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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year endedDECEMBER 31, 20072010
Commission file number | Exact name of registrant as specified in its charter | IRS Employer Identification No. |
1-12869 | CONSTELLATION ENERGY GROUP, INC. | 52-1964611 | ||
100 CONSTELLATION WAY, BALTIMORE, MARYLAND 21202 (Address of principal executive offices) (Zip Code) | ||||
410-470-2800 (Registrants' telephone number, including area code) |
1-1910 | BALTIMORE GAS AND ELECTRIC COMPANY | 52-0280210 |
MARYLAND
(States of incorporation)
750 E. PRATT2 CENTER PLAZA, 110 WEST FAYETTE STREET, BALTIMORE, MARYLAND 21202 (Address(Address of principal executive offices) (Zip Code)
410-783-2800410-234-5000
(Registrants' telephone number, including area code)
MARYLAND
(States of incorporation of both registrants)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Title of each class | | Name of each exchange on which registered | ||
---|---|---|---|---|
Constellation Energy Group, Inc. Common Stock—Without Par Value | ) | New York Stock Exchange Chicago Stock Exchange | ||
Constellation Energy Group, Inc. Series A Junior Subordinated Debentures 6.20% Trust Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust II, fully and unconditionally guaranteed, based on several obligations, by Baltimore Gas and Electric Company | ) | New York Stock Exchange |
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
Not Applicable
Indicate by check mark if Constellation Energy Group, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No o.
Indicate by check mark if Baltimore Gas and Electric Company is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No o.
Indicate by check mark if Constellation Energy Group, Inc. is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No ý.
Indicate by check mark if Baltimore Gas and Electric Company is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No ý.
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether Constellation Energy Group, Inc. has submitted electronically and posted on its corporate Web-site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
Indicate by check mark whether Baltimore Gas and Electric Company has submitted electronically and posted on its corporate Web-site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark whether Constellation Energy Group, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filerý Accelerated filer o Non-accelerated filero Smaller reporting company o
Indicate by check mark whether Baltimore Gas and Electric Company is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filero Accelerated filer o Non-accelerated filer ý Smaller reporting company o
Indicate by check mark whether Constellation Energy Group, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o No ý
Indicate by check mark whether Baltimore Gas and Electric Company is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o No ý
Aggregate market value of Constellation Energy Group, Inc. Common Stock, without par value, held by non-affiliates as of June 30, 20072010 was approximately $15,630,501,504$6,490,790,907 based upon New York Stock Exchange composite transaction closing price.
CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE177,923,807199,850,572 SHARES OUTSTANDING ON JANUARY 31, 2008.2011.
DOCUMENTS INCORPORATED BY REFERENCE
Part of Form 10-K | Document Incorporated by Reference | |
---|---|---|
III | Certain sections of the Proxy Statement for the |
Baltimore Gas and Electric Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this Form in the reduced disclosure format.
TABLE OF CONTENTSTable of Contents
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:
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 (SEC) 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 assumeassumes responsibility to update these forward looking statements.
Overview
Constellation Energy is an energy company that includes a merchant energygeneration business (Generation), a customer supply business (NewEnergy), and BGE, a regulated electric and gas public utility in central Maryland.
Constellation Energy was incorporated in Maryland on September 25, 1995. On April 30, 1999, Constellation Energy became the holding company for BGE and its subsidiaries. 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 merchant energyGeneration business is a competitive provider of energy solutions for a variety of customers. It hasdevelops, owns, owns interests in, and operates electric generation assetsfacilities and a fuel processing facility located in various regions of the United StatesStates. This business also includes an operation that manages certain contractually controlled physical assets, including generating facilities and provides energy solutions to meet customers' needs.owns an interest in a joint venture that owns and operates nuclear generating facilities.
Our merchant energyNewEnergy business is primarily a competitive provider of energy-related products and services for a variety of customers and focuses on serving the energyselling electricity, natural gas, and capacityother energy-related products to serve customers' requirements (load-serving) of,, and providing other energy products and risk management services for, various customers.services. This business also manages our upstream natural gas activities, designs, constructs, and operates renewable energy, heating, cooling, and cogeneration facilities and provides home improvements, sales of electric and gas appliances, and servicing of heating, air conditioning, plumbing, electrical, and indoor air quality systems.
BGE is a regulated electric transmission and distribution utility company and a regulated gas distribution utility company with a service territory that covers the City of Baltimore and all or part of ten10 counties in central Maryland. BGE was incorporated in Maryland in 1906.
Our other nonregulated businesses:
Constellation Energy maintains a website at constellation.com where copiesEDF the full ownership of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments may be obtained free of charge. These reports are posted on our website the same day they are filed with the SEC. The SEC maintains a website (sec.gov), where copies of our filings may be obtained free of charge. The website address for BGE is bge.com. These website addresses are inactive textual references, and the contents of these websites are not part ofprior nuclear development joint venture, UniStar Nuclear Energy, LLC (UNE). We discuss this Form 10-K.comprehensive agreement in more detail inNote 4 to Consolidated Financial Statements.
In addition, the website for Constellation Energy includes copies of our Corporate Governance Guidelines, Principles of Business Integrity, Corporate Compliance Program, Insider Trading Policy, Policy and Procedures with respect to Related Person Transactions, and Information Disclosure Policy, and the charters of the Audit, Compensation and Nominating and Corporate Governance Committees of the Board of Directors. Copies of each of these documents may be printed from our website or may be obtained from Constellation Energy upon written request to the Corporate Secretary.
The Principles of Business Integrity is a code of ethics that applies to all of our directors, officers, and employees, including the chief executive officer, chief financial officer, and chief accounting officer. We will post any amendments to, or waivers from, the Principles of Business Integrity applicable to our chief executive officer, chief financial officer, or chief accounting officer on our website.
The percentages of revenues, net (loss) income attributable to common stock, and assets attributable to our operating segments are shown in the tables below. We present information about our operating segments, including certain other items, inNote 3 to Consolidated Financial Statements.
| Unaffiliated Revenues | ||||||||
---|---|---|---|---|---|---|---|---|---|
| Merchant Energy | Regulated Electric | Regulated Gas | Other Nonregulated | |||||
2007 | 83 | % | 12 | % | 4 | % | 1 | % | |
2006 | 83 | 11 | 5 | 1 | |||||
2005 | 81 | 12 | 6 | 1 |
Net Income (1) | |||||||||
---|---|---|---|---|---|---|---|---|---|
| Merchant Energy | Regulated Electric | Regulated Gas | Other Nonregulated | |||||
2007 | 83 | % | 12 | % | 3 | % | 2 | % | |
2006 | 77 | 16 | 5 | 2 | |||||
2005 | 67 | 28 | 5 | — |
| Total Assets | ||||||||
---|---|---|---|---|---|---|---|---|---|
| Merchant Energy | Regulated Electric | Regulated Gas | Other Nonregulated | |||||
2007 | 73 | % | 20 | % | 6 | % | 1 | % | |
2006 | 75 | 17 | 6 | 2 | |||||
2005 | 77 | 16 | 6 | 1 |
| Unaffiliated Revenues | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Generation | NewEnergy | Regulated Electric | Regulated Gas | Holding Company and Other | |||||||||||
2010 | 8 | % | 68 | % | 19 | % | 5 | % | — | % | ||||||
2009 | 4 | 73 | 18 | 5 | — | |||||||||||
2008 | 4 | 77 | 14 | 5 | — |
| Net (Loss) Income Attributable to Common Stock | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Generation | NewEnergy | Regulated Electric | Regulated Gas | Holding Company and Other | |||||||||||
2010 | (128 | )% | 14 | % | 10 | % | 4 | % | — | % | ||||||
2009 | 107 | (9 | ) | 1 | 1 | — | ||||||||||
2008 | (27 | ) | (76 | ) | — | 3 | — |
| Total Assets | ||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Generation | NewEnergy | Regulated Electric | Regulated Gas | Holding Company and Other | Eliminations | |||||||||||||
2010 | 49 | % | 19 | % | 26 | % | 7 | % | 4 | % | (5 | )% | |||||||
2009 | 53 | 18 | 21 | 6 | 19 | (17 | ) | ||||||||||||
2008 | 50 | 32 | 21 | 6 | 15 | (24 | ) |
We develop, own, operate, and 2005 and cumulative effects of changes in accounting principles in 2005 as discussed in more detail in Item 8. Financial Statements and Supplementary Data.
Merchant Energy Business
Introduction
Our merchant energy business integrates electric generation assets with the marketing and risk management of energy and energy-related products to wholesale and retail customers, allowing us to manage energy price risk over geographic regions and time.
Our merchant energy business includes:
Our merchant energy business:
For years 2007 and prior, we analyze the results of our merchant energy business as follows:
Beginning in 2008, we will analyze our merchant energy business in terms of Generation, Customer Supply and Global Commodities activities.market.
We present details about our generating properties inItem 2. Properties.
Mid-Atlantic RegionInvestment in Nuclear Generating Facilities
We own 6,355 MWOn November 6, 2009, we completed the sale of fossil,a 49.99% membership interest in Constellation Energy Nuclear Group LLC and affiliates (CENG), our subsidiary that owns our nuclear and hydroelectric generation capacity in the Mid-Atlantic Region.generating facilities
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described below. The total output of these nuclear facilities over the past three years is presented in the following table:
| Calvert Cliffs | Nine Mile Point | Ginna | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| MWH | Capacity Factor | MWH (1) | Capacity Factor | MWH | Capacity Factor | |||||||||||||
| (MWH in millions) | ||||||||||||||||||
2010 | 14.0 | 94 | % | 12.6 | 93 | % | 4.9 | 97 | % | ||||||||||
2009 | 14.5 | 96 | 13.1 | 97 | 4.6 | 91 | |||||||||||||
2008 | 14.7 | 96 | 12.8 | 94 | 4.7 | 94 |
In connection with the closing of the transaction with EDF on November 6, 2009, we entered into a power purchase agreement (PPA) with CENG under which we will purchase 85 to 90% of the output that is not sold to third parties under pre-existing PPAs for an initial five year period. Additionally, pursuant to an amendment to the PPA entered into in 2010, beginning on January 1, 2015, and continuing to the end of the lives of the respective nuclear plants, is managed by our global commodities operationwe will purchase 50.01% and EDF will purchase 49.99% of the output of CENG's nuclear plants. We discuss this PPA in more detail inNote 16 to Consolidated Financial Statements.
Calvert Cliffs
CENG owns 100% of Calvert Cliffs Unit 1 and Unit 2. Unit 1 entered service in 1974 and is hedged through a combination of power saleslicensed to wholesaleoperate until 2034. Unit 2 entered service in 1976 and retail market participants. Our merchant energy business meets the load-serving requirements of various contracts using the output from the Mid-Atlantic Region and from purchases in the wholesale market.
BGE transferred all of these facilitiesis licensed to our merchant energy generation subsidiaries on July 1, 2000 as a result of the implementation of electric customer choice and competition among suppliers in Maryland, except for the Handsome Lake facility that commenced operations in mid-2001. The assets transferred from BGE are subject to the lien of BGE's mortgage. We expect the assets to be released from this lien following payment in March 2008 of the last series of bonds outstanding under the mortgage and the subsequent discharge of the mortgage.
Our merchant energy business supplies BGE with a portion of its market-based standard offer service obligation. For 2007, the peak load supplied to BGE was approximately 3,200 MW.operate until 2036.
Plants with Power Purchase Agreements
We own 2,134 MW of nuclear generation capacity with power purchase agreements for a significant portion of their output. Our facilities with power purchase agreements are the Nine Mile Point Nuclear Station (Nine Mile Point) and the R.E. Ginna Nuclear Plant (Ginna). Both Nine Mile Point and Ginna are located within the New York Independent System Operator (NYISO) region.
We ownCENG owns 100% of Nine Mile Point Unit 1 (620 MW) and 82% of Unit 2 (933 MW).2. The remaining interest in Nine Mile Point Unit 2 is owned by the Long Island Power Authority (LIPA). Unit 1 entered service in 1969 and is licensed to operate until 2029. Unit 2 entered service in 1988 and is licensed to operate until 2046.
We sellNine Mile Point Unit 2 sells 90% of our share of Nine Mile Point'sthe plant's output to the former owners of the plant at an average price of nearlyapproximately $35 per megawatt-hour (MWH)MWH under agreementsa PPA that terminate between 2009 andterminates in November 2011. The agreements arePPA is unit contingent (if the output is not available because the plant is not operating, there is no requirement to provide output from other sources). The remaining 10% of our sharethe output of Nine Mile Point's outputPoint Unit 2 is managed by our global commodities operationCENG and sold into the wholesale market.primarily to us and EDF.
After termination of the power purchase agreements,Nine Mile Point Unit 2 PPA, a revenue sharing agreement with the former owners of the plant will begin and continue through November 2021. Under this agreement, which applies only to ourCENG's ownership percentage of Unit 2, a predetermined strike price is compared to the market price for electricity. If the market price exceeds the strike price, then 80% of this excess amount is shared with the former owners of the plant. The average strike price for the first year of the revenue sharing agreement is $40.75 per MWH. The strike price increases two percent annually beginning in the second year of the revenue sharing agreement. The revenue sharing agreement is unit contingent and is based on the operation of the unit.Unit 2.
WeCENG exclusively operateoperates Unit 2 under an operating agreement with LIPA. LIPA is responsible for 18% of the operating costs (and(including decommissioning costs) and capital expenditures of Unit 2 and has representation on the Nine Mile Point Unit 2 management committee, which provides certain oversight and review functions.
We ownGinna
CENG owns 100% of the Ginna nuclear facility. Ginna consists of a 581 MW reactor that entered service in 1970 and is licensed to operate until 2029. We sell up to 80%Ginna sells approximately 90% of the plant's output and capacity to the former ownersowner for 10 years ending in 2014 at an average price of $44.00 per MWH under a long term unit contingent power purchase agreement.long-term unit-contingent PPA. The remaining 10% of the output of Ginna is managed by our global commodities operationCENG and sold into the wholesale market.
Competitive SupplyNew Nuclear
In November 2010, as part of our comprehensive agreement with EDF to restructure the relationship between our two companies, we sold our 50% ownership interest in UNE to EDF. EDF is now the sole owner of UNE, and we will no longer have responsibility for developing or financing new nuclear projects through UNE. As discussed inNote 4 to Consolidated Financial Statements, we will cause CENG to transfer to UNE two potential new nuclear sites upon receipt of necessary approvals.
Qualifying Facilities and Power Projects
We hold up to a 50% voting interest in 15 operating energy projects, totaling approximately 758 MW, that consist of electric generation (primarily relying on alternative fuel sources), fuel processing, or fuel handling facilities. Thirteen of the electric generation projects are considered qualifying facilities under the Public Utility Regulatory Policies Act of 1978. Each electric generating plant sells its output to a local utility under long-term contracts.
