of uranium enriched by the Department of Energy for each utility. We are amortizing these costs over the contribution period as a cost of fuel. We also discuss this in Note 1.
Deferred Environmental Costs Deferred environmental costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss this further in Note 10. We are amortizing $21.6 million of these costs (the amount we had incurred through October 1995) over a 10-year period in accordance with the Maryland PSC's November 1995 order.
Deferred Fuel Costs As described in Note 1, deferred fuel costs are the difference between our actual costs of electric fuel, net purchases and sales of electricity, and natural gas and our fuel rate revenues collected from customers. We reduce deferred fuel costs as we collect them from or refund them to our customers.
We show our deferred fuel costs in the following table:
At December 31, 1998 1997 - --------------------------------------------------------- (In millions) Electric over-recovered fuel costs $(11.5) $(19.0) Gas deferred fuel costs 24.2 23.4 - --------------------------------------------------------- Deferred fuel costs (net) $ 12.7 $ 4.4 =========================================================
Deferred Termination Benefits Deferred termination benefit costs are the net unamortized balance of the cost of certain termination benefits offered to employees of our regulated utility operations in 1992 and 1993. We are amortizing these costs over a five-year period in accordance with the Maryland PSC's orders.
Note 5 Pension, Postretirement, Other Postemployment, and Employee Savings Plan Benefits We offer pension, postretirement, other postemployment, and employee savings plan benefits. We describe each of these separately below.
Pension Benefits We sponsor several defined benefit pension plans for our employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. Our largest plan covers nearly all BGE employees and certain employees of our subsidiaries. Our other plans, which are not material in amount, provide supplemental benefits to certain key employees. Our employees do not contribute to these plans. Generally, we calculate the benefits under these plans based on age, years of service, and pay.
Sometimes we amend the plans retroactively. These retro- active plan amendments require us to recalculate benefits related to participants' past service. We amortize the change in the benefit costs from these plan amendments on a straight-line basis over the average remaining service period of active employees.
We fund the plans by contributing at least the minimum amount required under Internal Revenue Service regulations. We calculate the amount of funding using an actuarial method called the projected unit credit cost method. The assets in all of the plans at December 31, 1998 were mostly marketable equity and fixed income securities, and group annuity contracts.
Postretirement Benefits We sponsor defined benefit postretirement health care and life insurance plans which cover nearly all BGE employees and certain employees of our subsidiaries. Generally, we calculate the benefits under these plans based on age, years of service, and pension benefit levels. We do not fund these plans.
For nearly all of the health care plans, retirees make contributions to cover a portion of the plan costs. Contributions for employees who retire after June 30, 1992 are calculated based on age and years of service. The amount of retiree contributions increases based on expected increases in medical costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs.
Effective January 1, 1993, we adopted SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. The adoption of that statement caused:
o a transition obligation, which we are amortizing over 20 years, and o an increase in annual postretirement benefit costs.
For our diversified businesses, we expense all postretirement benefit costs. For our utility business, we accounted for the increase in annual postretirement benefit costs under two Maryland PSC rate orders: o in an April 1993 rate order, the Maryland PSC allowed us to expense one-half and defer, as a regulatory asset (see Note 4), the other half of the increase in annual postretirement benefit costs related to our electric and gas businesses, and o in a November 1995 rate order, the Maryland PSC allowed us to expense all of the increase in annual postretirement benefit costs related to our gas business.
Beginning in 1998, the Maryland PSC authorized us to:
o expense all of the increase in annual postretirement benefit costs related to our electric business, and o amortize the regulatory asset for postretirement benefit costs related to our electric and gas businesses over 15 years.
Obligations, Assets, and Funded Status We show the change in the benefit obligations, plan assets, and funded status of the pension and postretirement benefit plans in the following table:
Postretirement Pension Benefits Benefits 1998 1997 1998 1997 - ---------------------------------------------------------------------------- (In millions) Change in benefit obligation Benefit obligation at January 1, $ 902.0 $846.3 $320.3 $311.0 Service cost 21.6 16.8 6.6 5.4 Interest cost 63.0 61.3 23.4 21.8 Plan participants' contributions -- -- 2.0 2.0 Actuarial loss (gain) 102.9 35.5 48.9 (2.1) Benefits paid (58.2) (57.9) (18.1) (17.8) - ---------------------------------------------------------------------------- Benefit obligation at December 31, $1,031.3 $902.0 $383.1 $320.3 ============================================================================
Change in plan assets Fair value of plan assets at January 1, $912.3 $795.4 $ -- $ -- Actual return on plan assets 116.9 130.0 -- -- Employer contribution 14.5 44.8 16.1 15.8 Plan participants' contributions -- -- 2.0 2.0 Benefits paid (58.2) (57.9) (18.1) (17.8) - ---------------------------------------------------------------------------- Fair value of plan assets at December 31, $985.5 $912.3 $ -- $ -- ============================================================================
Postretirement Pension Benefits Benefits 1998 1997 1998 1997 - -------------------------------------------------------------- (In millions) Funded status Funded status at December 31, $ (45.8) $ 10.3 $(383.1) $(320.3) Unrecognized net actuarial loss 137.6 84.2 59.7 10.9 Unrecognized prior service cost 16.9 19.4 -- -- Unrecognized transition obligation -- -- 159.3 170.6 Unamortized net asset from adoption of SFAS No. 87 (0.7) (0.9) -- -- - -------------------------------------------------------------- Prepaid (accrued) benefit cost $108.0 $113.0 $(164.1) $(138.8) ==============================================================
Net Periodic Benefit Cost We show the components of net periodic pension benefit cost in the following table:
Year Ended December 31, 1998 1997 1996 - ------------------------------------------------------------------ (In millions) Components of net periodic pension benefit cost Service cost $21.6 $16.8 $16.1 Interest cost 63.0 61.3 59.9 Expected return on plan assets (72.1) (66.9) (62.8) Amortization of transition asset (0.2) (0.2) (0.2) Amortization of prior service cost 2.5 2.5 2.5 Recognized net actuarial loss 5.6 4.6 4.9 Amount capitalized as construction cost (3.8) (2.5) (2.4) - ------------------------------------------------------------------ Net periodic pension benefit cost $16.6 $15.6 $18.0 ==================================================================
We show the components of net periodic postretirement benefit cost in the following table:
Year Ended December 31, 1998 1997 1996 - ----------------------------------------------------------------- (In millions) Components of net periodic postretirement benefit cost Service cost $ 6.6 $ 5.4 $ 5.5 Interest cost 23.4 21.8 21.9 Amortization of transition obligation 11.4 11.4 11.4 Recognized net actuarial loss 0.2 0.1 0.2 Amount capitalized as construction cost (8.1) (7.6) (6.2) Amount deferred -- (7.2) (7.4) - ----------------------------------------------------------------- Net periodic postretirement benefit cost $33.5 $23.9 $25.4 =================================================================
Assumptions We made the assumptions below to calculate our pension and postretirement benefit cost and obligations.
