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Constellation Energy Group 10-Q 2005 Documents found in this filing:QuickLinks -- Click here to rapidly navigate through this document UNITED STATES FORM 10-Q QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF For The Quarterly Period Ended March 31, 2005
MARYLAND 750 E. PRATT STREET, BALTIMORE,
MARYLAND 21202 410-783-2800 (Registrants' telephone number, including area code) NOT APPLICABLE (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) have been subject to such filing requirements for the past 90 days. Yes ý No o Indicate by check mark whether Constellation Energy Group, Inc. is an accelerated filer Yes ý No o Indicate by check mark whether Baltimore Gas and Electric Company is an accelerated filer Yes o No ý Common Stock, without par value 177,529,344 shares outstanding of Baltimore Gas and Electric Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form in the reduced disclosure format.
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Constellation Energy Group, Inc. and Subsidiaries
Constellation Energy Group, Inc. and Subsidiaries
See Notes to Consolidated Financial Statements. 3 CONSOLIDATED BALANCE SHEETS Constellation Energy Group, Inc. and Subsidiaries
* Unaudited See Notes to Consolidated Financial Statements. 4 CONSOLIDATED BALANCE SHEETS Constellation Energy Group, Inc. and Subsidiaries
* Unaudited See Notes to Consolidated Financial Statements. 5 CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Constellation Energy Group, Inc. and Subsidiaries
See Notes to Consolidated Financial Statements. 6 CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Baltimore Gas and Electric Company and Subsidiaries
See Notes to Consolidated Financial Statements. 7 CONSOLIDATED BALANCE SHEETS Baltimore Gas and Electric Company and Subsidiaries
* Unaudited See Notes to Consolidated Financial Statements. 8 CONSOLIDATED BALANCE SHEETS Baltimore Gas and Electric Company and Subsidiaries
* Unaudited See Notes to Consolidated Financial Statements. 9 CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Baltimore Gas and Electric Company and Subsidiaries
See Notes to Consolidated Financial Statements. 10 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Various factors can have a significant impact on our results for interim periods. This means that the results for this quarter are not necessarily indicative of future quarters or full year results given the seasonality of our business. Our interim financial statements on the previous pages reflect all adjustments that management believes are necessary for the fair presentation of the financial position and results of operations for the interim periods presented. These adjustments are of a normal recurring nature. Basis of Presentation This Quarterly Report on Form 10-Q is a combined report of Constellation Energy Group, Inc. (Constellation Energy) and Baltimore Gas and Electric Company (BGE). References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "regulated business(es)" are to BGE. Variable Interest Entities We have a significant interest in the following variable interest entities (VIE) for which we are not the primary beneficiary:
We discuss the nature of our involvement with the power contract monetization VIEs in detail below under Customer Contract Restructuring. The following is summary information available as of March 31, 2005 about the VIEs in which we have a significant interest, but are not the primary beneficiary:
The maximum exposure to loss represents the loss that we would incur in the unlikely event that our interests in all of these entities were to become worthless and we were required to fund the full amount of all guarantees associated with these entities. Our maximum exposure to loss as of March 31, 2005 consists of the following:
We assess the risk of a loss equal to our maximum exposure to be remote.
In March 2005, our merchant energy business closed a transaction in which we assumed from a counterparty two power sales contracts with existing VIEs. Under the contracts, we sell power to the VIEs which, in turn, sell that power to an electric distribution utility through 2013. The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. The difference between the contract prices at which the VIEs purchase and sell power is used to service the debt of the VIEs, which totaled $721.0 million at March 31, 2005. The market price for power at closing of our transaction was higher than the contract price under the existing power sales contracts we assumed. Therefore, we 11 received compensation totaling $308.5 million, equal to the net present value of the difference between the contract price under the power sales contracts and the market price of power at closing. We used a portion of this amount to settle $68.5 million of existing derivative liabilities with the same counterparty, and we also loaned $82.8 million to the holder of the equity in the VIEs. As a result, we received net cash at closing of $157.2 million. We also guaranteed our subsidiaries' performance under the power sales contracts. The table below summarizes the transaction and the net cash received at closing:
We recorded this transaction in our financial statements at closing as follows:
We recorded the gross compensation we received to assume the power sales contracts as a financing cash inflow because it constitutes a prepayment for a portion of the market price of power which we will sell to the VIEs over the term of the contracts and does not represent a cash inflow from current period operating activities. If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could transfer its equity interests to us in lieu of repaying the loan. In this event, we would have the right to seek recovery of our losses from the electric distribution utility. Basic earnings per common share (EPS) is computed by dividing earnings applicable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Our dilutive common stock equivalent shares consist of stock options and stock unit awards totaling 1.8 million for the quarter ended March 31, 2005 and 1.1 million for the quarter ended March 31, 2004. Stock options to purchase approximately 0.7 million shares during the first quarter of 2005 were not dilutive and were excluded from the computation of diluted EPS for that period. There were no stock options excluded from the computation of diluted EPS for the quarter ended March 31, 2004. Stock-Based Compensation Under our long-term incentive plans, we granted stock options, performance and service-based restricted stock, performance-based units, and equity to officers, key employees, and members of the Board of Directors. As permitted by Statement of Financial Accounting Standards (SFAS) No. 123, Accounting for Stock-Based Compensation, we measure our stock-based compensation using the intrinsic value method in accordance with Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, and related interpretations. We discuss these plans and accounting further in Note 14 of our 2004 Annual Report on Form 10-K. 12 The following table illustrates the effect on net income and earnings per share had we applied the fair value recognition provisions of SFAS No. 123 to all outstanding stock options and stock awards in each period.
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment, which changed the accounting for stock-based compensation to require companies to expense stock options and other equity awards based on their grant-date fair values. We discuss SFAS No. 123R in more detail in the Accounting Standards Issued section on page 21.
SFAS No. 143, Accounting for Asset Retirement Obligations, provides the accounting requirements for recognizing an estimated liability for legal obligations associated with the retirement of tangible long-lived assets. We measure the liability at fair value when incurred and capitalize a corresponding amount as part of the book value of the related long-lived assets. The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the asset retirement obligations is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period to "Accretion of asset retirement obligations" in our Consolidated Statements of Income until the settlement of the liability. We record a gain or loss when the liability is settled after retirement. The change in our "Asset retirement obligations" liability during 2005 was as follows:
We incurred costs related to workforce reduction efforts initiated in 2004. We discuss these costs in more detail in Note 2 of our 2004 Annual Report on Form 10-K. The following table summarizes the status of the involuntary severance liability:
*Other represents adjustments to estimated severance liability based on additional information. In March 2005, we reached an agreement in principle to sell to affiliates of The Southern Company (Southern) our Oleander generating facility, a four-unit peaking plant located in Florida, for approximately $206 million, subject to closing adjustments. We executed a purchase and sale agreement in April 2005, and we expect the sale to close late in the second quarter or early in the third quarter of 2005. We classified Oleander as held for sale and performed an impairment test under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, as of March 31, 2005. The impairment test indicated that the carrying value of the plant was higher than its fair value less costs to sell, and therefore we recorded an impairment charge of $4.8 million pre-tax as part of discontinued operations. 13 Presented in the table below are certain amounts related to Oleander that are included in "Income from discontinued operations" in our Consolidated Statements of Income.
Presented in the table below are the components of the assets and liabilities held for sale which are included in our merchant energy business segment:
In April 2005, we acquired Cogenex Corporation from Alliant Energy Corporation. Cogenex is a North American energy services firm providing consulting and technology solutions to industrial, institutional and government customers. We acquired 100% ownership of Cogenex for approximately $36.4 million. We acquired cash of $14.4 million as part of the purchase.