Contracted Generation
We manage approximately 1,100 MWs under three agreements with third party generators in which we have long-dated contractual rights to purchase power from these third party generating plants. The economics of these transactions are similar to our owned generation.
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We are a leading supplier of energy products and services to wholesale customers and retail commercial, industrial, and governmental customers. In 2007, our wholesale competitive supply operation provided approximately 16,500 peak MWs of wholesale full requirements load-serving products. During 2007, our retail competitive supply activities served approximately 16,200 MW of peak load and approximately 410,000 mmBTUs ofelectricity, natural gas.
Wholesale and Retail Load-Serving Activities
Our wholesale competitive supply operation structures transactions that serve the full energy and capacity requirements of various customers such as distribution utilities, municipalities, cooperatives, and retail aggregators that do not own sufficient generating capacity or in-house supply functions to meet their own load requirements.
Our retail competitive supply operation structures transactions to supply full energy and capacity requirements and provide natural gas, transportation, and other energy products and services to wholesale and retail commercial, industrial,electric and governmentalnatural gas customers. Contracts with these customers generally extend from one to ten years, but some can be longer.
To meet our customers' load-serving requirements, our merchant energyNewEnergy business obtains energy from various sources, including:
During 2010, our NewEnergy business:
Our NewEnergy business also manages certain contractually controlled physical assets, including generation facilities (excluding long-dated tolling agreements managed by our Generation business), and natural gas contracts.
properties, provides risk management services, and trades energy and energy-related commodities. This business also provides the wholesale risk management function for our Generation business, as well as structured products and energy investment activities and includes our actual hedged positions with third parties.
Our NewEnergy business also manages our upstream natural gas activities, designs, constructs, and operates renewable energy, heating, cooling, and cogeneration facilities and provides home improvements, sales of electric and gas appliances, and servicing of heating, air conditioning, plumbing, electrical, and indoor air quality systems.
Wholesale Customer Supply
In 2010, our wholesale NewEnergy customer supply operation served approximately 57 million MWHs of wholesale full requirements electricity and related load-serving products.
Our wholesale NewEnergy customer supply operation structures transactions that serve the full energy and capacity requirements of various customers such as distribution utilities, municipalities, cooperatives and retail aggregators that do not own sufficient generating capacity or have in-house supply functions to meet their own load requirements.
Retail Customer Supply
During 2010, our retail NewEnergy customer supply operation served approximately 62 million MWHs of electricity load and approximately 334 million mmBTUs of natural gas.
Our retail NewEnergy customer supply operation structures transactions to supply full energy and capacity requirements and provide natural gas, transportation, and other energy products and services to commercial, industrial, governmental, and residential customers. Contracts with these customers generally extend from one to ten years, but some can be longer.
The retail NewEnergy customer supply operation combines a unified sales force with a customer-centric model that leverages technology to broaden the range of products and services we offer, which we believe promotes stronger customer relationships. This model focuses on efficiency and cost reduction, which we believe will provide a platform that is scalable and able to capitalize on opportunities for future growth.
Structured Products
Our NewEnergy business uses energy and energy-related commodities and contracts in order to manage our portfolio of energy purchases and sales to customers through structured transactions. Our NewEnergy business assists customers with customized risk management products in the power, gas, coal, and freight markets (e.g., generation tolls and gas transport and storage).
Energy Investments
Our NewEnergy business has investments in energy assets that primarily include natural gas activities. Our NewEnergy business includes upstream (exploration and production) and downstream (transportation and storage) natural gas operations. Our upstream natural gas activities include the development, exploration, and exploitation of natural gas properties, as well as an approximately 28.5% interest in Constellation Energy Partners LLC (CEP), a limited liability company that we formed. CEP is principally engaged in the acquisition, development, and exploitation of natural gas properties. We no longer have any active involvement in the day-to-day operations of CEP.
Portfolio Management and Trading
Our NewEnergy business transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. We continue to identify and pursue opportunitiesuse economic value
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at risk, which can generate additional returns throughmeasures the market risk in our total portfolio, management and trading activities within our business. These opportunities have increased due to the significant growth in scaleencompassing all aspects of our competitive supply operations.NewEnergy business, along with daily value at risk limits, stop loss limits, position limits, generation hedge ratios, and liquidity guidelines to restrict the level of risk in our portfolio.
In managing our portfolio, we may 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.
Our global commodities operation actively uses energy and energy-related commodities and contracts for those commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. We use both derivative and nonderivative contracts in managing our portfolio of energy sales and purchase contracts. Generally, we expect to use both derivative and nonderivative contracts to hedge our portfolio in order to reduce volatility. Although a substantial portion of our portfolio is hedged, we are able to identify opportunities to deploy risk capital to increase the value of our accrual positions, which we characterize as portfolio management.
We trade Active portfolio management is intended to allow our NewEnergy business to:
We discuss the impact of our trading activities and economic value at risk in more detail inItem 7. Management's Discussion and Analysis.
TheseOur portfolio management and trading activities involve the use of physical commodity inventories and a variety of instruments, including:
ActiveBeginning in the fourth quarter of 2008 and continuing throughout 2010, we reduced the risk and scale of our portfolio management allowsand trading activities. Energy trading activities were scaled back and are being used primarily for hedging our merchant energy business to:
Coal and International Services
Our global commodities operation participates in global coal sourcing activities by providing coal and coal-related logistical services for the variable or fixed supply needs of global customers. In late 2006, we formed a shipping joint venture that will own and operate six freight ships for the delivery of coal and other dry bulk freight products. We own a 50% interest in this joint venture. In 2007, we delivered approximately 28 million tons of coal to global customers and trading activities' contribution to our own generation fleet. Additionally, we entered into power, natural gas, freight, and emissions transactions outside of the United States. We also include in our coal services the results from our synthetic fuel processing facility in South Carolina. In 2008, these synthetic fuel processing facilities will be decommissioned.
We will continue to evaluate new international opportunities, including expanding our coal sourcing, freight, power, natural gas and emissions activities outside of the United States.operating results.
Natural Gas Services
Our global commodities operation includes upstream (exploration and production) and downstream (transportation and storage) natural gas operations. Our upstream activities include the acquisition, development, and exploitation of natural gas properties. Our downstream activities include providing natural gas to various customers, including large utilities, commercial and industrial customers, power generators, wholesale marketers, and retail aggregators.
In 2007, 2006 and 2005, we acquired working interests in gas producing fields. We discuss these acquisitions in more detail inNote 15 to Consolidated Financial Statements.
In November 2006, we completed the initial public offering of Constellation Energy Partners LLC (CEP), a limited liability company that we formed. CEP is principally engaged in the acquisition, development, and exploitation of natural gas properties. During 2007, CEP conducted additional equity issuances in which we did not participate, and our ownership percentage fell below 50 percent. Therefore, in 2007, we deconsolidated CEP and began to account for our interest under the equity method of accounting. We discuss the impact of CEP's equity issuances and deconsolidation on our financial results in more detail inNote 2 to Consolidated Financial Statements.
Other
We hold up to a 50% voting interest in 24 operating energy projects that consist of electric generation (primarily relying on alternative fuel sources), fuel processing, or fuel handling facilities. Of those, the electric generation projects are considered qualifying facilities under the Public Utility Regulatory Policies Act of 1978. Each electric generating plant sells its output to a local utility under long-term contracts.
We also provide operation and maintenance services, including testing and start-up, to owners of electric generating facilities.
UniStar Nuclear
In 2005, we formed UniStar Nuclear, LLC (UniStar), a joint enterprise with AREVA NP, Inc., (AREVA) to introduce the advanced design Evolutionary Power Reactor to the U.S. market. Upon conversion to U.S. electrical standards, the technology will be known as the U.S. EPR.
In August 2007, we formed a joint venture, UniStar Nuclear Energy, LLC (UNE) with an affiliate of Electricite de France, SA (EDF). We have a 50% ownership interest in this joint venture to develop, own, and operate new nuclear projects in the United States and Canada. The agreement with EDF includes a phased-in cash investment of $625 million by EDF in UNE. Initially, EDF invested $350 million of cash in UNE, and we contributed UniStar and other UniStar-related assets, which had a book value of $49 million, and the right to develop new nuclear projects at our existing nuclear plant locations. Upon reaching certain licensing milestones, EDF will contribute up to an additional $275 million of cash in UNE for a total of $625 million. In the event that the joint venture is terminated, the remaining equity of UNE, after certain expenses, will be divided equally between Constellation Energy and EDF pursuant to the joint venture agreement.
In connection with this joint venture, we entered into an investor agreement with EDF under which EDF may purchase in the open market up to a total of 9.9% of our outstanding common stock during the next five years, with a limit of 5% ownership during the first twelve months of the agreement. EDF has agreed to vote any shares of our common stock owned by it in the manner recommended by our board of directors and not take any actions that seek control of Constellation Energy during the next five years.
Fuel Sources
Our power plants use diverse fuel sources. Our plants' fuel mix based on capacity owned at December 31, 20072010 and our generation based on actual output by fuel type in 2007 wereduring 2010 was as follows:
Fuel | Capacity Owned | Generation | |||
---|---|---|---|---|---|
Nuclear | 45 | % | 61 | % | |
Coal | 31 | 35 | |||
Natural Gas | 7 | — | |||
Oil | 8 | — | |||
Renewable and Alternative (1) | 5 | 4 | |||
Dual (2) | 4 | — |
Fuel | Capacity Owned | Generation | |||||
---|---|---|---|---|---|---|---|
Nuclear (1) | 21 | % | 45 | % | |||
Coal | 30 | 37 | |||||
Natural Gas | 31 | 13 | |||||
Oil | 8 | — | |||||
Renewable and Alternative (2) | 6 | 5 | |||||
Dual (3) | 4 | — |
We discuss our risks associated with fuel in more detail inItem 7. Management's Discussion and Analysis—Market Risk.Risk Management.
Nuclear
The output ofCENG, our nuclear facilities overjoint venture with EDF, owns the past five years (including periods prior to our acquisition ofCalvert Cliffs, Nine Mile Point, and Ginna in June 2004) is presented in the following table:
| Calvert Cliffs | Nine Mile Point | Ginna | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| MWH | Capacity Factor | MWH* | Capacity Factor | MWH | Capacity Factor | |||||||
| (MWH in millions) | ||||||||||||
2007 | 14.3 | 94 | % | 12.3 | 90 | % | 4.9 | 98 | % | ||||
2006 | 13.8 | 90 | 12.8 | 93 | 4.1 | 93 | |||||||
2005 | 14.7 | 97 | 12.7 | 93 | 4.0 | 93 | |||||||
2004 | 14.5 | 96 | 12.1 | 89 | 4.3 | 100 | |||||||
2003 | 13.7 | 93 | 12.2 | 90 | 3.9 | 90 |
*represents our proportionate ownership interestnuclear generating facilities.
The supply of fuel for these nuclear generating stationsfacilities includes the:
CENG has commitments that provide for quantities of uranium, conversion, enrichment, and fabrication of fuel assemblies to substantially meet expected requirements for the next several years at these nuclear generating facilities.
The nuclear fueluranium markets are competitive, and while prices can be volatile; however, we dovolatile, CENG does not anticipate any significant problems in meeting ourits future supply requirements.
Storage of Spent Nuclear Fuel—Federal FacilitiesFuelOne of the issues associated with the operation and decommissioning of nuclear generating facilities is disposal of spent nuclear fuel. There are no facilities for the reprocessing or permanent disposal of spent nuclear fuel currently in operation in the United States, and the NRC has not licensed any such facilities.
The Nuclear Waste Policy Act of 1982, (NWPA) requiredas amended, ("NWPA") requires the federal government, through the Department of Energy (DOE), to develop a repository for the disposal of spent nuclear fuel and high-level radioactive waste.
As required by Although the NWPA we are a party to contracts with the DOE to provide for disposal of spent nuclear fuel from our nuclear generating plants. The NWPA and our contracts with the DOE require payments to the DOE of one tenth of one cent (one mill) per kilowatt hour on nuclear electricity generated and sold to pay for the cost of long-term nuclear fuel storage and disposal. We continue to pay those fees into the DOE's Nuclear Waste Fund for our nuclear generating facilities. The NWPA and ourCENG's contracts with the DOE required the DOE to begin taking possession of spent nuclear fuel generated by nuclear generating units no later than
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January 31, 1998.1998, the DOE has failed to meet its obligation. The DOE's delay in taking possession of spent fuel has required CENG to undertake additional actions and incur costs to provide on-site dry fuel storage at all three of its nuclear sites. CENG has installed additional capacity at its independent spent fuel storage installation ("ISFSI") at Calvert Cliffs, has constructed an ISFSI at Ginna, and is constructing an ISFSI to be placed in service at Nine Mile Point in 2012.
ThePrior to 2010, the DOE hashad stated that it may not meet thatits obligation until 20172020 at the earliest. This delay has required that we undertake additional actionsDuring 2010, the DOE requested the withdrawal of its license application to provide on-site fuel storage at ouruse Yucca Mountain as a national repository for spent nuclear generating facilities, includingfuel. At this time, CENG is not able to determine whether the installationDOE will be able to commence meeting its obligation by 2020.
Each of on-site dry fuel storage capacity as described in more detail below.
In 2004,CENG's plant subsidiaries have filed complaints were filed against the federal government in the United StatesU.S. Court of Federal Claims seeking to recover damages caused by the DOE's failure to meet its contractual obligation to begin disposing of spent nuclear fuel by January 31, 1998. TheseThe cases are currently stayed, pending litigation in other related cases.
In connection with our purchase of Ginna, all of the former owner's rights and obligations related to recovery of damages for DOE's failure to meet its contractual obligations were assigned to us. However, we have an obligation to reimburse the former owner for up to $10 million of any recovered damages for such claims.
Storage of Spent Nuclear Fuel—On-Site FacilitiesCalvert Cliffs has a license Any funds received from the NRCDOE that represent the reimbursement of costs incurred prior to operate an on-site independent spent fuel storage installation that expiresNovember 6, 2009, the date we sold a 49.99% membership interest in 2012. We have storage capacity at Calvert Cliffs thatCENG to EDF, will accommodate spent fuel from operations through 2011. In addition, we can expand our temporary storage capacity at Calvert Cliffsbelong to meet future requirements until approximately 2025. Nine Mile Pointus, and Ginna are developing independent spent fuel storage installations at eachany funds representing the reimbursement of those facilities, which we expectcosts incurred after November 6, 2009 will belong to be completed in 2011 and 2010, respectively. Nine Mile Point and Ginna have sufficient storage capacity within the plant until the expected completion of the on-site independent spent fuel storage installations.CENG.