Postretirement Pension Benefits Benefits At December 31, 1998 1997 1998 1997 - -------------------------------------------------------------- Discount rate 6.50% 7.25% 6.50% 7.25% Expected return on plan assets 9.00 9.00 N/A N/A Rate of compensation increase 4.00 4.00 4.00 4.00
We assumed the health care inflation rates to be:
o in 1998, 6.0% for both Medicare-eligible retirees and retirees not covered by Medicare, and o in 1999, 7.5% for Medicare-eligible retirees and 9.0% for retirees not covered by Medicare.
After 1999, we assumed both inflation rates will decrease by 0.5% annually to a rate of 5.5% in the years 2003 and 2006.
A 1% increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit obligation by approximately $52.8 million as of December 31, 1998 and would increase the combined service and interest costs of the postretirement benefit cost by approximately $4.5 million annually.
A 1% decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretirement benefit obligation by approximately $41.7 million as of December 31, 1998 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $3.5 million annually.
Other Postemployment Benefits We provide the following postemployment benefits:
o health and life insurance benefits to our employees and certain employees of our subsidiaries who are found to be disabled under our Disability Insurance Plan, and
o income replacement payments for employees found to be disabled before November 1995. (Payments for employees found to be disabled after that date are paid by an insurance company, and the cost is paid by employees.)
The liability for these benefits totaled $52.9 million as of December 31, 1998 and $45.4 million as of December 31, 1997.
Effective December 31, 1993, we adopted SFAS No. 112, Employers' Accounting for Postemployment Benefits. We deferred, as a regulatory asset (see Note 4), the postemployment benefit liability attributable to our utility business as of December 31, 1993, consistent with the Maryland
PSC's orders for postretirement benefits (described earlier in this note). We began to amortize the regulatory asset over 15 years beginning in 1998. The Maryland PSC authorized us to reflect this change in our current electric and gas base rates to recover the higher costs in 1998.
We assumed the discount rate for other postemployment benefits to be 4.5% in 1998 and 6.0% in 1997.
Employee Savings Plan Benefits We also sponsor a defined contribution savings plan that is offered to all eligible BGE employees and certain employees of our subsidiaries. In a defined contribution plan, the benefits a participant is to receive result from regular contributions to a participant account. Under this plan, we make matching contributions to participant accounts. We made matching contributions to this plan of:
o $10.1 million in 1998, o $8.5 million in 1997, and o $9.4 million in 1996.
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Note 6 Short-Term Borrowings
Summary of Short-Term Borrowings Our short-term borrowings may include bank loans, commercial paper notes, and bank lines of credit. Short-term borrowings mature within one year from the date of the financial statements. We pay commitment fees to banks for providing us lines of credit. When we borrow under the lines of credit, we pay market interest rates.
As of December 31, 1998, we had no short-term borrowings outstanding. As of December 31, 1997, we had $316.1 million outstanding consisting entirely of BGE commercial paper notes.
We had unused bank lines of credit supporting our commercial paper notes of $113 million at December 31, 1998 and $231 million at December 31, 1997. These amounts do not include unused revolving credit agreements of $100 million at December 31, 1998 and 1997 that are discussed in Note 7.
Constellation Enterprises, Inc. has a $135 million unsecured revolving credit agreement that matures December 20, 1999, to provide liquidity for general corporate purposes including financing requirements of subsidiaries and to provide for the issuance of letters of credit to meet subsidiary business requirements. At December 31, 1998, letters of credit totaling $2.3 million were issued under this credit facility.
Weighted-Average Interest Rates Our weighted-average effective interest rate for BGE's commercial paper notes was 5.65% for the year ended December 31, 1998 and 5.66% for 1997.
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Note 7 Long-Term Debt Long-term debt matures more than one year from the date of the financial statements. We summarize our long-term debt in the Consolidated Statements of Capitalization. As you read this section, it may be helpful to refer to those statements. We discuss BGE's and our diversified businesses' long-term debt separately below.
BGE's Long-Term Debt BGE's First Refunding Mortgage Bonds BGE's first refunding mortgage bonds are secured by a mortgage lien on nearly all of its assets, including all utility properties and franchises and its subsidiary capital stock. BGE's subsidiary capital stock pledged under the mortgage is that of Safe Harbor Water Power Corporation and Constellation Enterprises, Inc.
BGE is required to make an annual sinking fund payment each August 1 to the mortgage trustee. The amount of the payment is equal to 1% of the highest principal amount of bonds outstanding during the preceding 12 months. The trustee uses these funds to retire bonds from any series through repurchases or calls for early redemption. However, the trustee cannot call the following bonds for early redemption:
o 5 1/2% Installment Series, o 6 1/2% Series, due 2003 due 2002 o 6 1/8% Series, due 2003 o 8.40% Series, due 1999 o 5 1/2% Series, due 2004 o 5 1/2% Series, due 2000 o 7 1/2% Series, due 2007 o 8 3/8% Series, due 2001 o 6 5/8% Series, due 2008 o 7 1/4% Series, due 2002
Holders of the Remarketed Floating Rate Series Due September 1, 2006 have the option to require BGE to repurchase their bonds at face value on September 1 of each year. BGE is required to repurchase and retire at par any bonds that are not remarketed or purchased by the remarketing agent. BGE also has the option to redeem all or some of these bonds at face value each September 1.