Our reportable operating segments are—Merchant Energy, Regulated Electric, and Regulated Gas:
Our remaining nonregulated businesses:
In addition, we own several investments that we do not consider to be core operations. These include financial investments, real estate projects, and interests in a Panamanian distribution facility and in a fund that holds interests in two South American energy projects. Our Merchant Energy, Regulated Electric, and Regulated Gas reportable segments are strategic businesses based principally upon regulations, products, and services that require different technology and marketing strategies. 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 in the table on the next page. 14
We show the components of net periodic pension benefit cost in the following table:
(1) Net periodic pension benefit cost excludes a reduction in termination benefits of $0.4 million in 2005. BGE's portion of our net periodic pension benefit cost was $5.1 million in 2005 and $2.0 million in 2004. We show the components of net periodic postretirement benefit cost in the following table:
(1) BGE's portion of our net periodic postretirement benefit cost was $5.8 million in 2005 and $6.8 million in 2004. 15 Our non-qualified pension plans and our postretirement benefit programs are not funded, however we have trust assets securing certain executive pension benefits. We estimate that we will incur approximately $2.9 million in pension benefit payments for our non-qualified pension plans and approximately $29.4 million for retiree health and life insurance benefit payments during 2005. We contributed an additional $50 million to our qualified pension plans in March 2005, even though there was no IRS required minimum contribution in 2005. During the first quarter of 2005, we entered into a new five-year credit facility totaling $1.5 billion. This new facility replaced two facilities totaling $1,087.5 million—a $640.0 million facility that would have expired in June 2005 and a $447.5 million facility that would have expired in June 2006. Constellation Energy also has an existing $800.0 million revolving credit facility expiring in June 2007 and a $300.0 million facility expiring in June 2009. We use these facilities to ensure adequate liquidity to support our operations. We can borrow directly from the banks or use the facilities to allow the issuance of commercial paper. Additionally, we use the facilities to support letters of credit primarily for our merchant energy business. These revolving credit facilities allow the issuance of letters of credit up to approximately $2.6 billion. In addition, BGE maintains $200.0 million in credit facilities. At March 31, 2005, letters of credit that totaled $859.5 million were issued under our facilities. Additionally, under our employee benefit plans and shareholder investment plans we issued $26.3 million of common stock during the quarter ended March 31, 2005. We have investments in facilities that manufacture solid synthetic fuel produced from coal as defined under Section 29 of the Internal Revenue Code for which we claim tax credits on our Federal income tax return. We recognize the tax benefit of these credits in our Consolidated Statements of Income when we believe it is highly probable that the credits will be sustained. As of March 31, 2005, we have recognized cumulative tax benefits associated with Section 29 credits of $225.8 million, of which $24.6 million was recognized during the quarter ended March 31, 2005. Section 29 provides for a phase-out of the tax credit if average annual wellhead oil prices increase above certain levels. Each year, we are required to compare average annual wellhead oil prices per barrel as determined by the Internal Revenue Service (IRS) (reference price) to an inflation adjusted oil price for the year, also determined by the IRS. The reference price is determined based on wellhead prices for all domestic oil production as published by the Energy Information Administration and has historically been $3 to $4 per barrel lower than the NYMEX price for light, sweet crude oil. For 2005, we estimate the credit reduction would begin if the reference price exceeds approximately $52 per barrel and would be fully phased out if the reference price exceeds approximately $66 per barrel. We currently believe that the 2005 reference price will not trigger a phase-out of the synthetic fuel tax credits in 2005 and, accordingly, we have recognized the full tax benefit of these credits in our Consolidated Statements of Income for the quarter ended March 31, 2005. Although we currently believe the 2005 reference price will not trigger a phase-out of synthetic fuel tax credits, we actively monitor and manage this exposure as part of our ongoing hedging activities. The objective of these activities is to reduce the potential losses we could incur in 2005 should the reference price exceed $52 per barrel. While we believe the production and sale of synthetic fuel from all of our synthetic fuel facilities meet the conditions to qualify for tax credits under Section 29 of the Internal Revenue Code, we cannot predict the timing or outcome of any future challenge by the IRS, legislative or regulatory action, oil prices, the effectiveness of our hedging program, or the ultimate impact of such events on the Section 29 credits that we have claimed to date or expect to claim in the future, but the impact could be material to our financial results. Our recognition of Section 29 credits reduced our effective tax rate as detailed in the table below. Total income taxes are different from the amount that would be computed by applying the statutory Federal income tax rate of 35% to book income before income taxes as follows:
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We have made substantial commitments in connection with our merchant energy, regulated electric and gas, and other nonregulated businesses. These commitments relate to:
Our merchant energy business has committed to long-term service agreements and other purchase commitments for our plants. Our regulated businesses enter into various long-term contracts for the procurement of electricity and for the procurement, transportation, and storage of gas. Our other nonregulated businesses have committed to gas purchases, as well as to contribute additional capital for construction programs and joint ventures in which they have an interest. We have also committed to long-term service agreements and other obligations related to our information technology systems. At March 31, 2005, the total amount of commitments was $5,216.2 million. These commitments are primarily related to our merchant energy business.
We enter into long-term power sales contracts in connection with our load-serving activities. We also enter into long-term power sales contracts associated with certain of our power plants. Our load-serving power sales contracts extend for terms through 2013 and provide for the sale of full requirements energy to electricity distribution utilities and certain retail customers. Our power sales contracts associated with our power plants extend for terms into 2014 and provide for the sale of all or a portion of the actual output of certain of our power plants. All long-term contracts were executed at pricing that approximated market rates, including profit margin, at the time of execution. The terms of our guarantees are as follows:
At March 31, 2005, we had a total of $7,505.7 million in guarantees outstanding related to loans, credit facilities, and contractual performance of certain of our subsidiaries as described below. These guarantees do not represent our incremental obligations, but rather represent parental guarantees of existing subsidiary obligations, and we do not expect to fund the full amount under these guarantees.
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The total fair value of the obligations for our guarantees recorded in our Consolidated Balance Sheets was $967.4 million and not the $7.5 billion of total guarantees. We assess the risk of loss from these guarantees to be minimal. Solid and Hazardous Waste The Environmental Protection Agency (EPA) and several state agencies have notified us that we are considered a potentially responsible party with respect to the clean-up of certain environmentally contaminated sites. We cannot estimate the final clean-up costs for all of these sites, but the costs and current status of each site is described in more detail below. Metal Bank In 1997, the EPA, under the Comprehensive Environmental Response, Compensation and Liability Act ("Superfund"), issued a Record of Decision (ROD) for the proposed clean-up at the Metal Bank of America site, a metal reclaimer in Philadelphia. We had previously recorded a liability in our Consolidated Balance Sheets for BGE's 15.47% share of probable clean-up costs. Based on current settlement negotiations among the EPA and the potentially responsible parties involved at the site, we do not believe we will incur clean-up costs in excess of the amount recorded as a liability. The EPA and the potentially responsible parties, including BGE, are currently pursuing claims against Metal Bank of America for an equitable share of expected site remediation costs. 68th Street Dump In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List ("NPL"), which is its list of sites targeted for clean-up and enforcement, and sent a general notice letter to BGE and 19 other parties identifying them as potentially liable parties at the site. In March 2004, we and other potentially responsible parties formed the 68th Street Coalition, which has entered into consent order negotiations with the EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. While negotiations under this program are ongoing, the 68th Street Dump will not be placed on the NPL. At this stage, it is not possible to predict the outcome of those discussions or our share of the liability. However, the costs could have a material effect on our financial results. Kane and Lombard The EPA issued its ROD for the Kane and Lombard Drum site located in Baltimore, Maryland on September 30, 2003. The ROD specifies the clean-up plan for the site, consisting of enhanced reductive dechlorination, a soil management plan, and institutional controls. In July 2004, the EPA issued a Special Notice/Demand Letter to BGE and three other potentially responsible parties regarding implementation of the remedy. In response, the potentially responsible parties have proposed negotiations with the EPA regarding the implementation. The total clean-up costs are estimated to be approximately $10 million. We estimate our current share of site-related costs to be 11.1% of the total. In December 2002, we recorded a liability in our Consolidated Balance Sheets for our share of the clean-up costs that we believe is probable. Our final share of the $10 million has not been determined and it may vary from the current estimate. Spring Gardens In December 1996, BGE signed a consent order with the Maryland Department of the Environment that requires it to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland. The Spring Gardens site was once used to manufacture gas from coal and oil. Based on the remedial action plans, BGE estimates its probable clean-up costs will total $47 million. BGE has recorded these costs as a liability in its Consolidated Balance Sheets and has deferred these costs, net of accumulated amortization and amounts it recovered from insurance companies, as a regulatory asset. Based on the results of studies at this site, it is reasonably possible that additional costs could exceed the amount BGE has recognized by approximately $14 million. Through March 31, 2005, BGE has spent approximately $40 million for remediation at this site. BGE also has investigated other small sites where gas was manufactured in the past. We do not expect the clean-up costs of the remaining smaller sites to have a material effect on our financial results. 