Cost for Decommissioning Nuclear FacilitiesWe are
When Constellation Energy sold a 49.99% membership interest in CENG on November 6, 2009, we deconsolidated CENG for financial reporting purposes and, as a result, the decommissioning trust funds were removed from our Consolidated Balance Sheets. CENG is obligated to decommission ourits nuclear power plants after these plants cease operation. Every two years,
Decommissioning activities are currently projected to be staged through the NRC requires us to demonstrate reasonable assurance that funds will be available to decommission2080 decade. Any changes in the sites. When BGE transferred allcosts or timing of its nuclear generating assets to our merchant energy business, it also transferreddecommissioning activities, or changes in the fund earnings, could affect the adequacy of the funds accumulated to paycover the decommissioning of the plants, and if there were to be a shortfall, additional funding would have to be provided by CENG. CENG has the ability to request funding assistance from both Constellation Energy and EDF, as the owners of CENG.
Calvert Cliffs
In March 2008, Constellation Energy, BGE, and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the Public Service Commission of Maryland (Maryland PSC), and certain State of Maryland officials. The settlement agreement became effective on June 1, 2008. Pursuant to the terms of the settlement agreement, BGE customers were relieved of the potential future liability for decommissioning Calvert Cliffs. At December 31, 2007,Cliffs Unit 1 and Unit 2. BGE will continue to collect the external Calvert Cliffs trust fund assets were $457.4 million.
Under the Maryland Public Service Commission's (Maryland PSC) order regarding the deregulation of$18.7 million annual nuclear decommissioning charge from all electric generation, BGE ratepayers must pay a total of $520 million, in 1993 dollars adjusted for inflation,customers through 2016 and continue to decommission Calvert Cliffs through fixed annual collections. BGE is collectingrebate this amount on behalf of Calvert Cliffs. Any costs to decommission Calvert Cliffs in excess of this $520 million, in 1993 dollars adjusted for inflation, must be paidresidential electric customers, as previously required by Calvert Cliffs. If BGE ratepayers have paid more than this amount at the time of decommissioning, Calvert Cliffs must refund the excess. If the cost to decommission Calvert Cliffs is less than the $520 million, in 1993 dollars adjusted for inflation, BGE's ratepayers are obligated to pay, Calvert Cliffs may keep the difference.
In 2006, BGE received approval from the Maryland PSC to continue previously approved annual customer collections for decommissioning of approximately $18.7 million through December 31, 2016. BGE will be required to submit a filing to determine the level of customer contributions after December 31, 2016. Senate Bill 1 which was enacted in June 2006, requires BGE to provide credits to residential electric customers equal to the amount collected for decommissioning annually for 10 years beginning January 1, 2007. Under the provisions of Senate Bill 1, we are required to apply the collection of the nuclear decommissioning trust funds over the ten year period beginning January 1, 2007 toward the fulfillment of the decommissioning obligations of BGE ratepayers. As discussed inItem 7. Management's Discussion and Analysis—Business Environment—Regulation—Maryland—Senate Bills 1 and 400 section, we have notified the State of Maryland of our intent to file an action challenging the legality of this Senate Bill 1 requirement.
The sellers of Nine Mile Point transferred a $441.7 million decommissioning trust fund to us at the time of sale. In return, we assumed all liability for the costs to decommission Unit 1 and 82% of the costs to decommission Unit 2. We believe that this amount is adequate to cover our responsibility for decommissioning Nine Mile Point to a greenfield status (restoration of the site so that it substantially matches the natural state of the surrounding properties and the site's intended use). At December 31, 2007, the Nine Mile Point trust fund assets were $610.2 million.
The seller of Ginna transferred $200.8 million in decommissioning funds to us. In return, we assumed all liability for the costs to decommission the unit. We believe that this amount will be sufficient to cover our responsibility for decommissioning Ginna to a greenfield status. At December 31, 2007, the Ginna trust fund assets were $263.2 million.2006.
Coal
We purchase the majority of our coal for electric generation under supply contracts with miningmine operators, and we acquire the remainder in the spot or forward coal markets. The actual fuel quantities required can vary substantially from year to year depending upon the relationship between energy prices and fuel costs, weather conditions, and operating requirements. We believe that we will be able to renew supply contracts as they expire or enter into contracts with other coal suppliers. Our primary coal burningcoal-burning facilities have the following requirements:
| Approximate Annual Coal Requirement (tons) | ||||
---|---|---|---|---|---|
Brandon | 2,800,000 | ||||
C. P. | 1,000,000 | ||||
H. A. | 800,000 |
CoalWe receive coal deliveries to these facilities are made by rail and barge. Over the past few years, we expanded our coal sources through a variety of methods, including restructuring our rail and terminal contracts, increasing the range of coals we can consume, adding synthetic fuel as an alternate source, and finding potential other coal supply sources including limited shipments from various international sources. While we primarily use coal produced from mines located in central and northern Appalachia, we are capable of switchingusing sub-bituminous coal from the Western United States at C.P. Crane and have the ability to switch to using imported coalscoal at Brandon Shores and H.A. Wagner to manage our coal supply. Synthetic fuel will no longer be burned as an alternate source since tax credits for synthetic fuel expired on December 31, 2007. The timely delivery of coal together with the maintenance of appropriate levels of inventory is necessary to allow for continued, reliable generation from these facilities.
As discussed in theEnvironmental Matters section, our Maryland coal-fired generating facilities must comply with the requirements of the Maryland Healthy Air Act (HAA), which requires reduction of sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury emissions. To comply with the HAA requirements, we
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are planning to burn domestic and/or import compliance coals (1.2 lb/mmbtu SO2 or less) at H.A. Wagner. The C.P. Crane station was converted to burn up to 100% sub-bituminous coal in June 2010. In March 2010, we completed installation of flue gas desulfurization (FGD) equipment on both Brandon Shores units. With the FGD installation, Brandon Shores now is able to burn higher sulfur coals (limit 6 lbs/mmbtu or approximately 3.5% sulfur) while simultaneously reducing station emissions. The blend of coals actually procured for Brandon Shores will be optimized to achieve the lowest delivered cost while complying with HAA limitations.
We own an undivided interest in the Keystone and Conemaugh electric generating plants in Western Pennsylvania. Our ownership interests in these plants are 20.99% in Keystone and 10.56% in Conemaugh. All of the Conemaugh and Keystone plants' annual coal requirements are purchased by the plant operators from regional suppliers on the open market. FGD equipment was installed on both of the Keystone units in 2009 and has been installed on both Conemaugh units since the mid-1990s. The sulfurFGD SO2 restrictions on coal are 6 lbs/mmbtu (or approximately 2.3%3.7% sulfur) for the Keystone plant and approximately 5.3%4.9 lbs/mmbtu (or 3% sulfur) for the Conemaugh plant. The blend of coal procured is optimized to ensure compliance with station emission limits at the lowest delivered cost.
The annual coal requirements for the ACE, Jasmin, and Poso plants, which are located in California, are supplied under contracts with mining operators. These plants are restricted to coal with sulfur content less than 2.0%4.0%.
The primary fuel source for Panther Creek and Colver generating facilities' primary fuel sourcefacilities is waste coal. These facilities meet their annual requirements through existing reserves of mined and processed waste coal and through supply agreements with various terms.
All of our coal requirements reflect historicalexpected generating levels. The actual fuel quantities required can vary substantially from historical generating levels depending upon the relationship between energy prices and fuel costs, weather conditions, and operating requirements. However, we believe that we will be able to obtain adequate quantities of coal to meet our requirements.
Gas
We purchase natural gas, storage capacity, and transportation, as necessary, for electric generation at certain plants. Some of our gas-fired units can use residual fuel oil or distillates instead of gas. Gas is purchased under contracts with suppliers on the spot market and forward markets, including financial exchanges and under bilateral agreements. The actual fuel quantities required can vary substantially from year to year depending upon the relationship between energy prices and fuel costs, weather conditions, and operating requirements. However, we believe that we will be able to obtain adequate quantities of gas to meet our requirements.
OilUnder normal burn practices,
From 2008 through 2010, our requirements for residual fuel oil (No. 6) amountamounted to approximately 1.0 million to 1.5less than 0.5 million barrels of low-sulfur oil per year. Deliveries of residual fuel oil are made from the suppliers' Baltimore Harbor and Philadelphia marine terminals for distribution to the various generating plant locations. Also, based on normal burn practices, we require approximately 8.0 million to 11.0 million gallons of distillates (No. 2 oil and kerosene) annually, but these requirements can vary substantially from year to year depending upon the relationship between energy prices and fuel costs, weather conditions, and operating requirements. Distillates are purchased from the suppliers' Baltimore truck terminals for distribution to the various generating plant locations. We have contracts with various suppliers to purchase oil at spot prices, and for future delivery, to meet our requirements.
Competition
We encounter competition from companies of various sizes, having varying levels of experience, financial and human resources, and differing strategies.
We face competition in the market for energy, capacity, and ancillary services. In our merchant energyNewEnergy business, we compete with international, national, and regional full servicefull-service energy providers, merchants, and producers to obtain competitively priced supplies from a variety of sources and locations, and to utilize efficient transmission, transportation, or storage. We principally compete on the basis of price, customer service, reliability, and availability of our products.
With respect to power generation,our Generation business, we compete in the operation of energy-producing projects, and our competitors in this business are both domestic and international organizations, including various utilities, industrial companies and independent power producers (including affiliates of utilities, financial investors, banks and investment banks), some of which have greater financial resources.
StatesMany states are considering different types of regulatory initiatives concerning competition in the power and gas industry, which makes a general assessment of the state of competitive assessmentmarkets difficult. Increased competition that resulted from some of these initiatives in several states contributed in some instances to a reduction in electricity prices and put pressure on electric utilities to lower their costs, including the cost of purchased electricity. Many states continue to support or expand retail competition and industry restructuring. Other states that were considering deregulationrestructuring have slowed their plans or postponed consideration of deregulation.competitive markets. In addition, certain previouslystates that have restructured states are considering reregulation of their retail markets.energy markets routinely consider new market rules including return to monopoly service measures that could result in more limited opportunities for competitive energy suppliers like Constellation Energy. While there is significant activity in this area, we believe there is
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adequate growth potential in the current deregulated market and that further market changes could provide additional opportunities for our merchant energy business.competitive market.
As theThe market for commercial, industrial, and governmental energy supply continues to grow and we have experiencedcontinue to experience increased competition from energy and non-energy market participants on a regional and national basis in our retail competitivecustomer supply activities. The increase inStrong retail competition and the impact of wholesale power prices compared to the rates charged by local utilities has, in certain circumstances, reducedaffects the margins thatcontract margin we realizereceive from our customers. However, we believe that ourRecent economic conditions have increased overall margins reflecting an appropriate return on capital to support the business. Our experience and expertise in assessing and managing risk and our strong focus on customer service willshould help us to remain competitive during volatile or otherwise adverse market circumstances.
Merchant EnergyGeneration and NewEnergy Operating Statistics
| 2007 | 2006 | 2005 | 2004 | 2003 | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Revenues(In millions) | ||||||||||||||||
Mid-Atlantic Region | $ | 3,462.2 | $ | 2,813.5 | $ | 2,283.9 | $ | 1,925.6 | $ | 1,696.2 | ||||||
Plants with Power Purchase Agreements | 657.3 | 650.5 | 665.9 | 555.3 | 463.3 | |||||||||||
Competitive Supply—Retail | 9,086.3 | 8,014.7 | 6,942.3 | 4,280.0 | 2,567.7 | |||||||||||
Competitive Supply—Wholesale | 5,469.4 | 5,612.7 | 4,672.3 | 3,353.8 | 2,703.9 | |||||||||||
Other | 69.3 | 74.8 | 58.0 | 73.6 | 45.1 | |||||||||||
Total Revenues | $ | 18,744.5 | $ | 17,166.2 | $ | 14,622.4 | $ | 10,188.3 | $ | 7,476.2 | ||||||
Generation(In millions)—MWH* | 51.6 | 59.1 | 60.2 | 55.3 | 51.6 | |||||||||||
*Includes output from gas-fired plants until sale in December 2006.
| 2010 | 2009 | 2008 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Gross Margin(In millions) | |||||||||||
Generation (1) | $ | 800 | $ | 2,082 | $ | 2,042 | |||||
NewEnergy | 1,244 | 1,079 | 1,040 | ||||||||
Total Gross Margin | $ | 2,044 | $ | 3,161 | $ | 3,082 | |||||
Generation(In millions)—MWH (1)(2) | 35.1 | 46.0 | 50.9 | ||||||||
Operating statistics do not reflect the elimination of intercompany transactions.
Baltimore Gas and Electric Company
BGE is an electric transmission and distribution utility company and a gas distribution utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland. BGE is regulated by the Maryland PSC and Federal Energy Regulatory Commission (FERC) with respect to rates and other aspects of its business.
BGE's electric service territory includes an area of approximately 2,300 square miles. There are no municipal or cooperative wholesale customers within BGE's service territory. BGE's gas service territory includes an area of approximately 800 square miles.
BGE's electric and gas revenues come from many customers—residential, commercial, and industrial.
Electric Business
Electric Competition
Deregulation
Effective July 1, 2000,Maryland has implemented electric customer choice and competition among electric suppliers was implemented in Maryland.suppliers. As a result, of the deregulation of electric generation, all customers can choose their electric energy supplier.supplier, which includes subsidiaries of Constellation Energy. While BGE does not sell electric commodityelectricity to all customers in its service territory, BGE continues to deliver electricity to all customers and provides meter reading, billing, emergency response, and regular maintenance.
Standard Offer Service
BGE is obligated by the Maryland PSC to provide market-based standard offer service (SOS) to all of its electric customers.customers who elect not to select a competitive energy supplier. The SOS rates charged recover BGE's wholesale power supply costs and include an administrative fee. The administrative fee includes a shareholder return component and an incremental cost component. As discussed inItem 7. Management's Discussion and Analysis—Regulated Electric Business—Senate Bill 1 CreditsBusiness section, BGE is now requiredresumed collection of the shareholder return portion of the residential SOS administrative charge, which had been eliminated under Maryland Senate Bill 1, from June 1, 2008 through May 31, 2010 without having to creditrebate it to all residential electric customers. Starting June 1, 2010, BGE provides all residential electric customers a credit for the shareholderresidential return component of the administrative charge for residential SOS service.through December 2016.
Bidding to supply BGE's market-based standard offer service will occurSOS occurs from time to time through a competitive bidding process approved by the Maryland PSC. Successful bidders, which may include subsidiaries of Constellation Energy, will execute contracts with BGE for varying terms.terms of three months or two years.
Commercial and Industrial Customers
BGE is obligated by the Maryland PSC to provide market-based standard offer serviceseveral variations of SOS to commercial and industrial customers for varying periods beyond June 30, 2004, depending on customer load.
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Residential Customers
Residential customers went to full market rates in January 2008. Pursuant to the order issued by the Maryland PSC in October 2009 approving our transaction with EDF, Constellation Energy agreed to fund a one-time per customer distribution rate credit for BGE residential customers, in 2010, totaling $110.5 million, which approximated $100 per customer. In August 2006,December 2009, BGE filed a tariff with the Maryland PSC stating we would give residential customers a rate credit of exactly $100 per customer. As a result, BGE provided rate credits totaling $112.4 million. Constellation Energy made a $66 million equity contribution to BGE in December 2009 to fund the after-tax amount of the rate credit as required by the Maryland PSC order.