BGE's Other Long-Term Debt We show the weighted-average interest rates and maturity dates for BGE's fixed-rate medium-term notes outstanding at December 31, 1998 in the following table:
Weighted-Average Series Interest Rate Maturity Dates - ------------------------------------------------ B 8.10% 2000-2006 C 7.34 1999-2003 D 6.66 2001-2006 E 6.66 2006-2012 G 6.08 2008
Some of the medium-term notes include a "put option." These put options allow the holders to sell their notes back to BGE on the put option dates at a price equal to 100% of the principal amount. The following is a summary of medium-term notes with put options:
Series E Notes Principal Put Option Dates - ------------------------------------------------------ (In millions) 6.75%, due 2012 $60.0 June 2002 and 2007 6.75%, due 2012 25.0 June 2004 and 2007 6.73%, due 2012 25.0 June 2004 and 2007
BGE has $100 million of revolving credit agreements with several banks that are available through 2000 to 2001. At December 31, 1998, BGE had no outstanding borrowings under these agreements. These banks charge us commitment fees based on the daily average of the unborrowed amount, and we pay market interest rates on any borrowings. These agreements also support BGE's commercial paper notes, as described in Note 6.
Company Obligated Mandatorily Redeemable Trust Preferred Securities On June 15, 1998, BGE Capital Trust I (Trust), a Delaware business trust established by BGE, issued 10,000,000 Trust Originated Preferred Securities (TOPrS) for $250 million ($25 liquidation amount per preferred security) with a distribution rate of 7.16%.
The Trust used the net proceeds from the issuance of common securities and the preferred securities to purchase a series of 7.16% Deferrable Interest Subordinated Debentures due June 30, 2038 (Debentures) from BGE in the aggregate principal amount of $257.7 million with the same terms as the TOPrS. The Trust must redeem the TOPrS at $25 per preferred security plus accrued but unpaid distributions when the Debentures are paid at maturity or upon any earlier redemption. BGE has the option to redeem the Debentures at any time on or after June 15, 2003 or at any time when certain tax or other events occur.
The interest paid on the Debentures, which the Trust will use to make distributions on the TOPrS, is included in "Interest Expense" in the Consolidated Statements of Income and is deductible for income tax purposes.
BGE fully and unconditionally guarantees the TOPrS based on its various obligations relating to the trust agreement, indentures, Debentures, and the preferred security guarantee agreement.
The Debentures are the only assets of the Trust. The Trust is wholly owned by BGE because we own all the common securities of the Trust that have general voting power.
For the payment of dividends and in the event of liquidation of BGE, the Debentures are ranked prior to preference stock and common stock.
Diversified Businesses' Long-Term Debt Revolving Credit Agreements A subsidiary of Constellation Enterprises, Inc. has a $75 million unsecured revolving credit agreement that matures December 9, 1999, to provide liquidity for general corporate purposes. Our diversified businesses pay a commitment fee based on the daily average of the unborrowed portion of the commitment. At December 31, 1998, our diversified businesses had $45.0 million outstanding under this agreement.
Constellation Energy Source has a $10 million revolving credit agreement that matures February 1, 2000. At December 31, 1998, Constellation Energy Source had no outstanding borrowings under this agreement. Constellation Energy Source pays a facility fee based on the total amount of the commitment.
ComfortLink has a $50 million unsecured revolving credit agreement that matures September 26, 2001. Under the terms of the agreement, ComfortLink has the option to obtain loans at various rates for terms up to nine months. ComfortLink pays a facility fee on the total amount of the commitment. At December 31, 1998, ComfortLink had $29 million outstanding under this agreement.
Mortgage and Construction Loans Our diversified businesses' mortgage and construction loans have varying terms. The following mortgage notes require monthly principal and interest payments:
o 7.90%, due in 2000 o 7.357%, due in 2009 o 8.00%, due in 2001 o 9.65%, due in 2028
The 8.00% mortgage note due in 2003 requires interest payments until maturity. The variable rate mortgage notes and construction loans require periodic payment of principal and interest. The 8.00% mortgage note due in 2033, requires interest payments initially then monthly principal and interest payments.
Unsecured Notes The unsecured notes mature on the following schedule:
Amount - ------------------------------------------------------ (In millions) 7.30%, due April 22, 1999 $ 90.0 8.73%, due October 15, 1999 15.0 7.125%, due March 13, 2000 15.0 7.55%, due April 22, 2000 35.0 7.50%, due May 5, 2000 139.0 7.43%, due September 9, 2000 30.0 5.43%, due October 15, 2000 5.0 7.66%, due May 5, 2001 135.0 5.67%, due May 5, 2001 152.0 - ------------------------------------------------------ Total unsecured notes at December 31, 1998 $616.0 ======================================================
Maturities of Long-Term Debt All of our long-term borrowings mature on the following schedule (includes sinking fund requirements):
Diversified Year BGE Businesses - ------------------------------------------------------ (In millions) 1999 $ 334.5 $200.2 2000 252.6 273.4 2001 195.2 362.6 2002 154.0 1.5 2003 284.3 8.9 Thereafter 1,584.4 23.6 - ------------------------------------------------------ Total long-term debt at December 31, 1998 $2,805.0 $870.2 ======================================================
At December 31, 1998, BGE had long-term loans totaling $255.0 million that mature after 2002 (including $110 million of medium-term notes discussed in this note under "BGE's Other Long-Term Debt") that lenders could potentially require us to repay early. Of this amount, $145.0 million could potentially be repaid in 1999, $60.0 million in 2002, and $50.0 million thereafter. We have the ability and intent to refinance such debt by issuing medium-term notes or by borrowing under our revolving credit agreements, if necessary.