18 Western Power Markets James M. Millar v. Allegheny Energy Supply, Constellation Power Source, Inc., High Desert Power Project, LLC, et al— On December 19, 2003, plaintiffs filed an amended complaint in Superior Court of California, County of San Francisco, naming for the first time, Constellation Power Source, Inc., renamed Constellation Energy Commodities Group (CCG), and High Desert Power Project, LLC (High Desert), two of our subsidiaries, as additional defendants. The complaint is a putative class action on behalf of California electricity consumers and alleges that the defendant power suppliers, including CCG and High Desert, violated California's Unfair Competition Law in connection with certain long-term power contracts that the defendants negotiated with the California Department of Water Resources in 2001 and 2002. Notwithstanding the amended long-term power contracts and the releases and settlement agreements negotiated at the time of such amendments, the plaintiff seeks to have the Court certify the case as a class action and to order the repayment of any monies that were acquired by the defendants under the long-term contracts or the amended long-term contracts by means of unfair competition in violation of California law We believe that we have meritorious defenses to this action and intend to defend against it vigorously. However, we cannot predict the timing, or outcome, of this case, or its possible effect on our results. City of Tacoma v. AEP, et al.,—The City of Tacoma, on June 7, 2004, in the U.S. District Court, Western District of Washington, filed a complaint against over 60 companies, including CCG. The complaint alleges that the defendants engaged in manipulation of electricity markets resulting in prices for power in the western power markets that were substantially above what market prices would have been in the absence of the alleged unlawful contracts, combinations and conspiracy in violation of Section 1 of the Sherman Act. The complaint further alleges that the total amount of damages is unknown, but is estimated to exceed $175 million. On February 11, 2005, the Court granted the defendants' motion to dismiss the action based on the Court's lack of jurisdiction over the claims in question. The plaintiff has appealed the dismissal of the action to the Ninth Circuit Court of Appeals. We believe that we have meritorious defenses to this action and intend to defend against it vigorously. However, we cannot predict the timing, or outcome, of this case, or its possible effect on our financial results. Mercury Beginning in September 2002, BGE, Constellation Energy, and several other defendants have been involved in numerous actions filed in the Circuit Court for Baltimore City, Maryland alleging mercury poisoning from several sources, including coal plants formerly owned by BGE. The plants are now owned by a subsidiary of Constellation Energy. In addition to BGE and Constellation Energy, approximately 11 other defendants, consisting of pharmaceutical companies, manufacturers of vaccines and manufacturers of Thimerosal have been sued. Approximately 70 cases have been filed to date, with each case seeking $90 million in damages from the group of defendants. In a ruling applicable to all but several of the cases, the Circuit Court for Baltimore City dismissed with prejudice all claims against BGE and Constellation Energy and entered into a stay of the proceedings as they relate to other defendants. Plaintiffs may attempt to pursue appeals of the rulings in favor of BGE and Constellation Energy once the cases are finally concluded as to all defendants. We believe that we have meritorious defenses and intend to defend the actions vigorously. However, we cannot predict the timing, or outcome, of these cases, or their possible effect on our, or BGE's, financial results. Employment Discrimination Miller, et. al v. Baltimore Gas and Electric Company, et al.—This action was filed on September 20, 2000 in the U.S. District Court for the District of Maryland. Besides BGE, Constellation Energy, Constellation Nuclear Power Plants, Inc. and Calvert Cliffs Nuclear Power Plant, Inc. are also named defendants. The action seeks class certification for approximately 150 past and present employees and alleges racial discrimination at Calvert Cliffs Nuclear Power Plant. The parties have reached a settlement which requires Court approval. Under the settlement, Calvert Cliffs Nuclear Power Plant, Inc. will modify certain employment practices and we have agreed to pay a settlement amount that is not material to our financial results. Asbestos Since 1993, BGE has been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE knew of and exposed individuals to an asbestos hazard. The actions relate to two types of claims. 19 The first type is direct claims by individuals exposed to asbestos. BGE is involved in these claims with approximately 70 other defendants. Approximately 500 individuals that were never employees of BGE each claim $6 million in damages ($2 million compensatory and $4 million punitive). These claims are currently pending in state courts in Maryland and Pennsylvania. BGE does not know the specific facts necessary to estimate its potential liability for these claims. The specific facts BGE does not know include:
To date, 357 asbestos cases were dismissed or resolved for amounts that were not significant. Approximately 11 cases are currently scheduled for trial through 2006. The second type is claims by one manufacturer—Pittsburgh Corning Corp. (PCC)—against BGE and approximately eight others, as third-party defendants. On April 17, 2000, PCC declared bankruptcy. 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. To date, about 375 cases have been resolved, all without any payment by BGE. BGE does not know the specific facts necessary to estimate its potential liability for these claims. The specific facts we do not know include:
Until the relevant facts for both types of claims are determined, we are unable to estimate what our, or BGE's, liability might be. Although insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions, the potential effect on our, or BGE's, financial results could be material. We discuss our nuclear and non-nuclear insurance programs in Note 12 of our 2004 Annual Report on Form 10-K.
We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price and transportation costs of electricity, natural gas, and other commodities. We discuss our market risk in more detail in our 2004 Annual Report on Form 10-K. We use interest rate swaps to manage our interest rate exposures associated with new debt issuances and to optimize the mix of fixed and floating-rate debt. The swaps used to manage our exposure prior to the issuance of new debt are designated as cash-flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in "Accumulated other comprehensive income" in our Consolidated Balance Sheets, in anticipation of planned financing transactions. We reclassify gains and losses on the hedges from "Accumulated other comprehensive income" into "Interest expense" in our Consolidated Statements of Income during the periods in which the interest payments being hedged occur. The swaps used to optimize the mix of fixed and floating-rate debt are designated as fair value hedges under SFAS No. 133. We record any gains or losses on swaps that qualify for fair value hedge accounting treatment, as well as changes in the fair value of the debt being hedged, in "Interest expense," and we record any changes in fair value of the swaps and the debt in "Risk management assets and liabilities" and "Long-term debt" in our Consolidated Balance Sheets. In addition, we record the difference between interest on hedged fixed-rate debt and floating-rate swaps in "Interest expense" in the periods that the swaps settle. We had net unrealized pre-tax gains on interest rate cash-flow hedges recorded in "Accumulated other comprehensive income" of $17.6 million at March 31, 2005 and $18.3 million at December 31, 2004. We expect to reclassify $2.9 million of pre-tax net gains on these cash-flow hedges from "Accumulated other comprehensive income" into "Interest expense" during the next twelve months. We had no hedge ineffectiveness on these swaps. 20 During 2004, to optimize the mix of fixed and floating-rate debt, we entered into interest rate swaps qualifying as fair value hedges relating to $450 million of our fixed-rate debt maturing in 2012 and 2015, and converted this notional amount of debt to floating-rate. The fair value of these hedges was $7.9 million at March 31, 2005 and $13.3 million at December 31, 2004 and was recorded as an increase in our "Risk management assets" and "Long-term debt." We have not recognized any hedge ineffectiveness on these interest rate swaps. At March 31, 2005 our merchant energy business had designated certain purchase and sale contracts as cash-flow hedges of forecasted transactions for the years 2005 through 2013 under SFAS No. 133. Under the provisions of SFAS No. 133, we record gains and losses on energy derivative contracts designated as cash-flow hedges of forecasted transactions in "Accumulated other comprehensive income" in our Consolidated Balance Sheets prior to the settlement of the anticipated hedged physical transaction. We reclassify these gains or losses into earnings upon settlement of the underlying hedged transaction. We record derivatives used for hedging activities from our merchant energy business in "Risk management assets and liabilities" in our Consolidated Balance Sheets. At March 31, 2005, our merchant energy business has net unrealized pre-tax gains of $191.4 million on these hedges recorded in "Accumulated other comprehensive income." We expect to reclassify $600.1 million of net pre-tax gains on cash-flow hedges from "Accumulated other comprehensive income" into earnings during the next twelve months based on the market prices at March 31, 2005. However, the actual amount reclassified into earnings could vary from the amounts recorded at March 31, 2005 due to future changes in market prices. We recognized into earnings a pre-tax gain of $11.6 million for the quarter ended March 31, 2005 and a pre-tax gain of $15.8 million for the quarter ended March 31, 2004 related to the ineffective portion of our hedges. In addition, during the quarter ended March 31, 2005, we terminated a contract previously designated as a cash-flow hedge. The forecasted transaction originally hedged is no longer probable and as a result we recognized a pre-tax loss of $6.1 million. Our merchant energy business also enters into natural gas storage contracts under which the gas in storage qualifies for fair value hedge accounting treatment under SFAS No. 133. For the quarter ended March 31, 2005, we had unrealized pre-tax gains of $1.5 million and unrealized pre-tax losses of $0.9 million due to hedge ineffectiveness resulting in a pre-tax net gain of $0.6 million being recognized into earnings. We record changes in fair value of these hedges as a component of "Fuel and purchased energy expenses" in our Consolidated Statements of Income. In December 2004, the FASB issued SFAS No. 123 Revised (SFAS No. 123R), Share-Based Payment. SFAS No. 123R revises SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB No. 25, Accounting for Stock Issued to Employees. SFAS No. 123R requires companies to recognize compensation expense for all equity-based compensation awards issued to employees. Equity-based compensation awards include stock options, restricted stock, and any other share-based payments. Under SFAS 123R, we must recognize compensation cost over the period during which an employee is required to provide service in exchange for the award. We estimate the fair value of employee stock options using option-pricing models adjusted for the unique characteristics of those instruments. We previously disclosed in our 2004 Annual Report on Form 10-K that we planned to adopt SFAS No. 123R effective July 1, 2005. However, based on Final Rule 74 issued by the Securities and Exchange Commission in April 2005, which delayed the implementation of SFAS No. 123R, we currently plan to adopt SFAS No. 123R effective January 1, 2006. We expect to adopt SFAS No. 123R using the Modified Prospective Application method without restatement of prior periods. Under this method, we will begin to amortize compensation cost for the remaining portion of our outstanding awards on the adoption date for which the requisite service has not yet been rendered. Compensation cost for these awards will be based on the fair value of those awards as disclosed on a pro-forma basis under SFAS 123 in the Stock-Based Compensation section on page 12. We will account for awards that are granted, modified, or settled after the adoption date in accordance with SFAS No. 123R. 21 Currently, we are evaluating the impact of adopting this standard on our financial results. However, we do not believe the impact of this standard on our ongoing operating results will be materially different than the results as disclosed on a pro-forma basis in the Stock-Based Compensation section on page 12. In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. (FIN) 47, Accounting for Conditional Asset Retirement Obligations—an interpretation of FASB Statement No. 143. FIN 47 clarifies that asset retirement obligations that are conditional upon a future event are subject to the provisions of SFAS No. 143. Under SFAS No. 143, we are required to recognize an estimated liability for legal obligations associated with the retirement of long-lived assets. We are currently evaluating the impact of this Interpretation.