In 2010, the Maryland PSC issued ana rate order indefinitely extending the obligation of Maryland utilitiesauthorizing BGE to provide SOS service for those commercialincrease electric and industrial customers for which market-based standard offer service was scheduled to expire at the end of May 2007. The extended service will be provided on substantially the same terms as under the then existing service, except that wholesale biddinggas distribution rates for service to some customers will be conducted more frequently.
BGE's obligation to provide market-based standard offer service to its largest commercial and industrial customers expiredrendered on May 31, 2005. BGE continues to provide an hourly-priced market-based standard offer service to those customers.
Residential Customers
As a result of the November 1999 Maryland PSC order regarding the deregulation of electric generation in Maryland, BGE's residential electric base rates were frozen until July 2006. Subsequent orders of the Maryland PSC specified that BGE would procure the power to serve residential customers beginning July 2006 via auctions to be conducted in late 2005 and early 2006. The procured power costs of these auctions would have resulted in an average electric residential customer bill increase of 72%. In June 2006, Senate Bill 1 was enacted, which, among other things:
We further discuss the impacts of Senate Bill 1 and other recent legislation inItem 7. Management's Discussion and Analysis—Business Environment—Regulation—Maryland—Senate Bills 1 and 400 section.4, 2010. We discuss the market risk of our regulated electric businessthis rate order in more detail inItem 7. Management's Discussion and Analysis—Market RiskRegulation—Maryland—Base Rates section.
Electric Load Management
BGE has implemented various programs for use when system-operating conditions or market economics indicate that a reduction in load would be beneficial. These programs include:
These programs generally take effect on summer days when demand and/or wholesale prices are relatively high and had the effect of reducing BGE's system peak load by 248 MW during the summer period in 2007.
BGE is also developing other programs designed to help BGE manage its peak demand, improve system reliability and improve service to customers by giving customers greater control over their energy use.
Recently, In August 2010, the Maryland PSC approved full implementationa comprehensive smart grid initiative for BGE which includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of approximately $480 million. Under a demand response program, which will enablegrant from the DOE, BGE is a recipient of $200 million in federal funding for our smart grid and other related initiatives. This grant allows BGE to regulate participating customer energy use throughbe reimbursed for smart grid and other related expenditures up to $200 million, substantially reducing the usetotal cost of programmable thermostats and air conditioner load control devices at customer premises during peak demand periods.these initiatives.
The Maryland PSC also approved a full portfolio of conservation programs for implementation in 2009 as well as a customer surcharge to recover the implementation of an advanced metering pilot program, which will enable BGE to improve customer service and offer special pricing as an incentive to customers to reduce energy use during peak demand periods and to detect power outages electronically. BGE has also initiated a program that will provide incentives to customers to use energy efficient products and to take other actions to conserve energy. We also discuss the demand response initiatives inItem 7. Management's Discussion and Analysis—Regulation—Maryland—Maryland PSC section.associated costs.
Transmission and Distribution Facilities
BGE maintains approximately 250240 substations and approximately 1,300 circuit miles of transmission lines throughout central Maryland. BGE also maintains approximately 24,00024,800 circuit miles of distribution lines. The transmission facilities are connected to those of neighboring utility systems as part of PJM.PJM Interconnection (PJM). Under the PJM Tariff and various agreements, BGE and other market participants can use regional transmission facilities for energy, capacity, and ancillary services transactions, including emergency assistance.
We discuss various FERC initiatives relating to wholesale electric markets in more detail inItem 7. Management's Discussion and Analysis—Federal Regulation section.
BGE Electric Operating Statistics
| 2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Revenues(In millions) | |||||||||||||||||
Residential | $ | 1,514.9 | $ | 1,092.1 | $ | 1,066.6 | $ | 1,015.8 | $ | 959.0 | |||||||
Commercial | |||||||||||||||||
Excluding Delivery Service Only | 577.4 | 733.4 | 722.1 | 708.9 | 694.2 | ||||||||||||
Delivery Service Only | 217.0 | 149.4 | 107.5 | 78.6 | 66.1 | ||||||||||||
Industrial | |||||||||||||||||
Excluding Delivery Service Only | 31.6 | 46.8 | 52.8 | 92.3 | 137.0 | ||||||||||||
Delivery Service Only | 27.8 | 26.2 | 28.0 | 21.3 | 18.2 | ||||||||||||
System Sales and Deliveries | 2,368.7 | 2,047.9 | 1,977.0 | 1,916.9 | 1,874.5 | ||||||||||||
Other (A) | 87.0 | 68.0 | 59.5 | 50.8 | 47.1 | ||||||||||||
Total | $ | 2,455.7 | $ | 2,115.9 | $ | 2,036.5 | $ | 1,967.7 | $ | 1,921.6 | |||||||
Distribution Volumes(In thousands)—MWH | |||||||||||||||||
Residential | 13,365 | 12,886 | 13,762 | 13,313 | 12,754 | ||||||||||||
Commercial | |||||||||||||||||
Excluding Delivery Service Only | 4,364 | 6,325 | 7,847 | 9,286 | 9,937 | ||||||||||||
Delivery Service Only | 11,921 | 9,392 | 7,967 | 5,767 | 4,982 | ||||||||||||
Industrial | |||||||||||||||||
Excluding Delivery Service Only | 287 | 467 | 614 | 1,429 | 2,556 | ||||||||||||
Delivery Service Only | 3,175 | 2,988 | 3,122 | 2,562 | 1,780 | ||||||||||||
Total | 33,112 | 32,058 | 33,312 | 32,357 | 32,009 | ||||||||||||
Customers(In thousands) | |||||||||||||||||
Residential | 1,103.1 | 1,093.3 | 1,084.1 | 1,072.1 | 1,061.7 | ||||||||||||
Commercial | 116.7 | 115.5 | 114.7 | 113.6 | 112.1 | ||||||||||||
Industrial | 5.5 | 5.2 | 5.0 | 4.8 | 4.9 | ||||||||||||
Total | 1,225.3 | 1,214.0 | 1,203.8 | 1,190.5 | 1,178.7 | ||||||||||||
| 2010 | 2009 | 2008 | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Revenues(In millions) | ||||||||||||
Residential | ||||||||||||
Excluding Delivery Service Only | $ | 1,808.6 | $ | 1,864.0 | $ | 1,688.3 | ||||||
Delivery Service Only | 48.1 | 14.3 | 7.6 | |||||||||
Commercial | ||||||||||||
Excluding Delivery Service Only | 467.4 | 531.2 | 604.0 | |||||||||
Delivery Service Only | 249.5 | 245.0 | 222.8 | |||||||||
Industrial | ||||||||||||
Excluding Delivery Service Only | 28.7 | 30.4 | 31.3 | |||||||||
Delivery Service Only | 25.6 | 29.1 | 27.1 | |||||||||
System Sales and Deliveries | 2,627.9 | 2,714.0 | 2,581.1 | |||||||||
Other (1) | 124.4 | 106.7 | 98.6 | |||||||||
Total | $ | 2,752.3 | $ | 2,820.7 | $ | 2,679.7 | ||||||
Distribution Volumes(In thousands)—MWH | ||||||||||||
Residential | ||||||||||||
Excluding Delivery Service Only | 12,344 | 12,394 | 12,670 | |||||||||
Delivery Service Only | 1,490 | 457 | 353 | |||||||||
Commercial | ||||||||||||
Excluding Delivery Service Only | 3,707 | 3,945 | 3,957 | |||||||||
Delivery Service Only | 12,537 | 11,753 | 11,739 | |||||||||
Industrial | ||||||||||||
Excluding Delivery Service Only | 267 | 270 | 242 | |||||||||
Delivery Service Only | 2,519 | 2,757 | 3,002 | |||||||||
Total | 32,864 | 31,576 | 31,963 | |||||||||
Customers(In thousands) | ||||||||||||
Residential | 1,114.7 | 1,111.9 | 1,108.5 | |||||||||
Commercial | 118.6 | 118.5 | 117.6 | |||||||||
Industrial | 5.5 | 5.3 | 5.3 | |||||||||
Total | 1,238.8 | 1,235.7 | 1,231.4 | |||||||||
Operating statistics do not reflect the elimination of intercompany transactions.
"Delivery service only" refers to BGE's delivery of commodityelectricity that was purchased by the customer from an alternate supplier.
Gas Business
The wholesale price of natural gas as a commodity is not subject to regulation. All BGE gas customers have the option to purchase gas from alternative suppliers, including subsidiaries of Constellation Energy. BGE continues to deliver gas to all customers within its service territory. This delivery service is regulated by the Maryland PSC.
BGE also provides customers with meter reading, billing, emergency response, regular maintenance, and balancing services.
Approximately 50% of the gas delivered on BGE's distribution system is for customers that purchase gas from alternative suppliers. These customers are charged fees to recover the costs BGE incurs to deliver the customers' gas through our distribution system.
In December 2005, the Maryland PSC issued an order granting BGE a $35.6 million annual increase in its gas baseA market-based rates which are the rates the Maryland PSC allows BGEincentive mechanism applies to charge its customers for the cost of providing them delivery service plus a profit. In December 2006, the Baltimore City Circuit Court upheld the rate order. However, certain parties have filed an appeal with the Court of Special Appeals. We cannot provide assurance that the Maryland PSC's order will not be reversed in whole or in part or that certain issues will not be remanded to the Maryland PSC for reconsideration.
For customers that buy their gas from BGE, there is a market-based rates incentive mechanism.BGE. Under this market-based rates incentive mechanism, ourBGE's actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between ourBGE's actual cost and the market index is shared equally between shareholders and customers.
BGE must secure fixed-price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the market-based rates incentive mechanism.
BGE purchases themeets its natural gas it resells to customers directly from many producers and marketers. BGE hasload requirements through firm pipeline transportation and storage agreements that expire from 2008 to 2027.entitlements.
BGE's current pipeline firm transportation entitlements to serve BGE'sits firm loads are 338,053 dekatherms (DTH)DTH per day.
BGE's current maximum storage entitlements are 248,153297,091 DTH per day. To supplement its gas supply at times of heavy winter demands and to be available in temporary emergencies affecting gas supply, BGE has:
BGE has under contract sufficient volumes of propane for the operation of the propane air facility and is capable of liquefying sufficient volumes of natural gas during the summer months for operations of its liquefied natural gas facility during peak winter periods.
BGE historically has been able to arrange short-term contracts or exchange agreements with other gas companies in the event of short-term disruptions to gas supplies or to meet additional demand.
BGE also participates in the interstate markets by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Earnings from these activities are shared between shareholders and customers. BGE makes these sales as part of a program to balance ourits supply of, and cost of, natural gas.
BGE Gas Operating Statistics
| 2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Revenues(In millions) | |||||||||||||||||
Residential | |||||||||||||||||
Excluding Delivery Service Only | $ | 552.0 | $ | 490.2 | $ | 558.5 | $ | 478.0 | $ | 444.5 | |||||||
Delivery Service Only | 19.0 | 20.6 | 23.2 | 14.2 | 13.6 | ||||||||||||
Commercial | |||||||||||||||||
Excluding Delivery Service Only | 154.1 | 148.9 | 174.4 | 135.4 | 128.6 | ||||||||||||
Delivery Service Only | 41.2 | 35.9 | 31.9 | 28.0 | 24.6 | ||||||||||||
Industrial | |||||||||||||||||
Excluding Delivery Service Only | 7.8 | 7.5 | 10.5 | 9.4 | 11.5 | ||||||||||||
Delivery Service Only | 22.1 | 19.3 | 12.4 | 7.8 | 11.4 | ||||||||||||
System Sales and Deliveries | 796.2 | 722.4 | 810.9 | 672.8 | 634.2 | ||||||||||||
Off-System Sales | 157.4 | 168.6 | 154.7 | 77.2 | 84.8 | ||||||||||||
Other | 9.2 | 8.5 | 7.2 | 7.0 | 7.0 | ||||||||||||
Total | $ | 962.8 | $ | 899.5 | $ | 972.8 | $ | 757.0 | $ | 726.0 | |||||||
Distribution Volumes(In thousands)—DTH | |||||||||||||||||
Residential | |||||||||||||||||
Excluding Delivery Service Only | 39,199 | 33,019 | 39,107 | 39,080 | 40,894 | ||||||||||||
Delivery Service Only | 4,310 | 3,948 | 5,423 | 6,053 | 6,640 | ||||||||||||
Commercial | |||||||||||||||||
Excluding Delivery Service Only | 12,464 | 11,683 | 14,133 | 13,248 | 13,895 | ||||||||||||
Delivery Service Only | 30,367 | 25,695 | 28,993 | 34,120 | 29,138 | ||||||||||||
Industrial | |||||||||||||||||
Excluding Delivery Service Only | 658 | 604 | 921 | 865 | 1,143 | ||||||||||||
Delivery Service Only | 17,897 | 20,325 | 19,357 | 14,310 | 18,399 | ||||||||||||
System Sales and Deliveries | 104,895 | 95,274 | 107,934 | 107,676 | 110,109 | ||||||||||||
Off-System Sales | 19,963 | 19,738 | 17,209 | 9,914 | 12,859 | ||||||||||||
Total | 124,858 | 115,012 | 125,143 | 117,590 | 122,968 | ||||||||||||
Customers(In thousands) | |||||||||||||||||
Residential | 602.3 | 597.1 | 590.9 | 582.0 | 575.2 | ||||||||||||
Commercial | 42.7 | 42.3 | 42.0 | 41.6 | 41.1 | ||||||||||||
Industrial | 1.2 | 1.2 | 1.2 | 1.2 | 1.2 | ||||||||||||
Total | 646.2 | 640.6 | 634.1 | 624.8 | 617.5 | ||||||||||||
| 2010 | 2009 | 2008 | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Revenues(In millions) | ||||||||||||
Residential | ||||||||||||
Excluding Delivery Service Only | $ | 427.0 | $ | 460.7 | $ | 567.8 | ||||||
Delivery Service Only | 22.1 | 19.0 | 19.0 | |||||||||
Commercial | ||||||||||||
Excluding Delivery Service Only | 109.0 | 129.1 | 161.8 | |||||||||
Delivery Service Only | 39.8 | 40.4 | 46.4 | |||||||||
Industrial | ||||||||||||
Excluding Delivery Service Only | 5.2 | 6.4 | 8.1 | |||||||||
Delivery Service Only | 16.7 | 15.2 | 14.5 | |||||||||
System Sales and Deliveries | 619.8 | 670.8 | 817.6 | |||||||||
Off-System Sales | 79.8 | 81.1 | 197.7 | |||||||||
Other | 9.8 | 6.4 | 8.7 | |||||||||
Total | $ | 709.4 | $ | 758.3 | $ | 1,024.0 | ||||||
Distribution Volumes(In thousands)—DTH | ||||||||||||
Residential | ||||||||||||
Excluding Delivery Service Only | 37,791 | 37,889 | 37,675 | |||||||||
Delivery Service Only | 4,857 | 4,270 | 4,119 | |||||||||
Commercial | ||||||||||||
Excluding Delivery Service Only | 11,606 | 12,066 | 12,205 | |||||||||
Delivery Service Only | 24,329 | 25,046 | 29,289 | |||||||||
Industrial | ||||||||||||
Excluding Delivery Service Only | 595 | 635 | 650 | |||||||||
Delivery Service Only | 19,750 | 20,826 | 18,432 | |||||||||
System Sales and Deliveries | 98,928 | 100,732 | 102,370 | |||||||||
Off-System Sales | 14,711 | 17,542 | 18,782 | |||||||||
Total | 113,639 | 118,274 | 121,152 | |||||||||
Customers(In thousands) | ||||||||||||
Residential | 608.6 | 606.8 | 605.0 | |||||||||
Commercial | 42.9 | 42.9 | 42.8 | |||||||||
Industrial | 1.1 | 1.1 | 1.1 | |||||||||
Total | 652.6 | 650.8 | 648.9 | |||||||||
Operating statistics do not reflect the elimination of intercompany transactions.