Weighted-Average Interest Rates for Variable Rate Debt Our weighted-average interest rates for variable rate debt were:
Year Ended December 31, 1998 1997 - -------------------------------------------------------------------------------- BGE Floating rate series mortgage bonds 5.90% 6.11% Remarketed floating rate series mortgage bonds 5.70 5.75 Medium-term notes, Series D 5.74 5.78 Pollution control loan 3.48 3.63 Port facilities loan 3.61 3.71 Adjustable rate pollution control loan 3.75 3.90 Economic development loan 3.59 3.69 Variable rate pollution control loan 3.45 3.73 Diversified Businesses Loans under credit agreement 6.02 6.04 Mortgage and construction loans 8.17 8.10
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Note 8 Redeemable Preference Stock
Priority For the payment of dividends and in the event of liquidation of BGE, preference stock is ranked prior to common stock. All preference stock are ranked equally.
Redemptions in 1998 and 1999 During 1998, BGE redeemed all remaining shares of the following:
o the 7.50%, 1986 series, o the 6.75%, 1987 series, and o the 8.625%, 1990 series.
The redemptions were a combination of mandatory and optional sinking fund redemptions and early redemptions.
The remaining 70,000 shares of the 7.85%, 1991 series will be redeemed on July 1, 1999 under mandatory sinking fund provisions.
Note 9 Leases There are two types of leases--operating and capital. Capital leases qualify as sales or purchases of property and are reported in the Consolidated Balance Sheets. All other leases are operating leases and are reported in the Consolidated Statements of Income. We present information about our operating leases below.
Incoming Lease Rentals Some of our diversified businesses, as landlords, lease retail space to others. These operating leases expire over periods ranging from one to 20 years, and have options to renew. At December 31, 1998, our diversified businesses had property under operating leases with a net book value of $32.4 million. At December 31, 1998, tenants owed our diversified businesses future minimum rentals under operating leases as follows:
Year - -------------------------------------------------- (In millions) 1999 $ 3.4 2000 3.3 2001 3.1 2002 2.7 2003 2.7 Thereafter 24.3 - -------------------------------------------------- Total future minimum lease rentals $39.5 ==================================================
Outgoing Lease Payments We, as lessee, lease some facilities and equipment used in our businesses. The lease agreements expire on various dates and have various renewal options. We expense all lease payments associated with our regulated utility operations.
Lease expense was:
o $10.5 million in 1998, o $9.5 million in 1997, and o $11.6 million in 1996.
At December 31, 1998, we owed future minimum payments for long-term, noncancelable, operating leases as follows:
Year - ------------------------------------------------- (In millions) 1999 $ 6.7 2000 5.4 2001 4.1 2002 3.4 2003 2.2 Thereafter 5.5 - ------------------------------------------------- Total future minimum lease payments $27.3 =================================================
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Note 10 Commitments, Guarantees, and Contingencies
Commitments We have made substantial commitments in connection with our utility construction program for future years. In addition, our electric business has entered into two long-term contracts for the purchase of electric generating capacity and energy. The contracts expire in 2001 and 2013. We made payments under these contracts of:
o $70.7 million in 1998, o $65.6 million in 1997, and o $64.1 million in 1996.
At December 31, 1998, we estimate our future payments for capacity and energy that we are obligated to buy under these contracts to be:
Year - ------------------------------------------------------------ (In millions) 1999 $ 61.9 2000 63.1 2001 33.4 2002 12.3 2003 12.3 Thereafter 128.3 - ------------------------------------------------------------ Total estimated future payments for capacity and energy under long-term contracts $311.3 ============================================================
Some of our diversified businesses have committed to contribute additional capital and to make additional loans to some affiliates, joint ventures, and partnerships in which they have an interest. At December 31, 1998, the total amount of investment requirements committed to by our diversified businesses was $19.9 million.
In March 1998, our power marketing and trading business, Constellation Power Source, Inc. and Goldman, Sachs Capital Partners II L.P., an affiliate of Goldman, Sachs & Co., formed Orion Power Holdings, Inc. (Orion) to acquire electric generating plants in the United States and Canada. Constellation Power Source owns a minority interest in Orion, and BGE has committed to contribute up to $175 million in equity to Constellation Power Source to fund its investment in Orion.
BGE and BGE Home Products & Services have agreements to sell on an ongoing basis an undivided interest in a designated pool of customer receivables. Under the agreements, BGE can sell up to a total of $40 million, and BGE Home Products & Services can sell up to a total of $50 million. Under the terms of the agreements, the buyer of the receivables has limited recourse against BGE and has no recourse against BGE Home Products & Services. BGE and BGE Home Products & Services have recorded a reserve for credit losses. At December 31, 1998, BGE had sold $33.6 million and BGE Home Products & Services had sold $45.3 million of receivables under these agreements.
Guarantees BGE guarantees two-thirds of certain debt of Safe Harbor Water Power Corporation. The maximum amount of our guarantee is $23 million. At December 31, 1998, Safe Harbor Water Power Corporation had outstanding debt of $23.6 million, of which $15.7 million is guaranteed by BGE.
BGE has issued guarantees in an amount up to $162 million related to credit facilities and contractual performance of certain of its diversified subsidiaries. At December 31, 1998, letters of credit totaling $2.3 million were issued under one of the credit facilities.
At December 31, 1998, our diversified businesses had guaranteed outstanding loans and letters of credit of certain power projects and real estate projects totaling $59.7 million. Our diversified businesses also guarantee certain other borrowings of various power projects and real estate projects.
We assess the risk of material loss from these guarantees to be minimal.
Environmental Matters Clean Air The Clean Air Act of 1990 contains two titles designed to reduce emissions of sulfur dioxides and nitrogen oxides (NOx) from electric generating stations--Title IV and Title I.
Title IV addresses emissions of sulfur dioxides. Compliance is required in two phases:
o Phase I became effective January 1, 1995. We met the requirements of this phase by installing flue gas desulfurization system, switching fuels, and retiring some units.
o Phase II must be implemented by January 1, 2000. We expect to meet the compliance requirements through some combination of switching fuels and allowance trading.