BGE provides standard offer service to those customers that do not choose an alternate supplier. Our wholesale marketing and risk management operation provided BGE with the energy and capacity required to meet its commercial and industrial standard offer service obligations through June 30, 2004 and provides the energy and capacity required to meet its residential standard offer service obligations through June 30, 2006. Effective July 1, 2004, BGE executed one and two-year contracts for commercial and industrial electric power supply totaling approximately 2,300 megawatts. Our wholesale marketing and risk management operation is supplying a significant portion of this electric power supply. The cost of BGE's purchased energy from nonregulated subsidiaries of Constellation Energy to meet its standard offer service obligation was $213.1 million for the quarter ended March 31, 2005 compared to $240.4 million for the same period in 2004. In addition, Constellation Energy charges BGE for the costs of certain corporate functions. Certain costs are directly assigned to BGE. We allocate other corporate function costs based on a total percentage of expected use by BGE. We believe this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. These costs were approximately $25.0 million for the quarter ended March 31, 2005 compared to $17.6 million for the quarter ended March 31, 2004. BGE participates in a cash pool under a Master Demand Note agreement with Constellation Energy. Under this arrangement, participating subsidiaries may invest in or borrow from the pool at market interest rates. Constellation Energy administers the pool and invests excess cash in short-term investments or issues commercial paper to manage consolidated cash requirements. BGE had invested $295.1 million at March 31, 2005 and $127.9 million at December 31, 2004 under this arrangement. Amounts related to corporate functions performed at the Constellation Energy holding company, BGE's purchases to meet its standard offer service obligation, BGE's charges to Constellation Energy and its nonregulated affiliates for certain services it provides them, and the participation of BGE's employees in the Constellation Energy pension plan result in intercompany balances in BGE's Consolidated Balance Sheets. We believe our allocation methods are reasonable and approximate the costs that would be charged to unaffiliated entities. 22
Management's Discussion and Analysis of Financial Condition and Constellation Energy Group, Inc. (Constellation Energy) is a North American energy company that conducts its business through various subsidiaries including a merchant energy business and Baltimore Gas and Electric Company (BGE). We describe our operating segments in the Notes to Consolidated Financial Statements on page 14. This Quarterly Report on Form 10-Q is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "regulated business(es)" are to BGE. Our 2004 Annual Report on Form 10-K includes a detailed discussion of various items impacting our business, our results of operations, and our financial condition. These include:
Critical accounting policies are the accounting policies that are most important to the portrayal of our financial condition and results of operations and require management's most difficult, subjective, or complex judgment. Our critical accounting policies include revenue recognition/mark-to-market accounting, evaluation of assets for impairment and other than temporary decline in value, and asset retirement obligations. In this discussion and analysis, we explain the general financial condition and the results of operations for Constellation Energy and BGE including:
As you read this discussion and analysis, refer to our Consolidated Statements of Income on page 3, which present the results of our operations for the quarters ended March 31, 2005 and 2004. We analyze and explain the differences between periods in the specific line items of the Consolidated Statements of Income. We have organized our discussion and analysis as follows:
With the shift toward customer choice, competition, and the growth of our merchant energy business, various factors affect our financial results. We discuss these various factors in the Forward Looking Statements section on page 43. We discuss our market risks in the Market Risk section on page 40. In this section, we discuss in more detail events which have impacted our business during the quarter ended March 31, 2005.
Base Rates On April 29, 2005, BGE filed an application for a $52.7 million annual increase in our gas base rates. The Maryland Public Service Commission (Maryland PSC) is currently reviewing our application and is expected to issue an order by late November 2005. We cannot provide assurance that the Maryland PSC will approve the rate increase request, or if it does, that it will grant BGE the full amount requested. Federal Energy Legislation Federal energy legislation was passed by the U.S. House of Representatives in April 2005. However, the legislation remains subject to action by the U.S. Senate. As a result, we cannot predict the impact of potential legislation on our financial results at this time. 23 Air Quality National Ambient Air Quality Standards (NAAQS) The NAAQS are federal air quality standards that establish maximum ambient air concentrations for the following specific pollutants: ozone (smog), carbon monoxide, lead, particulates, sulfur dioxide (SO2), and nitrogen dioxide (NO2). Our generating facilities are primarily affected by ozone and particulates standards. Ozone is formed when sunlight interacts with emissions of nitrogen oxides (NOx) and volatile organic compounds (such as from motor vehicle exhaust). Our generating facilities are subject to various permits and programs meant to achieve or preserve attainment of the standards for all these pollutants. In order for states to achieve compliance with the NAAQS, the Environmental Protection Agency (EPA) adopted the Clean Air Interstate Rule (CAIR) in March 2005 to further reduce ozone and fine particulate pollution by addressing the interstate transport of SO2 and NOx emissions from fossil fuel-fired plants located primarily in the Eastern United States. The NOx reduction requirements will be phased-in starting in 2009 with both annual and ozone season reduction requirements. The phase-in will be complete by 2015. The SO2 reduction requirements will be phased-in starting in 2010 with the phase-in complete by 2015. According to the EPA, when fully implemented, CAIR will reduce SO2 emissions in the affected states by over 70 percent and reduce NOx emissions by over 60 percent from 2003 levels. Although CAIR provides the overall reduction requirements for SO2 and NOx, we do not yet know the impact on our facilities as that will be determined by the affected states in which our facilities operate. We are in the process of evaluating the impact of the rules on our financial results based on the information currently available to us. As of the filing date of this report, we believe that the environmental capital expenditure estimates provided in Item 1. Business—Environmental Matters in our 2004 Annual Report on Form 10-K remain reasonable projections. Additional federal and/or state legislation or regulation requiring further emission reductions from our facilities could be adopted. Hazardous Air Emissions The Clean Air Act requires the EPA to evaluate the public health impacts of hazardous air emissions from electric steam generating facilities. In March 2005, the EPA finalized regulations to reduce the emissions of mercury from coal-fired facilities. Under the Clean Air Mercury Rule (CAMR) the EPA has decided to regulate mercury through a market-based cap and trade program that will reduce nationwide utility emissions of mercury in two phases. Unlike the proposed rule, the final CAMR does not address emissions of nickel. The first phase of the program will begin in 2010. Additional mercury reductions will be required in the second phase of the program starting in 2018. According to the EPA, the CAMR will reduce mercury emissions from all affected coal-fired power plants by about 19 percent from 1999 levels in 2010, mostly from controls installed to comply with CAIR. The EPA expects total mercury reductions from all affected coal-fired plants of about 69 percent from 1999 levels by 2018. The CAMR will affect all coal or waste coal fired boilers at our generating facilities. Although our planned capital expenditures for compliance with CAIR are anticipated to enable us to substantially meet the mercury reduction requirements under the first phase of the cap and trade program, the overall cost of compliance with the CAMR, including complying with the requirements under the second phase of the program, could be material. We are currently evaluating the impact of the rule on our financial results. You will find details of our environmental matters in the Environmental Matters section of the Notes to Consolidated Financial Statements beginning on page 18 and in our 2004 Annual Report on Form 10-K in Item 1. Business—Environmental Matters. We discuss recently issued accounting standards in the Accounting Standards Issued section of the Notes to Consolidated Financial Statements beginning on page 21. In March 2005, we reached an agreement in principle to sell our Oleander generating facility to affiliates of The Southern Company for approximately $206 million, subject to closing adjustments. We expect the sale to close in late second quarter or early third quarter of 2005. We discuss our planned sale of the Oleander generating facility in more detail in the Notes to Consolidated Financial Statements on page 13. In April 2005, we acquired Cogenex Corporation from Alliant Energy Corporation. Cogenex is a North American energy services firm providing consulting and technology solutions to industrial, institutional and government customers. We discuss this acquisition in more detail in the Notes to Consolidated Financial Statements on page 14. 24
In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, then separately discuss earnings for our operating segments. Changes in other income, fixed charges, and income taxes are discussed, as necessary, in the aggregate for all segments in the Consolidated Nonoperating Income and Expenses section on page 35. Results
Our total net income for the quarter ended March 31, 2005 increased $54.5 million, or $0.29 per share, compared to the same period of 2004 mostly because of the following:
These increases were partially offset by the following:
Earnings per share was also impacted by additional dilution resulting from the issuance of common stock including 6.0 million shares on July 1, 2004 related to the acquisition of Ginna. In the following sections, we discuss our net income by business segment in greater detail. Background Our merchant energy business is a competitive provider of energy solutions for various customers. We discuss the impact of deregulation on our merchant energy business in Item 1. Business—Competition section of our 2004 Annual Report on Form 10-K. We record merchant energy revenues and expenses in our financial results in different periods depending upon which portion of our business they affect. We discuss our revenue recognition policies in the Critical Accounting Policies section and Note 1 of our 2004 Annual Report on Form 10-K. We summarize our policies as follows:
25
Mark-to-market accounting requires us to make estimates and assumptions using judgment in determining the fair value of our contracts and in recording revenues from those contracts. We discuss the effects of mark-to-market accounting on our revenues in the Competitive Supply—Mark-to-Market Revenues section on page 28. We discuss mark-to-market accounting and the accounting policies for the merchant energy business further in the Critical Accounting Policies section and in Note 1 of our 2004 Annual Report on Form 10-K. Results
Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 15 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. Revenues and Fuel and Purchased Energy Expenses Our merchant energy business manages the revenues we realize from the sale of energy to our customers and our costs of procuring fuel and energy. The difference between revenues and fuel and purchased energy expenses is the gross margin of our merchant energy business, and this measure is a useful tool for assessing the profitability of our merchant energy business. Accordingly, we believe it is appropriate to discuss the operating results of our merchant energy business by analyzing the changes in gross margin between periods. In managing our portfolio, we occasionally terminate, restructure, or acquire contracts. Such transactions are within the normal course of managing our portfolio and may materially impact the timing of our recognition of revenues, fuel and purchased energy expenses, and cash flows. We analyze our merchant energy gross margin in the following categories because of the risk profile of each category, differences in the revenue sources, and the nature of fuel and purchased energy expenses. With the exception of a portion of our competitive supply activities that we are required to account for using the mark-to-market method of accounting, all of these activities are accounted for on an accrual basis.
26 We provide a summary of our revenues, fuel and purchased energy expenses, and gross margin as follows:
Mid-Atlantic Region
The decrease in gross margin during the quarter ended March 31, 2005 compared to the same period of 2004 is primarily due to lower generation at Calvert Cliffs mostly because of the timing of the refueling outage resulting in lower gross margin of approximately $12 million. The refueling outage occurred during the first quarter of 2005 compared to the second quarter of 2004. In addition, we had lower gross margin mostly because of the timing of earnings related to new load-serving contracts during the quarter ended March 31, 2005 compared to the same period of 2004. Plants with Power Purchase Agreements
The increase in gross margin during the quarter ended March 31, 2005 compared to the same period of 2004 was primarily due to $46.7 million from Ginna which was acquired in June 2004. This increase in gross margin at Ginna includes an increase in revenues of $49.0 million. We also had higher gross margin of $9.8 million at our Nine Mile Point facility that benefited from the absence of an unplanned outage that occurred in January 2004 and a refueling outage that began later in the first quarter of 2005 compared to 2004. 27 Competitive Supply Retail
The increase in gross margin from our retail competitive supply activities during the quarter ended March 31, 2005 compared to the same period of 2004 is primarily due to serving 3.5 million more megawatt hours, partially offset by lower realized contract margins per megawatt hour. Wholesale
We analyze our wholesale accrual and mark-to-market competitive supply activities separately below. Wholesale Accrual Activities Our wholesale marketing and risk management operation had higher gross margin during the quarter ended March 31, 2005 compared to the same period of 2004 primarily due to approximately $43 million of newly originated and realized business in power, gas, and coal, partially offset by a decrease of approximately $19 million in the realization of contracts originated in prior periods. A substantial portion of newly originated gross margin related to the monetization of a power purchase agreement during the first quarter of 2005. The power purchase agreement would have otherwise delivered through December 2006. This sale for cash allowed us to eliminate performance risk by the counterparty under the original contract. Mark-to-Market Revenues Mark-to-market revenues include net gains and losses from origination and risk management activities for which we use the mark-to-market method of accounting. We discuss these activities and the mark-to-market method of accounting in more detail in the Critical Accounting Policies section of our 2004 Annual Report on Form 10-K. As a result of the nature of our operations and the use of mark-to-market accounting for certain activities, mark-to-market revenues and earnings will fluctuate. We cannot predict these fluctuations, but the impact on our revenues and earnings could be material. We discuss our market risk in more detail in the Market Risk section in our 2004 Annual Report on Form 10-K. The primary factors that cause fluctuations in our mark-to-market revenues and earnings are:
Mark-to-market revenues were as follows:
* Total unrealized revenues is the sum of origination transactions and total risk management. Origination gains arise from contracts that our wholesale marketing and risk management operation structures to meet the risk management needs of our customers. Transactions that result in origination gains may be unique and provide the potential for individually significant revenues and gains from a single transaction. Origination gains represent the initial fair value recognized on these structured transactions. The recognition of origination gains is dependent on the existence of observable market data that validates the initial fair value of the contract. As noted above, the recognition of origination gains is dependent on sufficient observable market data. Liquidity and market conditions impact our ability to identify sufficient, objective market-price information to permit recognition of origination gains. As a result, while our strategy and competitive position provide the opportunity to continue to originate such transactions, the level of origination revenue we are able to recognize may vary from year to year as a result of the number, size, and market-price transparency of the individual transactions executed in any period. 28 Risk management revenues represent both realized and unrealized gains and losses from changes in the value of our entire portfolio. We discuss the changes in mark-to-market revenues below. We show the relationship between our revenues and the change in our net mark-to-market energy asset later in this section. Mark-to-market revenues increased $13.2 million during the quarter ended March 31, 2005 compared to the same period of 2004 mostly because of an increase in unrealized changes in fair value. Unrealized changes in fair value increased primarily due to:
These increases in unrealized changes in fair value were partially offset by the impact of $13.8 million of higher mark-to-market losses on economic hedges that did not qualify for cash-flow hedge accounting treatment as discussed in more detail below. In the first quarter of 2005, increasing forward prices shifted value between accrual load-serving contracts and associated mark-to-market hedges, producing a timing difference in the recognition of earnings on these transactions. These mark-to-market hedges are economically effective; however, they do not qualify for cash-flow hedge accounting under Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. As a result, we recorded higher pre-tax losses of $13.8 million on the mark-to-market hedges during the quarter ended March 31, 2005 compared to the same period of 2004. This mark-to-market loss is expected to be offset as we realize the related accrual load-serving contracts in cash in future periods. Mark-to-Market Energy Assets and Liabilities Our mark-to-market energy assets and liabilities are comprised of derivative contracts and consisted of the following:
The following are the primary sources of the change in the net mark-to-market energy asset during the first quarter of 2005:
Components of changes in the net mark-to-market energy asset that affected revenues include:
29 The net mark-to-market energy asset also changed due to the following items recorded in accounts other than revenue:
The settlement terms of the net mark-to-market energy asset and sources of fair value as of March 31, 2005 are as follows:
We manage our mark-to-market risk on a portfolio basis based upon the delivery period of our contracts and the individual components of the risks within each contract. Accordingly, we record and manage the energy purchase and sale obligations under our contracts in separate components based upon the commodity (e.g., electricity or gas), the product (e.g., electricity for delivery during peak or off-peak hours), the delivery location (e.g., by region), the risk profile (e.g., forward or option), and the delivery period (e.g., by month and year). Consistent with our risk management practices, we have presented the information in the table above based upon the ability to obtain reliable prices for components of the risks in our contracts from external sources rather than on a contract-by-contract basis. Thus, the portion of long-term contracts that is valued using external price sources is presented under the caption "prices provided by external sources." This is consistent with how we manage our risk, and we believe it provides the best indication of the basis for the valuation of our portfolio. Since we manage our risk on a portfolio basis rather than contract-by-contract, it is not practicable to determine separately the portion of long-term contracts that is included in each valuation category. We describe the commodities, products, and delivery periods included in each valuation category in detail below. The amounts for which fair value is determined using prices provided by external sources represent the portion of forward, swap, and option contracts for which price quotations are available through brokers or over-the-counter transactions. The term for which such price information is available varies by commodity, region, and product. The fair values included in this category are the following portions of our contracts:
The remainder of the net mark-to-market energy asset is valued using models. The portion of contracts for which such techniques are used includes standard products for which external prices are not available and customized products that are valued using modeling techniques to determine expected future market prices, contract quantities, or both. 30 Modeling techniques include estimating the present value of cash flows based upon underlying contractual terms and incorporate, where appropriate, option pricing models and statistical and simulation procedures. Inputs to the models include:
Additionally, we incorporate counterparty-specific credit quality and factors for market price and volatility uncertainty and other risks in our valuation. The inputs and factors used to determine fair value reflect management's best estimates. The electricity, fuel, and other energy contracts we hold have varying terms to maturity, ranging from contracts for delivery the next hour to contracts with terms of ten years or more. Because an active, liquid electricity futures market comparable to that for other commodities has not developed, the majority of contracts used in the wholesale marketing and risk management operation are direct contracts between market participants and are not exchange-traded or financially settling contracts that can be readily liquidated in their entirety through an exchange or other market mechanism. Consequently, we and other market participants generally realize the value of these contracts as cash flows become due or payable under the terms of the contracts rather than through selling or liquidating the contracts themselves. Consistent with our risk management practices, the amounts shown in the table on the previous page as being valued using prices from external sources include the portion of long-term contracts for which we can obtain reliable prices from external sources. The remaining portions of these long-term contracts are shown in the table as being valued using models. In order to realize the entire value of a long-term contract in a single transaction, we would need to sell or assign the entire contract. If we were to sell or assign any of our long-term contracts in their entirety, we may not realize the entire value reflected in the table. However, based upon the nature of the wholesale marketing and risk management operation, we expect to realize the value of these contracts, as well as any contracts we may enter into in the future to manage our risk, over time as the contracts and related hedges settle in accordance with their terms. Generally, we do not expect to realize the value of these contracts and related hedges by selling or assigning the contracts themselves in total. The fair values in the table represent expected future cash flows based on the level of forward prices and volatility factors as of March 31, 2005 and could change significantly as a result of future changes in these factors. Additionally, because the depth and liquidity of the power markets varies substantially between regions and time periods, the prices used to determine fair value could be affected significantly by the volume of transactions executed. Management uses its best estimates to determine the fair value of commodity and derivative contracts 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, future market prices and actual quantities will vary from those used in recording mark-to-market energy assets and liabilities, and it is possible that such variations could be material. Risk Management Assets and Liabilities We record derivatives that qualify for designation as hedges under SFAS No. 133 in "Risk management assets and liabilities" in our Consolidated Balance Sheets. Our risk management assets and liabilities consisted of the following:
The increase in our net risk management liability was due primarily to our assumption of power sale agreements in connection with a customer contract restructuring, partially offset by increases in the value of our power and gas hedges due to higher forward market prices. We discuss the customer contract restructuring transaction in more detail in the Notes to Consolidated Financial Statements on page 11. Other
31 Our merchant energy business holds up to a 50% voting interest in 24 operating domestic energy projects that consist of electric generation, fuel processing, or fuel handling facilities. Of these 24 projects, 17 are "qualifying facilities" that receive certain exemptions and pricing under the Public Utility Regulatory Policy Act of 1978 based on the facilities' energy source or the use of a cogeneration process. We believe the current market conditions for our equity-method investments that own geothermal, coal, hydroelectric, and fuel processing projects provide sufficient positive cash flows to recover our investments. We continuously monitor issues that potentially could impact future profitability of these investments, including environmental and legislative initiatives. We discuss the impact of subsidies from the State of California in more detail in the Merchant Energy Business—Other section in our 2004 Annual Report on Form 10-K. We discuss certain risks and uncertainties in more detail in our Forward Looking Statements section on page 43. However, should future events cause these investments to become uneconomic, our investments in these projects could become impaired under the provisions of Accounting Principles Board Opinion (APB) No. 18, The Equity Method of Accounting for Investments in Common Stock. If our strategy were to change from an intent to hold to an intent to sell for any of our equity-method investments in qualifying facilities or power projects, we would need to adjust their book value to fair value, and that adjustment could be material. If we were to sell these investments in the current market, we may have losses that could be material. Operating Expenses Our merchant energy business operating expenses increased $59.6 million in 2005 compared to 2004 mostly due to the following:
These increases in expenses were partially offset by lower operating expenses of $22.5 million at Nine Mile Point, including the timing of the refueling outage as previously discussed. Depreciation and Amortization Expense Merchant energy depreciation and amortization expense increased during the quarter ended March 31, 2005 compared to the same period of 2004 mostly due to $4.8 million related to Ginna. We also had $2.4 million higher depreciation and amortization expense related to our South Carolina synthetic fuel facility during the quarter ended March 31, 2005 compared to the same period of 2004. Accretion of Asset Retirement Obligations Merchant energy accretion expense increased during the quarter ended March 31, 2005 compared to the same period of 2004 mostly due to the recognition of $3.0 million at Ginna. Taxes Other Than Income Taxes Merchant energy taxes other than income taxes increased during the quarter ended March 31, 2005 compared to the same period of 2004 mostly due to $1.7 million related to property taxes for Ginna and $1.7 million related to higher gross receipts taxes at our retail electric operation. 32 Our regulated electric business is discussed in detail in Item 1. Business—Electric Business section of our 2004 Annual Report on Form 10-K. Results
Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 15 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. Net income from the regulated electric business decreased during the quarter ended March 31, 2005 compared to the same period of 2004 mostly because of increased operations and maintenance expenses of $5.5 million after-tax primarily due to higher compensation and benefit costs and the impact of inflation on other costs. These unfavorable results were partially offset by increased revenues less electricity purchased for resale expenses of $3.3 million after-tax. Electric Revenues The changes in electric revenues in 2005 compared to 2004 were caused by:
Distribution Volumes Distribution volumes are sales to customers in BGE's service territory for the delivery service BGE provides at rates set by the Maryland PSC. The percentage changes in our distribution volumes, by type of customer, in 2005 compared to 2004 were:
In 2005, we distributed less electricity to residential customers compared to 2004 mostly due to milder winter weather partially offset by an increased number of customers. We distributed more electricity to commercial customers mostly due to increased usage per customer and an increased number of customers, partially offset by milder winter weather. We distributed less electricity to industrial customers mostly due to decreased usage by industrial customers. Standard Offer Service BGE provides standard offer service for customers that do not select an alternative generation supplier as discussed in Item 1. Business—Electric Regulatory Matters and Competition section of our 2004 Annual Report on Form 10-K. Standard offer service revenues increased in 2005 compared to 2004 mostly due to an increase in the standard offer service rates. Electric Operations and Maintenance Expenses Regulated electric operations and maintenance expenses increased $9.0 million in 2005 compared to 2004 mostly due to higher compensation and benefit costs and the impact of inflation on other costs. 33 Our regulated gas business is discussed in detail in Item 1. Business—Gas Business section of our 2004 Annual Report on Form 10-K. Results
Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 15 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. Gas Revenues The changes in gas revenues in 2005 compared to 2004 were caused by:
Distribution Volumes The percentage changes in our distribution volumes, by type of customer, in 2005 compared to 2004 were:
In 2005, we distributed less gas to residential customers compared to 2004 mostly due to decreased usage per customer and milder winter weather, partially offset by an increased number of customers. We distributed less gas to industrial customers mostly due to a decreased number of customers. Base Rates On April 29, 2005, BGE filed an application for a $52.7 million annual increase in our gas base rates. The Maryland PSC is currently reviewing our application and is expected to issue an order by late November 2005. We cannot provide assurance that the Maryland PSC will approve the rate increase request, or if it does, that it will grant BGE the full amount requested. Weather Normalization The Maryland PSC allows us to record a monthly adjustment to our gas distribution revenues to eliminate the effect of abnormal weather patterns on our gas distribution sales volumes. This means our monthly gas base rate revenues are based on weather that is considered "normal" for the month and, therefore, are not 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 as described in Note 1 of our 2004 Annual Report on Form 10-K. Gas cost adjustment revenues increased in 2005 compared to 2004 because we sold gas at a higher price partially offset by less gas sold. Off-System Gas 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. Revenues from off-system gas sales increased in 2005 compared to 2004 because we sold more gas at a higher price. Gas Purchased For Resale Expenses Gas purchased for resale expenses include the cost of gas purchased for resale to our customers and for off-system sales. These costs do not include the cost of gas purchased by delivery service only customers. Gas costs increased in 2005 compared to 2004 because we purchased more gas at a higher price. 34 Results
Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 15 provides a reconciliation of operating results by segment to our Consolidated Financial Statements. As previously discussed in our 2004 Annual Report on Form 10-K, we decided to sell certain non-core assets and accelerate the exit strategies on other assets that we will continue to hold and own over the next several years. While our intent is to dispose of these assets, market conditions and other events beyond our control may affect the actual sale of these assets. In addition, a future decline in the fair value of these assets could result in additional losses.