"Delivery service only" refers to BGE's delivery of commoditygas that was purchased by the customer from an alternate supplier.
Franchises
BGE has nonexclusive electric and gas franchises to use streets and other highways that are adequate and sufficient to permit it to engage in its present business. Conditions of the franchises are satisfactory.
Energy Projects and Services
We offer energy projects and services designed primarily to provide energy solutions to large commercial, industrial and governmental customers. These energy products and services include:
Home Products and Gas Retail Marketing
We offer services to customers in Maryland including:
Consolidated Capital Requirements
Our total capital requirements for 20072010 were $1,665 million.$1.0 billion. Of this amount, $1,263 million$0.4 billion was used in our nonregulatedGeneration and NewEnergy businesses and $402 million$0.6 billion was used in our regulated business. We estimate our total capital requirements will be $2.5$1.0 billion in 2008.2011.
We continuously review and change our capital expenditure programs, so actual expenditures may vary from the estimate above. We discuss our capital requirements further inItem 7. Management's Discussion and Analysis—Capital Resources section.
The development (involving site selection, environmental assessments, and permitting), construction, acquisition, and operation of electric generating and distribution facilities are subject to extensive federal, state, and local environmental and land use laws and regulations. From the beginning phases of development to the ongoing operation of existing or new electric generating and distribution facilities, our activities involve compliance with diverse laws and regulations that address emissions and impacts to air and water, protection of natural and cultural resources, and chemical and waste handling and disposal.
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We continuously monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance. Our capital expenditures were approximately $190 million$1.2 billion during the five-year period 2003-20072006-2010 to comply with existing environmental standards and regulations.regulations, including the Maryland HAA. Our estimated environmental capital requirements for the next three years are approximately $575$35 million in 2008, $3902011, $20 million in 2009,2012, and $30$25 million in 2010.2013.
Air Quality
Federal
The Clean Air Act (CAA) created the basic framework for the federal and state regulation of air pollution.
National Ambient Air Quality Standards (NAAQS)
The NAAQS are federal air quality standards authorized under the Clean Air ActCAA that establish maximum ambient air concentrations for the following specific pollutants: ozone (smog), carbon monoxide, lead, particulates, sulfur dioxides (SOSO2), and nitrogen dioxides (NO2).dioxide.
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 nitrogen oxide (NONOx) emissions from fossil fuel-fired generating facilities located primarily in the Eastern United States.
In December 2008, the United States Court of Appeals for the District of Columbia Circuit reversed its July 2008 decision to fully vacate CAIR, and instead, remanded the issue to the EPA for reconsideration with CAIR requirements to remain in effect until the EPA takes further action. The uncertainty around the adoption of CAIR has not resulted in a material change to our emissions reduction plan in Maryland as the emissions reduction requirements of Maryland's HAA and Clean Power Rule (CPR) are more stringent and applied sooner than those under CAIR. However, as CAIR is replaced, it could affect the market prices of SO2 and NOx emission allowances, which could in turn affect our financial results.
In July 2010, the EPA proposed regulations to replace the regional cap-and-trade program under CAIR with a program that would require each of 31 eastern states and the District of Columbia to reduce SO2 and NOX emissions. Depending on the scope of any final regulations that may be adopted by the EPA, which is expected to occur in July 2011, and any plans that may be adopted by the states in which our plants are located, additional regulation could result in additional compliance requirements and costs that could be material.
In January 2010, the EPA proposed rules to adopt NAAQS for ozone that are stricter than the NAAQS adopted in March 2008, based on the EPA's reevaluation of scientific evidence about ozone and ozone's effects on humans and the environment. The final standard is expected to be adopted in 2011. In June 2010, the EPA adopted a stricter NAAQS for SO2. We are unable to determine the impact that complying with the stricter NAAQS for ozone or SO2 will have on our financial results until the states in which our generating facilities are located adopt plans to meet the new standards. However, costs associated with compliance with these plans could be material.
In December 2006, the United States Court of Appeals for the District of Columbia Circuit ruled that a requirementrequirements to impose fees on large emissions sources in areas that have not attained the NAAQS based on the previous ozone standard (Section 185 fees), which had been rescinded by the EPA in May 2005, remained applicable retroactive to November 2005 and remanded the issue to the EPA for reconsideration. A petition to the United States Supreme Court to hear an appeal was denied in January 2008. The EPA has announced that it intends to propose regulations by the summer of 2008 to address howissued Section 185 fees will be handled. In addition,fee guidance to the exact method of computing these fees has not been established and will dependstates in part onJanuary 2010 that contained flexible state implementation regulations thatalternatives to meet the requirements. States in which we operate have not been proposed. Consequently,finalized their approach for implementing the requirements and consequently, we are unable to estimate the ultimate financial impact of this matter in light of the uncertainty surrounding the anticipated EPA and state rulemakings. However, the final resolution of this matter, and any fees that are ultimately assessed could have a material impact on our financial results.
In September 2006, the EPA adopted a stricter NAAQS for particulate matter. We are unable to determine the impact that complying with the stricter NAAQS for particulate matter will have on our financial results until the states in which our generating facilities are located adopt plans to meet the new standard.
Hazardous Air Pollutant Emissions
In March 2005, the EPA finalized the Clean Air Mercury Rule (CAMR) to reduce the emissions of mercury from coal-fired facilities through a market-based cap and trade program. CAMR was to affect all coal or waste coal fired boilers at our generating facilities. However, in February 2008, the United States Court of Appeals for the District of Columbia Circuit struck down CAMR. At this time, we cannot predict what actionsIn response to that decision and as a result of a court settlement with a number of parties, the EPA will take in responseis under a consent order to the court's decision. However, any actionpropose a rule by March 2011 and to finalize new hazardous air pollutant emission standards by November 2011. Any new standards that requiresrequire the installation of additional emissions control technology beyond what is required under Maryland's Healthy Air ActHAA and Clean Power Rule,CPR, which are discussed
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below, may require us to incur additional costs, which could have a material effect on our financial results.
New Source Review
In connection with its enforcement of the Clean Air Act'sCAA's new source review requirements, in 2000, the EPA requested information relating to modifications made to our Brandon Shores, C.P. Crane, and H. A. Wagner plants located in Maryland. The EPA also sent similar, but narrower, information requests to Keystone and Conemaugh, two of our newer Pennsylvania waste-coalcoal burning plants in which we have an ownership interest. We responded to the EPA in 2001, and as of the date of this report the EPA has taken no further action.
As discussed inNote 12 to Consolidated Financial Statements, in January 2009, the EPA issued a Notice of Violation to one of our subsidiaries alleging that the Keystone plant located in Pennsylvania, of which we own a 20.99% interest, performed various capital projects without complying with the new source review requirements.
Based on the level of emissions control that the EPA and states are seeking in these new source review enforcement actions, we believe that material additional costs and penalties could be incurred, and planned capital expenditures could be accelerated, if the EPA was successful in any future actions regarding our facilities.
State
Maryland has adopted the Healthy Air Act (HAA)HAA and the Clean Power Rule (CPR),CPR, which establish annual SO2, NOx, and mercury emission caps for specific coal-fired units in Maryland, including units located at three of our facilities. The requirements of the HAA and the CPR for SO2, NOx, and mercury emissions are more stringent and apply sooner than those required under CAIR.federal requirements. Likewise, Massachusetts has comprehensive air emissions standards in place that are more stringent than the federal standards, so impending regulations are not anticipated to cause additional costs to our natural gas and oil-fired units in Massachusetts. In addition, Pennsylvania, hasregulations adopted regulations requiring coal-fired generating facilities located in Pennsylvania to reduce mercury emissions.emissions were ruled invalid by a Pennsylvania court in January 2009.
Several other states Maryland has also adopted opacity regulations consistent with its commitment to resolve long-standing industry concerns about the prior regulations' continuous compliance requirements and is in the northeastern U.S. continueprocess of obtaining the EPA's approval of Maryland's state implementation plan (SIP) for these regulations. While EPA approval of Maryland's SIP is being obtained, the opacity regulations are being implemented in a manner that will enable our plants to consider more stringent and earlier SO2, NOx, and mercury emissions reductions than those requiredremain in compliance. We anticipate that the regulations under CAIR or what would have been required under CAMR.the EPA-approved SIP will be consistent with the regulations as currently implemented.
Capital Expenditure EstimatesEstimates—Air Quality
We expect to incur additional environmental capital spending as a result of complying with the air quality laws and regulations discussed above. To comply with CAIR, HAA and CPR, we will install additional air emission control equipment at our coal-fired generating facilities in Maryland and at our co-owned coal-fired facilities in Pennsylvania to meet air quality standards. We include in our estimated environmental capital requirements capital spending for these air quality projects, which we expect will be approximately $550$20 million in 2008, $350 million in 2009,2011, $15 million in 20102012, $25 million in 2013 and $25 million from 2011-2012.2014-2015.
Our estimates are subject to significant uncertainties including the timing of any additional federal and/or state regulations or legislation, such as any regulations adopted by the EPA in response to the court decision striking down CAMR, the implementation timetables for such regulation or legislation, and the specific amount of emissions reductions that will be required at our facilities. As a result, we cannot predict our capital spending or the scope or timing of these projects with certainty, and the actual expenditures, scope, and timing could differ significantly from our estimates.
We believe that the additional air emission control equipment we plan to install will meet the emission reduction requirements under CAIR, HAA and CPR. If additional emission reductions still are required, we will assess our various compliance alternatives and their related costs, and although we cannot yet estimate the additional costs we may incur, such costs could be material.
Global Climate Change
AlthoughIn response to the anticipated challenges of global climate change, we believe it is imperative to slow, stop and reverse the growth in greenhouse gas emissions. Climate change could pose physical risks, such as more frequent or more extreme weather events, that could affect our systems and operations; however, uncertainty remains as to the timing and extent of any direct, climate-related impacts to our systems and operations. Extreme weather can affect the supply of and demand for electricity, natural gas and fuels and these changes may impact the price of energy commodities in both the spot market and the forward market, which may affect our financial results. In addition, extreme weather typically increases demand for electricity and gas from BGE's customers.
There is continued likelihood that greenhouse gas emissions regulation will eventually occur at the international or federal level and/or continue to occur at the state level although considerable uncertainty remains as to the nature and timing of such regulation. Climate-related legislation was introduced in the last several United States Congress sessions but was not enacted. In September 2009, the EPA issued an "endangerment and
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cause or contribute finding" for greenhouse gases under the Clean Air Act and in 2010 finalized changes to its air construction and operating permit programs to incorporate greenhouse gases as pollutants subject to air permits. Beginning in 2011, in certain instances, additional greenhouse gas emissions regulation, thereresulting from the construction or modification of large facilities subject to the EPA's permit programs, which include power plants, will be required to be controlled through the use of the best available control technology, as determined by the EPA, before an air emissions permit will be issued. If we were to modify our generating plants, our costs to comply with these requirements could be material depending on the modifications made.
Maryland and Massachusetts are participants in the Northeast Regional Greenhouse Gas Initiative (RGGI). Under RGGI, the states auction carbon dioxide (CO2) allowances associated with power plants, which include plants owned by us. Auctions have occurred quarterly since September 2008. Although we did not incur material costs in these auctions, we could incur material costs in the future to purchase allowances necessary to offset CO2 emissions from our plants. Although we participate in RGGI, we believe a patchwork of climate policy and regulatory approaches across different states, regions or industry sectors has the potential to inequitably raise costs to particular businesses and/or drive the reallocation of emissions without actually achieving the desired overall reduction of emissions.
In addition, California has adopted regulations requiring our generating facilities in California to submit greenhouse gas emissions data to the state. More recently, in December 2010, the California Air Resources Board approved a declining cap and trade program for electricity suppliers beginning in 2012 aimed at achieving a 15% reduction in CO2 emissions by 2020 as compared with 2012. It is an increasing likelihood that such regulation will occur atnot possible to determine the scope of the impact of this program on our business or financial results until the details of the program are made public, but the impact could be material.
We continue to monitor international developments and proposed federal and/orand state level.legislation and regulations and evaluate the potential impact on our operations. In the event that additional greenhouse gas emissions reduction legislation or regulations are enacted, we will assess our various compliance alternatives, which may include installation of additional environmental controls, modification of operating schedules or the closure of one or more of our coal-fired generating facilities. Anyfacilities, and our compliance costs we incur could have a material impact on our financial results.be material.
However, to the extent greenhouse gas emissions are regulated through a federal, mandatory cap and trade greenhouse gas emissions program, we believe our business could also benefit. Our generation fleet currently has a carbon dioxide (COan overall CO2) emission rate that is lower than the industry average with more than 60%a substantial amount of the fleet's output coming from low carbon dioxide emitting nuclear and hydroelectric plants, which generate significantly lower CO2 emissions than fossil fuel plants. Our global commodities business hasWe also have experience trading in the markets for emissions allowances and renewable energy credits.
In accordance with HAA requirements, Maryland became a full participantcredits and our NewEnergy business has expertise in the Northeast Regional Greenhouse Gas Initiative (RGGI) in April 2007. In October 2007, under RGGI, the Maryland Department of the Environment proposed auctioning 90% of CO2 allowances associated with Maryland's power plants, which include plants owned by us. If this proposal is enacted, we could incur material costsproviding renewable energy products and services to purchase CO2 allowances necessary to offset emissions from our plants.
In addition, California has adopted regulations requiring our generating facilities in California to submit greenhouse gas emissions data to the state, which the state intends to use to develop a plan to reduce greenhouse gas emissions.