Title I addresses emissions of NOx. The Maryland Department of the Environment (MDE) issued NOx regulations which took effect June 1, 1998. The MDE regulations require major NOx sources to reduce NOx emissions up to 65% by May, 1999. While we are already taking steps to control NOx emissions at our generating plants, we communicated to MDE that we could not install the required technology at our Brandon Shores plant in time to meet the MDE's May, 1999 deadline. On June 19, 1998, we filed a lawsuit against MDE in Baltimore challenging these regulations. On February 9, 1999, the Baltimore City Circuit Court ordered the MDE to reissue the regulations with a new compliance date, indicating it was impossible for utilities to meet the May, 1999 deadline. We do not anticipate that MDE will appeal the court's decision.
The EPA issued a final rule in September, 1998 that requires the reduction of NOx emissions up to 85% by 22 states (including Maryland and Pennsylvania). The 22 states must submit plans to the EPA by September 1999 showing how they will meet its new requirements.
Based on the MDE and EPA regulations, we currently estimate that the additional controls needed at our generating plants to meet the 65% NOx emission reduction requirements will cost approximately $126 million. Through December 31, 1998, we have spent approximately $21.5 million to meet the 65% reduction requirements. We cannot estimate the cost for the 85% reduction requirements at this time; however, these costs could be material.
In July 1997, the EPA published National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment. These standards may require increased controls at our fossil generating plants in the future. We cannot estimate the cost of these increased controls at this time because the states, including Maryland, still need to determine what reductions, if any, in pollutants will be necessary to meet the federal standards.
Waste Disposal The EPA and several state agencies have notified us that we are considered a potentially responsible party with respect to the cleanup of certain environmentally contaminated sites owned and operated by others. We cannot estimate the cleanup costs for all of these sites. We can, however, estimate that our current 15.42% share of the reasonably possible cleanup costs at one of these sites, Metal Bank of America (a metal reclaimer in Philadelphia), could be as much as $4.9 million higher than amounts we have recorded as a liability on our Consolidated Balance Sheets. This estimate is based on a Record of Decision issued by the EPA. The cleanup costs for some of the remaining sites could be significant, but we do not expect them to have a material effect on our financial position or results of operations.
Also, we are coordinating investigation of several sites where gas was manufactured in the past. The investigation of these sites includes reviewing possible actions to remove coal tar. In late December 1996, we signed a consent order with the MDE that requires us to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. We submitted the required remedial action plans and they have been approved by the MDE. Based on the remedial action plans, the costs we consider to be probable to remedy the contamination are estimated to total $47 million in nominal dollars (including inflation). We have recorded these costs as a liability on our Consolidated Balance Sheets and have deferred these costs, net of accumulated amortization and amounts we recovered from insurance companies, as a regulatory asset. We discuss this further in Note 4. Through December 31, 1998, we have spent approximately $32 million for remediation at this site.
We are also required by accounting rules to disclose additional costs we consider to be less likely than probable costs, but still "reasonably possible" of being incurred at these sites. Because of the results of studies at these sites, it is reasonably possible that these additional costs could exceed the amount we recognized by approximately $14 million in nominal dollars ($7 million in current dollars, plus the impact of inflation at 3.1% over a period of up to 36 years).
Nuclear Insurance If there were an accident or an extended outage at either unit of the Calvert Cliffs Nuclear Power Plant (Calvert Cliffs), it could have a substantial adverse financial effect on BGE. The primary contingencies that would result from an incident at Calvert Cliffs could include:
o physical damage to the plant, o recoverability of replacement power costs, and o our liability to third parties for property damage and bodily injury.
We have insurance policies that cover these contingencies, but the policies have certain exclusions. Furthermore, the costs that could result from a covered major accident or a covered extended outage at either of the Calvert Cliffs units could exceed our insurance coverage limits.
Insurance for Calvert Cliffs and Third Party Claims For physical damage to Calvert Cliffs, we have $2.75 billion of property insurance from an industry mutual insurance company. If an outage at either of the two units at Calvert Cliffs is caused by an insured physical damage loss and lasts more than 17 weeks, we have insurance coverage for replacement power costs up to $494.2 million per unit, provided by an industry mutual insurance company. This amount can be reduced by up to $98.8 million per unit if an outage at both units of the plant is caused by a single insured physical damage loss. If accidents at any insured plants cause a shortfall of funds at the industry mutual insurance company, all policyholders could be assessed, with our share being up to $23.2 million.
In addition we, as well as others, could be charged for a portion of any third party claims associated with a nuclear incident at any commercial nuclear power plant in the country. At the date of this report, the limit for third party claims from a nuclear incident is $9.71 billion under the provisions of the Price Anderson Act. If third party claims exceed $200 million (the amount of primary insurance), our share of the total liability for third party claims could be up to $176.2 million per incident. That amount would be payable at a rate of $20 million per year.
Insurance for Worker Radiation Claims As an operator of a commercial nuclear power plant in the United States, we are required to purchase insurance to cover radiation injury claims of certain nuclear workers. On January 1, 1998, a new insurance policy became effective for all operators requiring coverage for current operations. Waiving the right to make additional claims under the old policy was a condition for acceptance under the new policy. We describe both the old and new policies below.
o BGE nuclear worker claims reported on or after January 1, 1998 are covered by a new insurance policy with an annual industry aggregate limit of $200 million for radiation injury claims against all those insured by this policy.
o All nuclear worker claims reported prior to January 1, 1998 are still covered by the old insurance policies. Insureds under the old policies, with no current operations, are not required to purchase the new policy described above, and may still make claims against the old policies for the next nine years. If radiation injury claims under these old policies exceed the policy reserves, all policyholders could be assessed, with our share being up to $6.3 million.
If claims under these polices exceed the coverage limits, the provisions of the Price Anderson Act (discussed above) would apply.