During the quarter ended March 31, 2005, other income increased $5.7 million compared to the same period of 2004 primarily because of higher interest and investment income due to a higher cash balance and higher decommissioning earnings. During the quarter ended March 31, 2005, total fixed charges decreased $3.9 million compared to the same period of 2004 mostly because of the benefit of lower interest rates due to interest rate swaps entered into during the third quarter of 2004 and a lower level of debt outstanding. We discuss the interest rate swaps in more detail in the Notes to Consolidated Financial Statements on page 20. During the quarter ended March 31, 2005, total fixed charges at BGE decreased $1.8 million compared to the same period of 2004 mostly because of a lower level of debt outstanding. During the quarter ended March 31, 2005, our income taxes decreased $1.9 million compared to the same period of 2004 mostly because of an increase in synthetic fuel tax credits claimed in 2005. We discuss our synthetic fuel tax credits in more detail in the Notes to Consolidated Financial Statements section on page 16. During the quarter ended March 31, 2005, income taxes at BGE decreased $2.6 million compared to the same period of 2004 mostly because of lower taxable income. 35 The following table summarizes our cash flows for the first quarter of 2005 and 2004, excluding the impact of changes in intercompany balances.
*Items are not allocated to the business segments because they are managed for the company as a whole. Cash Flows from Operating Activities Cash provided by operating activities was $349.6 million in 2005 compared to $331.6 million in 2004. Net income was $54.5 million higher in 2005 compared to 2004. This was partially offset by a decrease in non-cash adjustments to net income of $39.9 million in 2005 compared to 2004 primarily due to a decrease in loss from discontinued operations. Changes in working capital had a positive impact of $60.9 million on cash flow from operations in 2005 compared to $62.2 million in 2004. The net decrease of $1.3 million was primarily due to $68.5 million of cash paid to settle derivative liabilities, substantially offset by an increase in cash collateral received from counterparties by our merchant energy business. The $68.5 million of cash paid to settle derivative liabilities related to a customer contract restructuring which is discussed in more detail in the Notes to the Consolidated Financial Statements on page 11. Cash Flows from Investing Activities Cash used in investing activities was $292.5 million in 2005 compared to $180.8 million in 2004. The increase in cash used in 2005 compared to 2004 was primarily due to $176.4 million from issuances of loans receivable, partially offset by a $27.5 million decrease in cash paid for investments in property, plant and equipment and an increase of $42.7 million of cash provided by other investing activities. The $176.4 million issuances of loans receivable consisted of $93.6 million attributable to our merchant energy business' commodity activities and $82.8 million related to a customer contract restructuring which is discussed in more detail in the Notes to the Consolidated Financial Statements on page 11. 36 Cash Flows from Financing Activities Cash provided by financing activities was $239.5 million in 2005 compared to cash used in financing activities of $31.3 million in 2004. The increase in cash in 2005 compared to 2004 was primarily due to $308.5 million related to a customer contract restructuring which is discussed in more detail in the Notes to the Consolidated Financial Statements on page 11, partially offset by an increase in cash used for repayments of long-term debt, higher dividend payments, and an increase in cash paid for other financing activities in 2005 compared to 2004. In April 2005, we received $73 million in cash for another contract restructuring transaction previously disclosed in our 2004 Annual Report on Form 10-K. We continuously monitor our liquidity requirements and believe that our facilities and access to the capital markets provide sufficient liquidity to meet our business requirements. We discuss our available sources of funding in more detail below. Constellation Energy In addition to our cash balance, we have a commercial paper program under which we can issue short-term notes to fund our subsidiaries. At March 31, 2005, we had approximately $2.6 billion of credit under three facilities. These facilities include:
We use these facilities to ensure adequate liquidity to support our operations. We can borrow directly from the banks or use the facilities to allow the issuance of commercial paper. Additionally, we use these facilities to support letters of credit primarily for our merchant energy business. These revolving credit facilities allow the issuance of letters of credit up to approximately $2.6 billion. At March 31, 2005, letters of credit that totaled $859.5 million were issued under all of our facilities, which results in approximately $1.7 billion of unused credit facilities. BGE BGE maintains $200.0 million in annual committed credit facilities, expiring May through November of 2005, in order to allow commercial paper to be issued. BGE can borrow directly from the banks or use the facilities to allow commercial paper to be issued. As of March 31, 2005, BGE had no outstanding commercial paper, which results in $200.0 million in unused credit facilities. Our estimated annual amounts for the years 2005 and 2006 are shown in the table below. We will continue to have cash requirements for:
Capital requirements for 2005 and 2006 include estimates of spending for existing and anticipated projects. We continuously review and modify those estimates. Actual requirements may vary from the estimates included in the table below because of a number of factors including:
Our estimates are also subject to additional factors. Please see the Forward Looking Statements section on page 43. We discuss the potential impact of environmental legislation in more detail in Item 1. Business—Environmental Matters section of our 2004 Annual Report on Form 10-K. We discuss regulations recently adopted by the EPA and their impact on our capital requirements in the Environmental Matters section on page 24.
37 Capital Requirements Merchant Energy Business Our merchant energy business' capital requirements consist of its continuing requirements, including expenditures for:
Regulated Electric and Gas Regulated electric and gas construction expenditures primarily include new business construction needs and improvements to existing facilities, including projects to improve reliability.
We discuss our funding for capital requirements in our 2004 Annual Report on Form 10-K.
We enter into various agreements that result in contractual payment obligations in connection with our business activities. These obligations primarily relate to our financing arrangements (such as long-term debt, preference stock, and operating leases), purchases of capacity and energy to support the growth in our merchant energy business activities, and purchases of fuel and transportation to satisfy the fuel requirements of our power generating facilities. Our total contractual payment obligations as of March 31, 2005, increased $554.3 million during the first quarter of 2005 primarily due to new contracts related to nuclear fuel and coal procurement. We detail our contractual payment obligations in the following table:
1 Amounts in long-term debt reflect the original maturity date. Investors may require us to repay $381.6 million early through put options and remarketing features. Interest on variable rate debt is included based on the March 31, 2005 forward curve for interest rates. 2 Our operating lease commitments include future payment obligations under certain power purchase agreements as discussed further in Note 11 of our 2004 Annual Report on Form 10-K. 3 Contracts to purchase goods or services that specify all significant terms. Amounts related to certain purchase obligations are based on future purchase expectations which may differ from actual purchases. 4 Our contractual obligations for purchased capacity and energy are shown on a gross basis for certain transactions, including both the fixed payment portions of tolling contracts and estimated variable payments under unit-contingent power purchase agreements. We have recorded $13.3 million of liabilities related to purchased capacity and energy obligations at March 31, 2005 in our Consolidated Balance Sheets. 5 We have recorded liabilities of $7.6 million related to fuel and transportation obligations at March 31, 2005 in our Consolidated Balance Sheets. 6 Amounts related to postretirement and postemployment benefits are for unfunded plans and reflect present value amounts consistent with the determination of the related liabilities recorded on the Consolidated Balance Sheets. 38 The table below presents our contingent obligations. Our contingent obligations increased $764.1 million during the first quarter of 2005, primarily due to additional letters of credit and guarantees by the parent company for subsidiary obligations to third parties in support of the growth of our merchant energy business. These amounts do not represent incremental consolidated Constellation Energy obligations; rather, they primarily represent parental guarantees of certain subsidiary obligations to third parties. Our calculation of the fair value of subsidiary obligations covered by the $6,224.0 million of parent company guarantees was $2,188.5 million at March 31, 2005. Accordingly, if the parent company was required to fund subsidiary obligations, the total amount at current market prices is $2,188.5 million.
1 While the face amount of these guarantees is $6,224.0 million, we do not expect to fund the full amount. In the event the parent were required to fulfill subsidiary obligations, our calculation of the fair value of obligations covered by these guarantees was $2,188.5 million at March 31, 2005. 2 Other guarantees in the above table are shown net of liabilities of $25.0 million recorded at March 31, 2005 in our Consolidated Balance Sheets. In many cases, customers of our wholesale marketing and risk management operation rely on the creditworthiness of Constellation Energy. A decline below investment grade by Constellation Energy would negatively impact the business prospects of that operation. We regularly review our liquidity needs to ensure that we have adequate facilities available to meet collateral requirements. This includes having liquidity available to meet margin requirements for our wholesale marketing and risk management operation and our retail competitive supply activities. We have certain agreements that contain provisions that would require additional collateral upon significant credit rating decreases in the Senior Unsecured Debt of Constellation Energy. Decreases in Constellation Energy's credit ratings would not trigger an early payment on any of our credit facilities. Under counterparty contracts related to our wholesale marketing and risk management operation, we are obligated to post collateral if Constellation Energy's senior, unsecured credit ratings decline below established contractual levels. Based on contractual provisions, we estimate that we would have additional collateral obligations based on downgrades to the following credit ratings for our Senior Unsecured Debt:
Based on market conditions and contractual obligations at the time of a downgrade, we could be required to post collateral in an amount that could exceed the amounts specified above, which could be material. At March 31, 2005, we had approximately $1.9 billion of unused credit facilities. Certain credit facilities of Constellation Energy contain a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 65%. At March 31, 2005, the debt to capitalization ratio as defined in the credit agreements was no greater than 54%. Certain credit facilities of BGE contain provisions requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At March 31, 2005, the debt to capitalization ratio for BGE as defined in these credit agreements was 45%. At March 31, 2005, no amount is outstanding under these facilities.