We continue to evaluate the potential impact of the HAA and California CO2 emissions requirements and RGGI participation on our financial results; however, our compliance costs could be material.retail customers.
Water Quality
The Clean Water Act established the basic framework for federal and state regulation of water pollution control and requires facilities that discharge waste or storm water into the waters of the United States to obtain permits.
Water Intake Regulations
The Clean Water Act requires cooling water intake structures to reflect the best technology available for minimizing adverse environmental impacts. In July 2004, the EPA published final rules under the Clean Water Act for existing facilities that establish performance standards for meeting the best technology available for minimizing adverse environmental impacts. We currently have sixeight facilities affected by the regulation. In January 2007, the United States Court of Appeals for the Second Circuit ruled that the EPA's rule did not properly implement the Clean Water Act requirements in a number of areas and remanded the rule to the EPA for reconsideration.
In response to this ruling, in July 2007, the EPA suspended the second phase of the regulations pending further rulemaking and directed the permitting authorities to establish controls for cooling water intake structures that reflect the best technology available for minimizing adverse environmental impacts. In November 2007, a number of parties petitionedDecember 2008, the United States Supreme Court to hearheard an appeal of the Second Circuit's decision.decision relating to the application of cost-benefit analysis to best technology available decisions and ruled in April 2009 that the EPA has a right to consider cost-benefit analysis in such decisions.
A decision by the United States Supreme Court on whether to hear the case is not expected until mid to late 2008. In addition, theThe EPA is expected to propose new regulations by the end of 2008. During this period,in March 2011 and we will continue to evaluate our compliance options in light of those proposed regulations. Until the Second Circuit decision andnew regulations are finalized, which is expected in July 2012, water intake compliance will be determined in accordance with the EPA's July 2007 order.order and relevant state regulations and interpretations. Depending on the scope of any new regulations that may be adopted by the EPA, our compliance costs could be material.
In March 2010, the New York Department of Environmental Conservation issued a draft policy designating closed-cycle cooling as the best technology available for cooling water intake structures for minimizing adverse environmental impacts. At this time we cannot estimatepredict whether this policy will be adopted. However, if the policy is adopted and CENG is
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required to retrofit its two nuclear generating facilities in New York to implement this technology, our share of the compliance costs but they could be material.
Hazardous and Solid Waste
We discuss proceedings relating to compliance with the Comprehensive Environmental Response, Compensation and Liability Act inNote 12 to Consolidated Financial Statements.
Our coal-fired generating facilities produce approximately two and a half million tons of combustion by-products ("ash") each year. The EPA announced in 2007 its intention to develop national standards to regulate this material as a non-hazardous waste, and has been developing or considering regulations governing the placement of ash in landfills, surface impoundments, sand/gravel surface mines and coal mines. In 2009, following the Tennessee Valley Authority ash release, the EPA announced it is considering regulating ash as a hazardous waste. Depending on its final scope, additional federal regulation has the potential to result in additional compliance requirements and costs that could be material. In addition, the Maryland Department of the Environment proposed revisedfinalized regulations governing the disposal, storage, use and placement of ash in December 2007. Final rules are expected in June 2008. Federal and state regulation has the potential to result in additional requirements. Depending on the scope of any final requirements, our compliance costs could be material.
As a result of these regulatory proposals and our current ash generation projections, we are exploring our options for the management of ash, including construction of an ash placement facility. Over the next five years, we estimate that our capital expenditures for this project will be approximately $75$20 million. Our estimates are subject to significant uncertainties, including the timing of any regulatory change, its implementation timetable, and the scope of the final requirements. As a result, we cannot predict our capital spending or the scope and timing of this project with certainty, and the actual expenditures, scope and timing could differ significantly from our estimates.
In May 2010, the EPA proposed rules to regulate coal combustion by-products, such as fly ash, either as a special hazardous waste or as a nonhazardous waste. Depending on the scope of any final rules that are adopted, additional federal regulation has the potential to result in additional compliance requirements and costs that could be material.
Constellation Energy and its consolidated subsidiaries (excluding CENG, which was deconsolidated on November 6, 2009) had approximately 10,2007,600 employees at December 31, 2007. At the Nine Mile Point facility, approximately 510 employees are represented by the International Brotherhood of Electrical Workers, Local 97. The labor contract with this union expires in June 2011. We believe that our relationship with this union is satisfactory, but there can be no assurances that this will continue to be the case.
Constellation Energy maintains a website at constellation.com where copies of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments may be obtained free of charge. These reports are posted on our website the same day they are filed with the SEC. The SEC maintains a website (sec.gov), where copies of our filings may be obtained free of charge. The website address for BGE is bge.com. These website addresses are inactive textual references, and the contents of these websites are not part of this Form 10-K.
In addition, the website for Constellation Energy includes copies of our Corporate Governance Guidelines, Principles of Business Integrity, Corporate Compliance Program, Insider Trading Policy, Policy and Procedures with respect to Related Person Transactions, Information Disclosure Policy, and the charters of the Audit, Compensation and Nominating and Corporate Governance Committees of the Board of Directors. Copies of each of these documents may be printed from our website or may be obtained from Constellation Energy upon written request to the Corporate Secretary.
The Principles of Business Integrity is a code of ethics that applies to all of our directors, officers, and employees, including the chief executive officer, chief financial officer, and chief accounting officer. We will post any amendments to, or waivers from, the Principles of Business Integrity applicable to our chief executive officer, chief financial officer, or chief accounting officer on our website.
You should consider carefully the following risks, along with the other information contained in this Form 10-K. The risks and uncertainties described below are not the only ones that may affect us. Additional risks and uncertainties also may adversely affect our business and operations including those discussed in Item 7. Management's Discussion and Analysis. If any of the following events actually occur, our business and financial results could be materially adversely affected.
Economic conditions and instability in the financial markets could negatively impact our business.
Our operations are affected by local, national, and worldwide economic conditions. The consequences of a slow recovery from recession or a new recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity may continue to result in a decline in energy consumption, an increase in customers' inability to pay their accounts, and lower commodity prices. These impacts may adversely affect our financial results and future growth.
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Instability in the financial markets, as a result of recession or otherwise, may affect the cost of capital and our ability to raise capital. We rely on the capital and banking markets, as well as the periodic use of commercial paper to the extent available, to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit issued under our credit facilities to support our operations. Disruptions in the capital and credit markets as a result of uncertainty, reduced alternatives, or failures of significant financial institutions could adversely affect our access to liquidity needed for our businesses, including our ability to secure credit facilities and refinance debt that comes due, and our ability to complete other alternatives we are exploring. In addition, such disruptions could adversely affect our ability to draw on our credit facilities. Our access to funds under those credit facilities is dependent on the ability of the banks that are parties to the facilities to meet their funding commitments. Those banks may not be able to meet their funding commitments to us if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from borrowers within a short period of time. The disruptions in capital and credit markets may also result in higher interest rates on publicly issued debt securities and increased costs associated with commercial paper borrowing and under bank credit facilities.
Any disruptions could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, further changing our strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash. The inability to obtain the liquidity needed to meet our business requirements, or to obtain such liquidity on terms that are favorable to us, would have a material adverse effect on our business, results of operations and financial condition. If entities with which we do business are unable to raise capital or access the credit markets, they may be unable to perform their obligations or make payments under agreements we have with them. Defaults by these entities may have an adverse effect on our financial results.
Our merchant energyNewEnergy business may incur substantial costs and liabilities and be exposed to price volatility and counterparty performance risk as a result of its participation in the wholesale energy markets.
We purchase and sell power and fuel in markets exposed to significant risks, including price volatility for electricity and fuel and the credit risks of counterparties with which we enter into contracts.
We use various hedging strategies in an effort to mitigate many of these risks. However, hedging transactions do not guard against all risks and are not always effective, as they are based upon predictions about future market conditions. The inability or failure to effectively hedge assets or fuel or power positions against changes in commodity prices, interest rates, counterparty credit risk or other risk measures could significantly impair our future financial results.
Exposure to electricity price volatility. We buy and sell electricity in both the wholesale bilateral markets and spot markets, which expose us to the risks of rising and falling prices in those markets, and our cash flows may vary accordingly. At any given time, the wholesale spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. This is highly dependent on the regional generation market. In many cases, the next unit of electricity supplied would be supplied from generating stations fueled by fossil fuels, primarily coal, natural gas and oil. Consequently, the open market wholesale price of electricity may reflect the cost of coal, natural gas or oil plus the cost to convert the fuel to electricity and an appropriate return on capital. Therefore, changes in the supply and cost of coal, natural gas and oil may impact the open market wholesale price of electricity.
A portion of our power generation facilities operates wholly or partially without long-term power purchase agreements. As a result, power from these facilities is sold on the spot market or on a short-term contractual basis, which if not fully hedged may affect the volatility of our financial results.
Exposure to fuel cost volatility. Currently, our power generation facilities purchase a portion of their fuel through short-term contracts or on the spot market. Fuel prices can be volatile, and the price that can be obtained for power produced from such fuel may not change at the same rate as fuel costs. In addition, new sources of natural gas supplies from domestic shale production, as well as rising liquid natural gas (LNG) exports, could increase the long-term supply of natural gas and create a fundamental and long-lasting decline in natural gas prices. Lower natural gas prices could contribute to a decline in power generation prices that could have an adverse effect on our financial results and cash flows. As a result, fuel price increaseschanges may adversely affect our financial results.
Exposure to counterparty performance. Our merchant energyNewEnergy business enters into transactions with numerous third parties (commonly referred to as "counterparties"). In these arrangements, we are exposed to the credit risks of our counterparties and the risk that one or more counterparties may fail to perform under their obligations to make payments or deliver fuel or power. In addition, we enter into various wholesale transactions through Independent System Operators (ISOs). These ISOs are exposed to counterparty credit
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risks. Any losses relating to counterparty defaults impacting the ISOs are allocated to and borne by all other market participants in the ISO. These risks are enhancedexacerbated during periods of commodity price fluctuations. 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 derivative contracts recorded at fair value, the amount owed for settled transactions, and additional payments, if any, that we would have to make to settle unrealized losses on accrual contracts. Defaults by suppliers and other counterparties may adversely affect our financial results.
Changes in the prices of commodities, initial margin requirements, collateral posting asymmetries and types of collateral impact our liquidity requirements.
Our businesses are exposed to market fluctuations in the price and transportation costs of electricity, natural gas, coal, and other commodities. We seek to mitigate the effect of these fluctuations through various hedging strategies, which may require the posting of collateral by both us and our counterparties. Changes in the prices of commodities and initial margin requirements for exchange-traded contracts can affect the amount of collateral that must be posted, depending on the particular position we hold.
There are certain asymmetries relating to the use of collateral that create liquidity requirements for our Generation and NewEnergy businesses. These asymmetries arise as a result of our actions to be economically hedged as well as market conditions or conventions for conducting business that result in some transactions being collateralized while others are not, including:
As a result, significant changes in the prices of commodities and margin requirements for exchange-traded contracts could require us to post additional collateral from time to time without our counterparties having to post cash collateral to us, which could adversely affect our overall liquidity and ability to finance our operations, and, in turn, could adversely affect our credit ratings. Additionally, posting letters of credit to counterparties to meet collateral requirements adversely impacts our liquidity, while the receipt of letters of credit as collateral does not improve our liquidity.
Reduced liquidity in the markets in which we operate could impair our ability to appropriately manage the risks of our operations.
We are an active participant in energy markets through our competitive energy businesses. The liquidity of regional energy markets is an important factor in our ability to manage risks in these operations. Over the past several years, market participants in the merchant energy business have ended or significantly reduced their activities as a result of several factors, including government investigations, changes in market design, and deteriorating credit quality. As a result, several regional energy markets experienced a significant decline in liquidity, which, in turn, has impacted our ability to enter into certain types of transactions to manage our risks for settlement periods beyond 18 to 24 months. Liquidity in the energy markets can be adversely affected by various factors, including price volatility and the availability of credit. As a result, future reductions in liquidity may restrict our ability to manage our risks and this could impact our financial results.
We often rely on single suppliers and at times on single customers, exposing us to significant financial risks if either should fail to perform their obligations.
We often rely on a single supplier for the provision of fuel, water, and other services required for operation of a facility, and at times, we rely on a single customer or a few customers to purchase all or a significant portion of a facility's output, in some cases under long-term agreements that provide the support for any project debt used to finance the facility. The failure of any one customer or supplier to fulfill its contractual obligations could negatively impact our financial results.
We may not fully hedge our Generation and NewEnergy businesses, or other market positions against changes in commodity prices, and our hedging procedures may not work as planned.
To lower our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge a portion of our purchase and sale commitments, weather positions, fuel requirements, inventories of natural gas, coal and other commodities, and competitive supply obligations. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, we may not cover the entire exposure of our assets or positions to market price volatility, and the coverage will vary over time. Fluctuating commodity prices may negatively impact our financial results to the extent we have unhedged positions.
In addition, risk management tools and metrics such as economic value at risk, daily value at risk, and stress testing are based on historical price movements. If price movements significantly or persistently deviate
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from historical behavior, risk limits may not fully protect us from significant losses.
Our risk management policies and procedures may not always work as planned. As a result of these and other factors, we cannot predict with precision the impact that risk management decisions may have on our financial results.
The use of derivative and nonderivative contracts in the normal course of business could result in financial losses that negatively impact our financial results.
We use derivative instruments such as swaps, options, futures and forwards, as well as nonderivative contracts, to manage our commodity and financial market risks and to engage in trading activities. We could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.
In the absence of actively quoted market prices and pricing information from external sources, the valuation of derivative instruments involves management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
Additionally, the settlement of derivative instruments could reflect a realized value that differs from our reported estimates of fair value.
Inaccurate assumptions and estimates in the models we use could adversely impact our financial results.
We deploy many models to value merchant contracts, derivatives and assets, to dispatch power from our generation plants, and to measure the risks and costs of various transactions and businesses. Also, a significant portion of our business relies on the assumptions underlying the forecasting of customer load, correlations between prices of energy commodities and weather and the creditworthiness of our customers and other third parties. Inaccurate estimates of various business assumptions used in those models could create the mispricing of customer contracts and assets or the incorrect measurement of key risks relating to our portfolios and businesses that could adversely impact our financial results.
Poor market performance will affect our pension plan investments, which may adversely affect our liquidity and financial results.
At December 31, 2010, our qualified pension obligation was approximately $129 million greater than the fair value of our plan assets. The performance of the capital markets will affect the value of the assets that are held in trust to satisfy our future obligations under our qualified pension plans. A decline in the market value of those assets or the failure of those assets to earn an adequate return may increase our funding requirements for these obligations, which may adversely affect our liquidity and financial results.
The operation of power generation facilities, including nuclear facilities involves significant risks that could adversely affect our financial results.