Recoverability of Electric Fuel Costs By law, we are allowed to recover our cost of electric fuel as long as the Maryland PSC finds that, among other things, we have kept the productive capacity of our generating plants at a reasonable level. To do this, the Maryland PSC will perform an evaluation of each outage (other than regular maintenance outages) at our generating plants. The evaluation will determine if we used all reasonable and cost-effective maintenance and operating control procedures to try to prevent the outage.
The Maryland PSC, under the Generating Unit Performance Program, measures annually whether we have maintained the productive capacity of our generating plants at reasonable levels. To do this, the program uses a system-wide generating performance target and an individual performance target for each base load generating unit. In fuel rate hearings, actual generating performance adjusted for planned outages will be compared first to the system-wide target.
If that target is met, it should mean that the requirements of Maryland law have been met. If the system-wide target is not met, each unit's adjusted actual generating performance will be compared to its individual performance target to determine if the requirements of Maryland law have been met and, if not, to determine the basis for possibly imposing a penalty on BGE. Even if we meet these targets, parties to fuel rate hearings may still question whether we used all reasonable and cost-effective procedures to try to prevent an outage. If the Maryland PSC decides we were deficient in some way, the Maryland PSC may not allow us to recover the cost of replacement energy.
The two units at Calvert Cliffs use the cheapest fuel. As a result, the costs of replacement energy associated with outages at these units can be significant. We 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.
During 1989 through 1991 we had extended outages at Calvert Cliffs. These outages drove up fuel costs, and resulted in fuel rate proceedings before the Maryland PSC for several years. In these proceedings, the Maryland PSC considered whether any portion of the extra fuel costs should be charged to BGE instead of passed on to customers.
In December 1996, we settled the proceedings by agreeing not to bill our customers for $118 million of electric replacement energy costs associated with these outages. All costs associated with the outages in excess of $118 million have already been collected from customers through the fuel rate. In 1990, we wrote off $35 million of these costs. In 1996, we wrote off the remaining $83 million plus $5.6 million of related financing charges. The 1996 write-offs, together, reduced after-tax earnings by $57.6 million.
Also in 1996, we wrote off $6.8 million of fuel costs related to earlier outages that were disallowed by the Maryland PSC. This write-off reduced 1996 after-tax earnings by $4.5 million.
We have reported all of the 1996 write-offs as "Disallowed replacement energy costs" in our Consolidated Statements of Income.
California Power Purchase Agreements Constellation Power, Inc. and subsidiaries and Constellation Investments, Inc. (whose power projects are managed by Constellation Power) have $310.6 million invested in 15 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. In 1998, earnings from these projects were $41.3 million, or $.28 per share.
Under these agreements, the projects supply electricity to utility companies at:
o a fixed rate for capacity and energy for the first 10 years of the agreements, and o a fixed rate for capacity plus a variable rate for energy based on the utilities' avoided cost for the remaining term of the agreements.
Generally, a "capacity rate" is paid to a power plant for its availability to supply electricity, and an "energy rate" is paid for the electricity actually generated. "Avoided cost" generally is the cost of a utility's cheapest next-available source of generation to service the demands on its system.
We use the term transition period to describe the time frame when the 10-year periods for fixed energy rates expire for these 15 power generation projects and they begin supplying electricity at variable rates. The transition period for some of the projects began in 1996 and will continue for the remaining projects through 2000. At the date of this report, eight projects had already transitioned to variable rates and seven other projects will transition in 1999 and 2000.
The projects that have already transitioned to variable rates have had lower revenues under variable rates than they did under fixed rates. However, we have not yet experienced total lower earnings from the California projects because the combined revenues from the remaining projects, which continue to supply electricity at fixed rates, are high enough to offset the lower revenues from the variable-rate projects. When the remaining projects transition to variable rates, we expect the revenues from those projects also to be lower than they are under fixed rates.
Our power projects business is pursuing alternatives for some of these power generation projects including:
o repowering the projects to reduce operating costs, o changing fuels to reduce operating costs, o renegotiating the power purchase agreements to improve the terms, o restructuring financings to improve the financing terms, and o selling its ownership interests in the projects.
The California projects that make the highest revenues will transition to variable rates in 1999 and 2000. The projects which transition in 1999 contributed $10.7 million, or $.07 per share to 1998 earnings, while those changing over in 2000 contributed $24.0 million, or $.16 per share to 1998 earnings. We expect earnings to ultimately decrease by similar amounts beginning in 1999 as these projects transition.
Constellation Real Estate Most of Constellation Real Estate Group's (CREG) real estate projects are in the Baltimore-Washington corridor. The area has had a surplus of available land in recent years and as a result these projects have been economically hurt.
CREG's real estate projects have continued to incur carrying costs and depreciation over the years. Additionally, CREG has been charging interest payments to expense rather than capitalizing them for some undeveloped land where development activities have stopped. These carrying costs, depreciation, and interest expenses have decreased earnings and are expected to continue to do so.
Cash flow from real estate operations has not been enough to make the monthly loan payments on some of these projects. Cash shortfalls have been covered by cash obtained from the cash flows of, or additional borrowings by, other diversified subsidiaries.
We consider market demand, interest rates, the availability of financing, and the strength of the economy in general when making decisions about our real estate projects. If we were to decide to sell our real estate projects, we could have write-downs. In addition, if we were to sell our remaining real estate projects in the current market, we would have losses which could be material, although the amount of the losses is hard to predict.
Management's current real estate strategy is to hold each real estate project until we can realize a reasonable value for it, except for Church Street Station which we intend to sell as discussed in Note 3. Management evaluates strategies for all its businesses, including real estate, on an ongoing basis. We anticipate that competing demands for our financial resources and changes in the utility industry will cause us to evaluate thoroughly all diversified business strategies on a regular basis so we use capital and other resources in a manner that is most beneficial.
It may be helpful for you to understand when we are required, by accounting rules, to write down the value of a real estate project to market value. A write-down is required in either of two cases. The first is if we change our intent about a project from an intent to hold to an intent to sell and the market value of that project is below book value. The second is if the expected future cash flow from the project is less than the investment in the project. We discuss our real estate projects and investments further in Note 3.