We discuss our off-balance sheet arrangements in our 2004 Annual Report on Form 10-K. 39 We measure the sensitivity of our wholesale marketing and risk management mark-to-market energy contracts to potential changes in market prices using value at risk. Value at risk represents the potential pre-tax loss in the fair value of our wholesale marketing and risk management mark-to-market energy assets and liabilities over one and ten-day holding periods. We discuss value at risk in more detail in the Market Risk section of our 2004 Annual Report on Form 10-K. The table below is the value at risk associated with our wholesale marketing and risk management operation's mark-to-market energy assets and liabilities, including both trading and non-trading activities.
The following table details our value at risk for the trading portion of our wholesale marketing and risk management mark-to-market energy assets and liabilities over a one-day holding period at a 99% confidence level for the first quarter of 2005:
Due to the inherent limitations of statistical measures such as value at risk 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. As a result, actual changes in the fair value of mark-to-market energy assets and liabilities could differ from the calculated value at risk, and such changes could have a material impact on our financial results. We actively manage the credit portfolio of our wholesale marketing and risk management operation to attempt to reduce the impact of counterparty default. As of March 31, 2005 and December 31, 2004, the credit portfolio of our wholesale marketing and risk management operation had the following public credit ratings:
1 Includes counterparties with an investment grade rating by at least one of the major credit rating agencies. If split rating exists, the lower rating is used. Compared to December 31, 2004, we experienced a slight deterioration in the credit quality of our publicly rated wholesale marketing and risk management portfolio. The decline in investment grade equivalent counterparties is primarily due to increased exposure to lower credit quality fuel and power supply counterparties. In addition to the credit ratings provided by the major credit rating agencies, we utilize internal credit ratings to evaluate the creditworthiness of our wholesale customers, including those companies that do not have public credit ratings. The Not Rated category in the table above includes counterparties that do not have public credit ratings and include governmental entities, municipalities, cooperatives, power pools, and other load-serving entities, and marketers for which we determine creditworthiness based on internal credit ratings. The following table provides the breakdown of the credit quality of our wholesale credit portfolio based on our internal credit ratings.
40 Compared to December 31, 2004, the credit quality of our wholesale marketing and risk management portfolio improved slightly. A portion of our wholesale credit risk is related to transactions that are recorded in our Consolidated Balance Sheets. These transactions primarily consist of open positions from our wholesale marketing and risk management operation that are accounted for using mark-to-market accounting, as well as amounts owed by wholesale counterparties for transactions that settled but have not yet been paid. The following table highlights the credit quality and exposures related to these activities at March 31, 2005:
Due to the possibility of extreme volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to deliver the electricity our wholesale marketing and risk management operation had contracted for), we could incur a loss that could have a material impact on our financial results. Additionally, if a counterparty were to default and we were to liquidate all contracts with that entity, our credit loss would include the loss in value of mark-to-market contracts, the amount owed for settled transactions, and additional payments, if any, we would have to make to settle unrealized losses on accrual contracts. We continue to examine plans to achieve our strategies and to further strengthen our balance sheet and enhance our liquidity. We discuss our liquidity in the Financial Condition section on page 39.
We discuss our exposure to interest rate risk, retail credit risk, foreign currency risk, and equity price risk in the Market Risk section of our 2004 Annual Report on Form 10-K. 41 Item 3. Quantitative and Qualitative Disclosures About Market Risk We discuss the following information related to our market risk:
Item 4. Controls and Procedures A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Constellation Energy or BGE have been detected. These inherent limitations include errors by personnel in executing controls due to faulty judgment or simple mistakes, which could occur in situations such as when personnel performing controls are new to a job function or when inadequate resources are applied to a process. Additionally, controls can be circumvented by the individual acts of some persons or by collusion of two or more people. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no absolute assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions or personnel, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Evaluation of Disclosure Controls and Procedures The principal executive officers and principal financial officer of both Constellation Energy and BGE have evaluated the effectiveness of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the fiscal quarter covered by this quarterly report (the "Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, Constellation Energy's and BGE's disclosure controls and procedures are effective, in that they provide reasonable assurance that such officers are alerted on a timely basis to material information relating to Constellation Energy and BGE that is required to be included in Constellation Energy's and BGE's periodic filings under the Exchange Act. Changes in Internal Control over Financial Reporting Except as discussed below, during the quarter ended March 31, 2005, there has been no change in either Constellation Energy's or BGE's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d—15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, either Constellation Energy's or BGE's internal control over financial reporting. As previously disclosed in Item 9A. Controls and Procedures of our 2004 Annual Report on Form 10-K, during January 2005, Constellation Energy implemented a new enterprise reporting platform, which included a general ledger and various sub-ledgers, for certain of its operating subsidiaries. Following this implementation, substantially all of Constellation Energy's operating subsidiaries are using the new system. The implementation affected systems that include certain internal controls, and accordingly, the implementation required revisions to our internal control over financial reporting. We reviewed the system during and following the implementation, as well as the controls affected by the implementation of the system and made appropriate changes to affected internal controls. 42 PART II. OTHER INFORMATION We discuss our Legal Proceedings in the Notes to Consolidated Financial Statements on page 19.
The following table presents shares surrendered by employees to satisfy tax withholding obligations on vested restricted stock.
Forward Looking Statements We make statements in this report that are considered forward looking statements within the meaning of the Securities Exchange Act of 1934. Sometimes these statements will contain words such as "believes," "anticipates," "expects," "intends," "plans," and other similar words. We also disclose non-historical information that represents management's expectations, which are based on numerous assumptions. These statements and projections are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include, but are not limited to:
43
energy contracts, such as the ability to obtain market prices and, in the absence of verifiable market prices, the appropriateness of models and model inputs (including, but not limited to, estimated contractual load obligations, unit availability, forward commodity prices, interest rates, correlation and volatility factors), Given these uncertainties, you should not place undue reliance on these forward looking statements. Please see the other sections of this report and our other periodic reports filed with the Securities and Exchange Commission for more information on these factors. These forward looking statements represent our estimates and assumptions only as of the date of this report. Changes may occur after that date, and neither Constellation Energy nor BGE assume responsibility to update these forward looking statements. 44 Item 6. Exhibits
45 Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
46 PART 1—FINANCIAL INFORMATION Item 1—Financial Statements CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) CONSOLIDATED BALANCE SHEETS CONSOLIDATED BALANCE SHEETS CONSOLIDATED STATEMENTS OF CASH FLOWS CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) CONSOLIDATED BALANCE SHEETS CONSOLIDATED BALANCE SHEETS CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Basis of Presentation Variable Interest Entities Customer Contract Restructuring Earnings Per Share Stock-Based Compensation Accretion of Asset Retirement Obligations Workforce Reduction Discontinued Operations Acquisition of Cogenex Information by Operating Segment
Financing Activities Income Taxes Commitments, Guarantees, and Contingencies Long-Term Power Sales Contracts Guarantees Environmental Matters Legal Proceedings Insurance SFAS No. 133 Hedging Activities Interest Rates Commodity Prices Accounting Standards Issued SFAS No. 123 Revised FIN 47 Related Party Transactions—BGE Income Statement Balance Sheet
Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction and Overview Business Environment Regulation by the Maryland PSC Federal Regulation Environmental Matters Accounting Standards Issued Events of 2005 Discontinued Operations Acquisition of Cogenex
Overview Quarter Ended March 31, 2005 Merchant Energy Business
Consolidated Nonoperating Income and Expenses Other Income Fixed Charges Income Taxes Financial Condition Cash Flows Available Sources of Funding Capital Resources Funding for Capital Requirements Contractual Payment Obligations and Committed Amounts Liquidity Provisions Off-Balance Sheet Arrangements Market Risk Commodity Risk Wholesale Credit Risk Interest Rate Risk, Retail Credit Risk, Foreign Currency Risk, and Equity Price Risk Item 4. Controls and Procedures PART II OTHER INFORMATION
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds Item 5. Other Information SIGNATURE | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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