We own, operate and operatehave ownership interests in a number of power generation facilities. The operation of power generation facilities involves many risks, including start upstart-up risks, breakdown or failure of equipment, transmission lines, substations or pipelines, use of new technology, the dependence on a specific fuel source, including the transportation of fuel, or the impact of unusual or adverse weather conditions (including natural disasters such as hurricanes) or environmental compliance, as well as the risk of performance below expected or contracted levels of output or efficiency. This could result in lost revenues and/or increased expenses. Insurance, warranties, or performance guarantees may not cover any or all of the lost revenues or increased expenses, including the cost of replacement power. A portion of our generation facilities were constructed many years ago. Older generating equipment may require significant capital expenditures to keep it operating at peak efficiency. This equipment is also likely to require periodic upgrading and improvement. Breakdown or failure of one of our operating facilities may prevent the facility from performing under applicable power sales agreements which, in certain situations, could result in termination of the agreement or incurring a liability for liquidated damages.
Our Generation business may incur substantial costs and liabilities due to our ownership interest in nuclear generating facilities.
We indirectly own substantial interests in nuclear power plants. Operation of these plants exposes us to risks in addition to those that result from owning and operating non-nuclear power generation facilities. These risks include normal operating risks for a nuclear facility and the risks of a nuclear accident.
Nuclear Operating Risks. The operation of nuclear generating facilities involves routine operating risks, including:
Nuclear Accident Risks. In the event of a nuclear accident, the cost of property damage and other expenses incurred may exceed the insurance coverage available from both private sources and an industry retrospective payment plan. In addition, in the event of an accident at our nuclear joint venture or another participating insured party's nuclear plants, we or CENG could be assessed retrospective insurance premiums (because all nuclear plant operators contribute to a nationwide catastrophic insurance fund). In instances where CENG is the member insured, we have guaranteed our share of CENG's performance. Uninsured losses or the payment of retrospective insurance premiums could each have a material adverse effect on our financial results.
We are subject to numerous environmental laws and regulations that require capital expenditures, increase our cost of operations and may expose us to environmental liabilities.
We are subject to extensive federal, state, and local environmental statutes, rules, and regulations relating to air quality, water quality, waste management, wildlife protection, the management of natural resources, and the protection of human health and safety that could, among other things, require additional pollution control equipment, limit the use of certain fuels, restrict the output of certain facilities, or otherwise increase costs. Significant capital expenditures, operating and other costs are associated with compliance with environmental requirements, and these expenditures and costs could become even more significant in the future as a result of regulatory changes.
For example, there is increasing likelihood thatExamples of potential future regulatory changes include additional regulation of greenhouse gas emissions will occur at the federal, regional, and/or state level, whichheightened enforcement of new source review requirements, increased regulation of coal combustion by-products, and mandated investment in maximum achievable control technology or renewable energy resources. One or more of these changes could increase our compliance and operating costs.costs or require significant commitments of capital.
We are subject to liability under environmental laws for the costs of remediating environmental contamination. Remediation activities include the cleanup of current facilities and former properties, including manufactured gas plant operations and offsite waste disposal facilities. The remediation costs could be significantly higher than the liabilities recorded by us. Also, our subsidiaries are currently involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future.
We are subject to legal proceedings by individuals alleging injury from exposure to hazardous substances and could incur liabilities that may be material to our financial results. Additional proceedings could be filed against us in the future.
We may also be required to assume environmental liabilities in connection with future acquisitions. As a result, we may be liable for significant environmental remediation costs and other liabilities arising from the operation of acquired facilities, which may adversely affect our financial results.
Our generation business may incur substantial costsWe, and liabilities dueBGE in particular, are subject to its ownershipextensive local, state and operation of nuclear generating facilities.federal regulation that could affect our operations and costs.
We ownare subject to regulation by federal and operate nuclear power plants. Ownershipstate governmental entities, including the FERC, the NRC, the Maryland PSC and operationthe utility commissions of these plants exposesother states in which we have operations. In addition, changing governmental policies and regulatory actions can have a significant impact on us. Regulations can affect, for example, allowed rates of return, requirements for plant operations, recovery of costs, limitations on dividend payments, and the regulation or re-regulation of wholesale and retail competition.
BGE's distribution rates are subject to regulation by the Maryland PSC, and such rates are effective until new rates are approved. If the Maryland PSC does not approve adequate new rates, BGE might not be able to recover certain costs it incurs or earn an adequate rate of return. In addition, limited categories of costs are recovered through adjustment charges that are periodically reset to reflect current and projected costs. Inability to recover material costs not included in rates or adjustment clauses could have an adverse effect on our, or BGE's, cash flow and financial position.
Energy legislation enacted in Maryland in June 2006 and April 2007 mandated that the Maryland PSC review Maryland's competitive electricity market. Although the settlement agreement reached with the State of Maryland in March 2008 terminated certain studies relating to the 1999 deregulation settlement, the State of Maryland is still undertaking a review of the Maryland electric industry and market structure to consider various options for providing standard offer service to residential customers, including re-regulation. We cannot at this time predict the final outcome of this review or how such outcome may affect our, or BGE's financial results, but it could be material.
The Dodd-Frank Wall Street Reform and Consumer Protection Act provides for a new regulatory regime for derivatives. Final regulations may address collateral requirements, exchange margin cash postings, and other aspects of derivative transactions, which if applicable to us despite being an end user of derivatives, could require us to risks in addition to those that result from owning and operating non-nuclear power generation facilities. These risks include normal operating risks for a nuclear facility and the risks of a nuclear accident.
Nuclear Operating Risks. The ownership and operation of nuclear generating facilities involve routine operating risks, including:
Nuclear Accident Risks. In the event of a nuclear accident, the cost of property damage and other expenses incurred may exceed our insurance coverage available from both private sources and an industry retrospective payment plan. In addition, in the event of an accident at one of our or another participating insured party's nuclear plants, we could be assessed retrospective insurance premiums (because all nuclear plant operators contribute to a nationwide catastrophic insurance fund). Uninsured losses or the payment of retrospective insurance premiums could eachotherwise have a material adverse effect on our financial results.business.
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Our generation growth plans We are also subject to mandatory reliability standards enacted by the North American Electric Reliability Corporation (NERC) and enforced by the FERC. Compliance with the mandatory reliability standards may not achieve the desired financial results.
Wesubject us to higher operating costs and may expand our generation capacity over the next several years through increasing the generating power of existing plants, the renovation of retired plants owned by us, and the construction or acquisition of new plants. The renovation, development, construction, and acquisition of additional generation capacity involves numerous risks. Any planned power uprates, construction, or renovation could result in cost overruns, lower than expected plant efficiency, and higher operating and other costs. With respect to the renovation of retired plants or the construction of new plants, we may incur significant sums for preliminary engineering, permitting, legal, and other expenses before it can be established whether a project is feasible, economically attractive, or capable of being financed.
increased capital expenditures. If we were unableare found to be in noncompliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties. The State of Maryland also is considering legislative or regulatory changes that would impose reliability and quality of service standards on electric and gas companies, including penalties for failure to meet those standards.
Further, federal and/or state regulatory approval may be necessary for us to complete transactions. As part of the construction or renovation of a plant, weregulatory approval process, governmental entities may not be able to recover our investment in the project. Furthermore, we may be unable to run any new, acquired or renovated plants as efficiently as projected, which could result in higher-than-projected operatingimpose terms and other costs that adversely affect our financial results.
We often rely on single suppliers and at times on single customers, exposing us to significant financial risks if either should fail to perform their obligations.
We often rely on a single supplier for the provision of fuel, water, and other services required for operation of a facility, and at times, we rely on a single customer or a few customers to purchase all or a significant portion of a facility's output, in some cases under long-term agreements that provide the support for any project debt used to finance the facility. The failure of any one customer or supplier to fulfill its contractual obligations could negatively impact our financial results. Consequently, our financial performance dependsconditions on the continued performance by customerstransaction or our business that are unfavorable or add significant additional costs to our future operations.
The regulatory and suppliers of their obligations under these long-term agreements.
Reduced liquidity in the markets in which we operate could impair our ability to appropriately manage the risks of our operations.
We are an active participant in energy markets through our competitive energy businesses. The liquidity of regional energy markets is an important factor in our ability to manage risks in these operations. Over the past several years, several merchant energy businesses have ended or significantly reduced their activities as a result of several factors including government investigations, changes in market design and deteriorating credit quality. As a result, several regional energy markets experienced a significant decline in liquidity. Liquidity in the energy markets can be adversely affected by various factors, including price volatility and the availability of credit. As a result, future reductions in liquiditylegislative process may restrict our ability to manage our risks and this could impact our financial results.
We may not fully hedge our generation assets, competitive supply or other market positions against changesgrow earnings in commodity prices, and our hedging procedures may not work as planned.
To lower our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge a portioncertain parts of our purchasebusiness, cause delays in or affect business planning and sale commitments, weather positions, fuel requirements, inventories of natural gas, coaltransactions and other commodities, and competitive supply. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter marketsincrease our, or on exchanges. However, we may not cover the entire exposure of our assets or positions to market price volatility and the coverage will vary over time. Fluctuating commodity prices may negatively impact our financial results to the extent we have unhedged positions.
In addition, risk management tools and metrics such as daily value at risk, stop loss limits and liquidity guidelines are based on historical price movements. If price movements significantly or persistently deviate from historical behavior, the limits may not protect us from significant losses.
Our risk management policies and procedures may not always work as planned. As a result of these and other factors, we cannot predict with precision the impact that risk management decisions may have on our financial results.BGE's, costs.
The use of derivative contracts by us in the normal course of business could result in financial losses that negatively impact our financial results.
We use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks and to engage in trading activities. We could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.
In the absence of actively quoted market prices and pricing information from external sources, the valuation of these derivative instruments involves management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
A failure in our operational systems or infrastructure, or those of third parties, may adversely affect our financial results.
Our businesses are dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, accounting or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws or employee tampering or manipulation of those systems will result in losses that are difficult to detect.
We may also be subject to disruptions of our operational systems arising from events that are wholly or partially beyond our control (for example, natural disasters, acts of terrorism, epidemics, computer viruses and telecommunications outages). Third party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt one or more of our businesses, result in potential liability or reputational damage or otherwise have an adverse affect on our financial results.
We operate in deregulatedcompetitive segments of the electric and gas industries created by federal and state restructuring initiatives. If competitive restructuring of the electric or gas industries is reversed, discontinued, restricted, or delayed, our business prospects and financial results could be materially adversely affected.
The regulatory environment applicable to the electric and natural gas industries has undergone substantial changes as a result of restructuring initiatives at both the state and federal levels. These initiatives have had a significant impact on the nature of the electric and natural gas industries and the manner in which their participants conduct their businesses. We have targeted the competitive segments of the electric and natural gas industries created by these initiatives.
Due to recent events in the energy markets, energyEnergy companies have been under increased scrutiny by state legislatures, regulatory bodies, capital markets, and credit rating agencies. This increased scrutiny could lead to substantial changes in laws and regulations affecting us, including modifications to the auction processes in competitive markets and new accounting standards that could change the way we are required to record revenues, expenses, assets, and liabilities. Recent proposals byProposals in the State of Maryland PSCfrom time to time relating to the structure of the electric industry in Maryland and various options for re-regulation of the industry is one exampleare examples of how these laws and regulations can change. In addition, other states are seeking more direct ways to affect the results of wholesale capacity markets, including legislation adopted in New Jersey that provides guaranteed cost recovery for the development of up to 2,000 MWs of generation in exchange for the new generation clearing in the PJM capacity market. We cannot predict the future development of regulation or legislation in these markets or the ultimate effect that this changing regulatory environment will have on our business.
If competitive restructuring of the electric and natural gas markets is reversed, discontinued, restricted, or delayed, or if the recent Maryland PSClegislative or regulatory proposals are implemented in a manner adverse to us, our business prospects and financial results could be negatively impacted.
Our financial results may be harmed if transportation and transmission availability is limited or unreliable.
We have business operations throughout the United States and internationally.in Canada. As a result, we depend on transportation and transmission facilities owned and operated by utilities and other energy companies to deliver the electricity, coal,natural gas and natural gasother related products we sell to the wholesale and retail markets, as well as the natural gas and coal we purchase to supply some of our generating facilities. If transportation or transmission is disrupted or capacity is inadequate, our ability to sell and deliver products may be hindered. Such disruptions could also hinder our ability to provide electricity, coal, or natural gas to our customers or power plants and may materially adversely affect our financial results.
BGE's electric and gas infrastructure may require significant expenditures to maintain and is subject to operational failure, which could result in potential liability.
Much of BGE's electric and gas operational systems and infrastructure, such as gas mains and pipelines and electric transmission and distribution equipment, has been in service for many years. Older equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including due to events that are beyond BGE's control, and may require significant expenditures to operate efficiently. Operational failure could result in potential liability if such failure results in damage to property or injury to individuals. As a result, electric and gas infrastructure expenditures and operational failure of equipment could have an adverse effect on our, or BGE's, financial results.
Our merchant energyNewEnergy business has contractual obligations to certain customers to provide full requirements service, which makes it difficult to predict and plan for load requirements and may result in reduced revenues and increased operating costs to our business.
Our merchant energyNewEnergy business has contractual obligations to certain customers to supply full requirements service to such customers to satisfy all or a portion of their energy requirements. The uncertainty regarding the amount of load that our merchant energyNewEnergy business must be prepared to supply to customers may increase our operating costs. The process of estimating the load requirements of our
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customers is complicated by potential variability in demand resulting from extreme changes in weather and economic factors affecting our customers. A significant under- or over-estimation of load requirements could result in our merchant energyNewEnergy business not having enough power or having too much power to cover its load obligation, in which case it would be required to buy or sell power from or to third parties at prevailing market prices. Those prices may not be favorable and thus could reduce our revenues and/or increase our operating costs.costs and result in the possibility of reduced earnings or incurring losses.
Our financial results may fluctuate on a seasonal and quarterly basis or as a result of severe weather.
Our business is affected by weather conditions. Our overall operating results may fluctuate substantially on a seasonal basis, and the pattern of this fluctuation may change depending on the nature and location of any facility we acquire and the terms of any contract to which we become a party. Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities.
Generally, demand for electricity peaks in winter and summer and demand for gas peaks in the winter. Typically, when winters are warmer than expected and summers are cooler than expected, demand for energy is lower, resulting in less electric and gas consumption than forecasted. Depending on prevailing market prices for electricity and gas, these and other unexpected conditions may reduce our revenues and results of operations. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and may make period comparisons less relevant.
Severe weather can be destructive, causing outages and/or property damage. This could require us to incur additional costs. Catastrophic weather, such as hurricanes, could impact our or our customers' operating facilities, communication systems and technology. Unfavorable weather conditions may have a material adverse effect on our financial results.
A downgradeInvestment in our credit ratings could negativelynew business initiatives and markets may not be successful.