Year 2000 Project We have not experienced any significant year 2000 problems to date and we do not expect any significant problems to impair our operations as we transition to the new century. However, due to the magnitude and complexity of the year 2000 issue, even the most conscientious efforts cannot guarantee that every problem will be found and corrected prior to January 1, 2000. We discuss our year 2000 project further in the "Year 2000 Readiness Disclosure" section of Management's Discussion and Analysis.
- --------------------------------------------------------------------------------
Note 11 Fair Value of Financial Instruments The fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Significant differences can occur between the fair value and carrying amount of financial instruments that are recorded at historical amounts. We used the following methods and assumptions in estimating fair value disclosures for financial instruments.
o Cash and cash equivalents, net accounts receivable, other current assets, certain current liabilities, short-term borrowings, current portions of long-term debt and preference stock and certain deferred credits and other liabilities: The amounts reported in the Consolidated Balance Sheets approximate fair value. o Investments and other assets where it was practicable to estimate fair value: The fair value is based on quoted market prices where available. o Fixed-rate long-term debt, and redeemable preference stock: The fair value is based on quoted market prices where available or by discounting remaining cash flows at current market rates. The carrying amount of variable-rate long-term debt approximates fair value.
We show the carrying amounts and fair values of financial instruments included in our Consolidated Balance Sheets in the following table.
At December 31, 1998 1997 - -------------------------------------------------------------------------- Carrying Fair Carrying Fair Amount Value Amount Value - -------------------------------------------------------------------------- (In millions) Investments and other assets for which it is: Practicable to estimate fair value $ 213.0 $ 213.0 $ 197.4 $ 198.8 Not practicable to estimate fair value 56.5 N/A 57.5 N/A Fixed-rate long-term debt 2,954.7 3,076.6 2,637.5 2,718.4 Redeemable preference stock 7.0 7.2 113.0 116.5
It was not practicable to estimate the fair value of investments held by our diversified businesses in:
o several financial partnerships that invest in nonpublic debt and equity securities, o several partnerships that own solar powered energy production facilities, and o a company involved in developing international power projects with a carrying amount of $3.7 million at December 31, 1998 and $3.0 million at December 31, 1997.
This is because the timing and amount of cash flows from these investments are difficult to predict. We report these investments at their original cost in our Consolidated Balance Sheets.
The investments in financial partnerships totaled $41.9 million at December 31, 1998 and $43.6 million at December 31, 1997, representing ownership interests up to 10%. The total assets of all of these partnerships totaled $5.8 billion at December 31, 1997 (which is the latest information available).
The investments in solar powered energy production facility partnerships totaled $10.9 million at December 31, 1998 and 1997, representing ownership interests up to 13%. The total assets of all of these partnerships totaled $41.5 million at December 31, 1997 (which is the latest information available).
Guarantees It was not practicable to determine the fair value of certain loan guarantees of BGE and its diversified businesses. BGE guaranteed outstanding debt and other obligations totaling $18.0 million at December 31, 1998 and $20 million at December 31, 1997. Our diversified businesses guaranteed outstanding debt totaling $59.7 million at December 31, 1998 and $43 million at December 31, 1997. We do not anticipate that we will need to fund these guarantees.
- --------------------------------------------------------------------------------
Note 12 Quarterly Financial Data (Unaudited) Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair presentation. Our utility business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.
1998 QUARTERLY DATA
Our first quarter results include a $12.0 million after-tax write-down of a real estate project (see Note 3).
Our second quarter results include a $31.9 million after-tax write-down of a real estate project (see Note 3).
Our fourth quarter results include:
o a $37.5 million after-tax write-off of merger costs (see Note 2), and o a $2.1 million after-tax write-down of a real estate project (see Note 3).
THE SUM OF THE QUARTERLY EARNINGS PER SHARE AMOUNTS MAY NOT EQUAL THE TOTAL FOR THE YEAR DUE TO THE EFFECTS OF ROUNDING.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item with respect to directors is set forth on pages 19 through 22 under "Election of BGE Directors" in the Proxy Statement and is incorporated herein by reference.
The information required by this item with respect to executive officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set forth in Item 4 of Part I of this Form 10-K under "Executive Officers of the Registrant," except that information with regard to a late filing of a Section 16(a) report by an executive officer is set forth on page 22 under "Section 16(a) Beneficial Ownership Reporting Compliance" in the Proxy Statement and is incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth on pages 21 and 22 under "Directors' Compensation" on pages 24 through 28 under "Executive Compensation," and "Common Stock Performance Graph" and on pages 29 through 31 under "Report of Committee on Management on Executive Compensation" in the Proxy Statement and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item regarding security ownership of management is set forth on page 23 under "Security Ownership" in the Proxy Statement and is incorporated herein by reference.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
NAME OF TITLE AMOUNT OF PERCENT BENEFICIAL OF BENEFICIAL OF OWNER CLASS OWNERSHIP CLASS - ------------------------ -------- ------------------- -------- Capital Research and Common 10,225,000 shares 6.9% Management Company Stock 333 South Hope Street Los Angeles, CA 90071 ............
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is set forth on page 22 under "Certain Relationships and Transactions" in the Proxy Statement and is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this Report:
1. Financial Statements:
Report of Independent Accountants dated January 15, 1999 of PricewaterhouseCoopers LLP Consolidated Statements of Income for three years ended December 31, 1998 Consolidated Statements of Comprehensive Income for three years ended December 31, 1998 Consolidated Balance Sheets at December 31, 1998 and December 31, 1997 Consolidated Statements of Cash Flows for three years ended December 31, Consolidated Statements of Common Shareholders' Equity for three years ended December 31, 1998 Consolidated Statements of Capitalization at December 31, 1998 and December 31, 1997 Consolidated Statements of Income Taxes for three years ended December 31, Notes to Consolidated Financial Statements
2. Financial Statement Schedules: Schedule II -- Valuation and Qualifying Accounts Schedules other than Schedule II are omitted as not applicable or not required.
3. Exhibits Required by Item 601 of Regulation S-K.
EXHIBIT NUMBER - -------------------------------------------------------------------------------- *2 -- Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 in Form S-4 dated March 3, 1999, File No. 33-64799.)
*3(a) -- Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated November 14, 1996, File No. 1-1910.)
*3(b) -- By-Laws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 in Form 10-Q dated November 13, 1998, File No. 1-1910.)
*4(a) -- Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910.); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:
*4(b) -- Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
*4(c) -- Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures (Designated as Exhibit 4(d) in Form S-3 dated May 28, 1998, File No. 333-53767).
*4(d) -- Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures (Designated as Exhibit 4(e) in Form S-3 dated May 28, 1998, File No. 333-53767).
*4(e) -- Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in Form S-3 dated May 28, 1998, File No. 333-53767).
*4(f) -- Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in Form S-3 dated May 28, 1998, File No. 333-53767).
*4(g) -- Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) in Form S-3 dated May 28, 1998, File No. 333-53767).
*10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(a) in Form 10-Q dated November 14, 1996, File No. 1-1910.)
*10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
*10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan. (Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
*10(d) -- Baltimore Gas and Electric Company Nonqualified Deferred Compensation Plan, as amended and restated. (Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended December 31, 1996, File No. 1-1910.)
*10(e) -- Amended and Restated Baltimore and Gas and Electric Company Deferred Compensation Plan for Non-Employee Directors. (Designated as Exhibit No. 10 in Form 10-Q dated November 13, 1997, File No. 1-1910.)
*10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) (Terminated effective August 1, 1997.)
10(g) -- Summary of severance arrangement for a named executive officer.
*10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore Gas and Electric Company and Citibank, N.A. (Designated as Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
*10(i) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
*10(j) -- Severance Agreements between Baltimore Gas and Electric Company and eight key employees. (Designated as Exhibit No. 10(k) to the Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-1910.)
10(k) -- Form of amendment to Severance Agreements between Baltimore Gas and Electric Company and eight key employees.
10(l) -- Constellation Enterprises, Inc. Deferred Compensation Plan for Non-Employee Directors.
10(m) -- Summary of enhanced retirement benefits for a named executive officer.
*10(n) -- Grantor Trust Agreement dated as of June 1, 1996 between Baltimore Gas and Electric Company and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(b) in Form 10-Q dated August 13, 1996, File No. 1-1910.)
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.
21 -- Subsidiaries of the Registrant.
23 -- Consent of PricewaterhouseCoopers LLP, Independent Accountants.
27 -- Financial Data Schedule.
*99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No. 28(a) to the Annual Report on Form 10-K for the year ended December 31, 1988, File No. 1-1910.)
- ---------- * Incorporated by Reference.
(b) Reports on Form 8-K:
None.
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
- ---------- (A) Represents principally net amounts charged off as uncollectible.
(B) Represents net unrealized (gains)/losses (credited)/charged to accumulated other comprehensive income.
(C) Represents net unrealized gains credited to accumulated depreciation.
(D) Represents removal of a reserve based on actual disallowance of replacement energy costs.
(E) Represents removal of a reserve associated with an energy project of a subsidiary that was abandoned.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Baltimore Gas and Electric Company, 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: March 18, 1999 By /s/ C. H. POINDEXTER ------------------------------------- C. H. POINDEXTER CHAIRMAN OF THE BOARD, PRESIDENT, AND CHIEF EXECUTIVE OFFICER
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.
EXHIBIT INDEX
*4(b) -- Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
*4(c) -- Form of Subordinated Indenture between the Company and The Bank of New York, as Trustee in connection with the issuance of the Junior Subordinated Debentures (Designated as Exhibit 4(d) in Form S-3 dated May 28, 1998, File No. 333-53767).
*4(d) -- Form of Supplemental Indenture between the Company and The Bank of New York, as Trustee in connection with the issuances of the Junior Subordinated Debentures (Designated as Exhibit 4(e) in Form S-3 dated May 28, 1998, File No. 333-53767).
*4(e) -- Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in Form S-3 dated May 28, 1998, File No. 333-53767).
*4(f) -- Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in Form S-3 dated May 28, 1998, File No. 333-53767).
*4(g) -- Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) in Form S-3 dated May 28, 1998, File No. 333-53767).
*10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(a) in Form 10-Q dated November 14, 1996, File No. 1-1910.)
*10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
*10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan. (Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
*10(d) -- Baltimore Gas and Electric Company Nonqualified Deferred Compensation Plan, as amended and restated. (Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended December 31, 1996, File No. 1-1910.)
*10(e) -- Amended and Restated Baltimore and Gas and Electric Company Deferred Compensation Plan for Non-Employee Directors. (Designated as Exhibit No. 10 in Form 10-Q dated November 13, 1997, File No. 1-1910.)
*10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) (Terminated effective August 1, 1997.)
10(g) -- Summary of severance arrangement for a named executive officer.
*10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore Gas and Electric Company and Citibank, N.A. (Designated as Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
*10(i) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
*10(j) -- Severance Agreements between Baltimore Gas and Electric Company and eight key employees. (Designated as Exhibit No. 10(k) to the Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-1910.)
10(k) -- Form of amendment to Severance Agreements between Baltimore Gas and Electric Company and eight key employees.
10(l) -- Constellation Enterprises, Inc. Deferred Compensation Plan for Non-Employee Directors.
10(m) -- Summary of enhanced retirement benefits for a named executive officer.
*10(n) -- Grantor Trust Agreement dated as of June 1, 1996 between Baltimore Gas and Electric Company and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(b) in Form 10-Q dated August 13, 1996, File No. 1-1910.)
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.
21 -- Subsidiaries of the Registrant.
23 -- Consent of PricewaterhouseCoopers LLP, Independent Accountants.
27 -- Financial Data Schedule.
*99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No. 28(a) to the Annual Report on Form 10-K for the year ended December 31, 1988, File No. 1-1910.)
- ---------- * Incorporated by Reference.