Our NewEnergy business has sought to invest in new business initiatives and actively participate in new markets. These include, but are not limited to, unconventional oil and gas exploration and production, residential retail power and gas sales, solar and wind generation, and managed load response. Such initiatives may involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered in the diligence performed prior to launching an initiative or entering a market. Due to these risks, no assurance can be given that such initiatives will be successful and will not materially adversely affect our ability to access capital and/financial results. Additionally, as these markets mature, there may be new market entrants or operateexpansion by established competitors that increase competition for customers and resources, which could result in us not achieving our wholesaleplans and retail competitive supply businesses.
We rely on access to capital markets as a source of liquidity for capital requirements not satisfied by
operating cash flows. If any of our credit ratings were to be downgraded, especially below investment grade, our ability to raise capital on favorable terms, including the commercial paper markets, could be hindered, and our borrowing costs would increase. Additionally, the business prospects of our wholesale and retail competitive supply businesses, which in many cases rely on the creditworthiness of Constellation Energy, would be negatively impacted. Some of the factors that affect credit ratings are cash flows, liquidity, the amount of debt as a component of total capitalization, and political, legislative and regulatory events.
In addition, the ability of BGE to recover its costs of providing service and timing of BGE's recovery could have a material adverse effect on the credit ratingsour financial results.
A failure in our operational systems or infrastructure, or those of BGE and us.
We, and BGE in particular, are subject to extensive local, state and federal regulation that couldthird parties, may adversely affect our operationsfinancial results.
Our businesses are dependent upon our operational systems to process a large amount of data and costs.
We are subject to regulation by federal and state governmental entities, including the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, the Maryland PSC and the utility commissions of other states in which we have operations. In addition, changing governmental policies and regulatory actions can have a significant impact on us. Regulations can affect, for example, allowed rates of return, requirements for plant operations, recovery of costs, limitations on dividend payments and the regulation or re-regulation of wholesale and retail competition (including but not limited to retail choice and transmission costs).
BGE's distribution rates are subject to regulation by the Maryland PSC, and such rates are effective until new rates are approved. In addition, limited categories of costs are recovered through adjustment charges that are periodically reset to reflect current and projected costs. Inability to recover material costs not included in rates or adjustment clauses, including increases in uncollectible customer accounts that may result from higher gas or electric costs, could have an adverse effect on our, or BGE's, cash flow and financial position.
Energy legislation enacted in Maryland in June 2006 and April 2007 mandated that the Maryland PSC review Maryland's deregulated electricity market. In December 2007 and January 2008, the Maryland PSC issued interim reports that addressed the costs and benefits of options for re-regulation and reviewed the impact to customers resulting from Maryland's deregulation process. In addition, the Maryland PSC continues to review the relationship between Constellation Energy and BGE. Because reviews of the Maryland electric industry and market structure are ongoing, we cannot at this time predict the final outcome of these reviews and proposals or how such outcome may affect our, or BGE's, financial results, but it could be material.
In addition, the June 2006 legislation required BGE to provide credits to residential electric customers totaling approximately $39 million annually. In January 2008, we notified the State of Marylandcomplex transactions. If any of our intent to file a federal action to enforcefinancial, accounting, or other data processing systems fail or have other significant shortcomings, our rights under the 1999 Maryland electric deregulation settlement and to challenge the constitutionality of the residential customer credits provided for under the June 2006 legislation. We may incur significant costs to litigate this action and we cannot provide any assurances that it will be resolved in our favor. If the action is resolved in a manner adverse to us, which may include a court determining that the legislation appropriately required the residential rate credits or overturning aspects of the 1999 electric deregulation settlement, the impact on our, or BGE's, financial results could be material.adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws or employee tampering or manipulation of those systems will result in losses that are difficult to detect.
The regulatory processWe may restrict our abilityalso be subject to grow earnings in certain partsdisruptions of our business, cause delays inoperational systems arising from events that are wholly or affect business planningpartially beyond our control (for example, natural disasters, acts of terrorism, epidemics, computer viruses and transactions and increase our,telecommunications outages). Third party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt one or BGE's, costs.
Poor market performance will affect our benefit plan and nuclear decommissioning trust asset values, which may adversely affect our liquidity and financial results.
Our qualified pension obligations have exceeded the fair valuemore of our plan assets since 2001. At December 31, 2007, our qualified pension obligations were approximately $315 million greater than the fair value of our plan assets. The performance of the capital markets will affect the value of the assets that are heldbusinesses, result in trust to satisfy our future obligations under our qualified pension plans. A decline in the market value of those assets may increase our funding requirements for these obligations, which may adversely affect our liquidity and financial results.
We are required to maintain funded trusts to satisfy our future obligations to decommission our nuclear power plants. A decline in the market value of those assets due to poor investment performancepotential liability or other factors may increase our funding requirements for these obligations, which mayreputational damage or otherwise have an adverse effectaffect on our liquidity and financial results.
Our ability to successfully identify, complete and integrate acquisitions is subject to significant risks, including the effect of increased competition.
We are likely to encounter significant competition for acquisition opportunities that may become available. In addition, we may be unable to identify attractive acquisition opportunities at favorable prices, to secure the financing necessary to undertake them, or to successfully and timely complete and integrate them. Specifically, we intend to continue to pursue the acquisition of new generating plants in regions where we have significant retail and wholesale customer supply operations. Acquired plants may not generate the projected rates of return or sufficiently match generation capacity with retail and wholesale customer supply operations volumes causing an increase in collateral requirements. If we cannot identify, complete and integrate acquisitions successfully, our business, results of operations and financial condition could be adversely affected.
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War, and threats of terrorism and catastrophic events that could result from terrorism may impact ourthe results of our operations in unpredictable ways.
We cannot predict the impact that any future act of war, terrorist attacks mayattack, or catastrophic event might have on the energy industry in general and on our business in particular. In addition, any retaliatory military strikes or sustained military campaign may affect our operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil.
The possibility alone that infrastructure facilities, such as electric generation, electric and gas transmission and distribution facilities would be direct targets of, or indirect casualties of, an act of terror, war, or a catastrophic event may affect our operations. Furthermore, these catastrophic events could compromise the physical or cyber security of our facilities, which could adversely affect our ability to manage our business effectively.
Such activity may have an adverse effect on the United States economy in general. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our financial results or restrict our future growth. Instability in the financial markets as a result of war, threats of terrorism, or warand catastrophic events may affect our stock price and our ability to raise capital.
In addition, we maintain a level of insurance coverage consistent with industry practices against property and casualty losses subject to unforeseen occurrences or catastrophic events that may damage or destroy assets or interrupt operations. Furthermore, in the event of a severe disruption resulting from war, threats of terrorism, and catastrophic events, we have contingency plans and employ crisis management to respond and recover operations. Despite these measures, there may be events beyond our control that may severely impact operations and affect financial performance.
A downgrade in our credit ratings could negatively affect our ability to access capital and/or operate our wholesale and retail NewEnergy business.
We rely on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows. If any of our credit ratings were to be downgraded, especially below investment grade, our ability to raise capital on favorable terms, including in the commercial paper markets, if available, could be hindered, and our borrowing costs would increase. Additionally, the business prospects of our wholesale and retail NewEnergy business, which in many cases rely on the creditworthiness of Constellation Energy, would be negatively impacted. In this regard, we have certain agreements that contain provisions that would require us to post additional collateral upon a credit rating downgrade. Based on market conditions and contractual obligations at the time of a downgrade, we could be required to post collateral in an amount that exceeds our available liquidity. Some of the factors that affect credit ratings are cash flows, liquidity, the amount of debt as a component of total capitalization, and political, legislative, and regulatory events.
We are subject to employee workforce factors that could affect our businesses and financial results.
We are subject to employee workforce factors, including loss or retirement of key executives or other employees, availability of qualified personnel, collective bargaining agreements with union employees, and work stoppage that could affect our financial results. In particular, our competitive energy businesses are dependent, in part, on recruiting and retaining personnel with experience in sophisticated energy transactions and the functioning of complex wholesale markets.
Our ability to successfully identify, complete and integrate acquisitions is subject to significant risks, including the effect of increased competition.
We are likely to encounter significant competition for acquisition opportunities that may become available. In addition, we may be unable to identify attractive acquisition opportunities at favorable prices and to successfully and timely complete and integrate them.
Constellation Energy occupies approximately 900,000856,000 square feet of leased and owned office space in North America, which includes its corporate offices in Baltimore, Maryland. We describe our electric generation properties on the next page. We also have leases for other offices and services located in the Baltimore metropolitan region, and for various real property and facilities relating to our generation projects.
BGE owns its principal headquarters building located in downtown Baltimore. BGE also leases approximately 16,670 square feet of office space. In addition, BGE owns propane air and liquefied natural gas facilities as discussed inItem 1. Business—Gas Business section.
BGE also has rights-of-way to maintain 26-inch natural gas mains across certain Baltimore City-owned property (principally parks) which expired in 2004. BGE is in the process of renewing the rights-of-way with Baltimore City for an additional 25 years. The expiration of the rights-of-way does not affect BGE's ability to use the rights-of-way during the renewal process.
BGE has electric transmission and electric and gas distribution lines located:
All of BGE's property is subject to the lien of BGE's mortgage securing its mortgage bonds. The generation facilities transferred to our subsidiaries by BGE on July 1, 2000, along with the stock we own in certain of our subsidiaries, are subject to the lien of BGE's mortgage. We expect the assets to be released from this lien following payment in March 2008 of the last series of bonds outstanding under the mortgage and the discharge of the mortgage.
We believe we have satisfactory title to our power project facilities in accordance with standards generally accepted in the energy industry, subject to exceptions, which in our opinion, would not have a material adverse effect on the use or value of the facilities.
Our merchant energyNewEnergy business owns several natural gas producing properties. We also lease office space in the United Kingdom and Australia to support our merchant energy business.
The following table describes our generating facilities:
Plant | Location | Capacity (MW) | % Owned | Capacit Owned (MW) | Primary Fuel | ||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| | (at December 31, 2007) | |||||||||
Mid-Atlantic Region | |||||||||||
Calvert Cliffs | Calvert Co., MD | 1,735 | 100.0 | 1,735 | Nuclear | ||||||
Brandon Shores | Anne Arundel Co., MD | 1,286 | 100.0 | 1,286 | Coal | ||||||
H. A. Wagner | Anne Arundel Co., MD | 963 | 100.0 | 963 | Coal/Oil/Gas | ||||||
C. P. Crane | Baltimore Co., MD | 399 | 100.0 | 399 | Oil/Coal | ||||||
Keystone | Armstrong and Indiana Cos., PA | 1,711 | 21.0 | 359 | (A) | Coal | |||||
Conemaugh | Indiana Co., PA | 1,711 | 10.6 | 181 | (A) | Coal | |||||
Perryman | Harford Co., MD | 355 | 100.0 | 355 | Oil/Gas | ||||||
Riverside | Baltimore Co., MD | 232 | 100.0 | 232 | Oil/Gas | ||||||
Handsome Lake | Rockland Twp, PA | 268 | 100.0 | 268 | Gas | ||||||
Notch Cliff | Baltimore Co., MD | 120 | 100.0 | 120 | Gas | ||||||
Westport | Baltimore City, MD | 116 | 100.0 | 116 | Gas | ||||||
Philadelphia Road | Baltimore City, MD | 64 | 100.0 | 64 | Oil | ||||||
Safe Harbor | Safe Harbor, PA | 417 | 66.7 | 278 | Hydro | ||||||
Total Mid-Atlantic Region * | 9,376 | 6,355 | |||||||||
Plants with Power Purchase Agreements | |||||||||||
Nine Mile Point Unit 1 | Scriba, NY | 620 | 100.0 | 620 | Nuclear | ||||||
Nine Mile Point Unit 2 | Scriba, NY | 1,138 | 82.0 | 933 | Nuclear | ||||||
R.E. Ginna | Ontario, NY | 581 | 100.0 | 581 | Nuclear | ||||||
Total Plants with Power Purchase Agreements | 2,339 | 2,134 | |||||||||
Other | |||||||||||
Panther Creek | Nesquehoning, PA | 80 | 50.0 | 40 | Waste Coal | ||||||
Colver | Colver Township, PA | 104 | 25.0 | 26 | Waste Coal | ||||||
Sunnyside | Sunnyside, UT | 51 | 50.0 | 26 | Waste Coal | ||||||
ACE | Trona, CA | 102 | 31.1 | 32 | Coal | ||||||
Jasmin | Kern Co., CA | 35 | 50.0 | 18 | Coal | ||||||
POSO | Kern Co., CA | 35 | 50.0 | 18 | Coal | ||||||
Mammoth Lakes G-1 | Mammoth Lakes, CA | 6 | 50.0 | 3 | Geothermal | ||||||
Mammoth Lakes G-2 | Mammoth Lakes, CA | 13 | 50.0 | 7 | Geothermal | ||||||
Mammoth Lakes G-3 | Mammoth Lakes, CA | 13 | 50.0 | 7 | Geothermal | ||||||
Soda Lake I | Fallon, NV | 4 | 50.0 | 2 | Geothermal | ||||||
Soda Lake II | Fallon, NV | 10 | 50.0 | 5 | Geothermal | ||||||
Rocklin | Placer Co., CA | 24 | 50.0 | 12 | Biomass | ||||||
Fresno | Fresno, CA | 24 | 50.0 | 12 | Biomass | ||||||
Chinese Station | Jamestown, CA | 20 | 45.0 | 9 | Biomass | ||||||
Malacha | Muck Valley, CA | 32 | 50.0 | 16 | Hydro | ||||||
SEGS IV | Kramer Junction, CA | 33 | 12.2 | 4 | Solar | ||||||
SEGS V | Kramer Junction, CA | 24 | 4.2 | 1 | Solar | ||||||
SEGS VI | Kramer Junction, CA | 34 | 8.8 | 3 | Solar | ||||||
Total Other * | 644 | 239 | |||||||||
Total Generating Facilities * | 12,359 | 8,728 | |||||||||
| | At December 31, 2010 | | | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Plant | Location | Capacity (MW) | % Owned | Capacity Owned (MW) | 2010 Capacity Factor (%) | Primary Fuel | ||||||||||
Calvert Cliffs Unit 1 (1) | Calvert Co., MD | 855 | 50.0 | 428 | 90.0 | Nuclear | ||||||||||
Calvert Cliffs Unit 2 (1) | Calvert Co., MD | 850 | 50.0 | 425 | 97.2 | Nuclear | ||||||||||
Nine Mile Point Unit 1 (1) | Scriba, NY | 620 | 50.0 | 310 | 97.5 | Nuclear | ||||||||||
Nine Mile Point Unit 2 (1) | Scriba, NY | 1,138 | 41.0 | 467 | 89.7 | Nuclear | ||||||||||
R.E. Ginna (1) | Ontario, NY | 581 | 50.0 | 291 | 97.2 | Nuclear | ||||||||||
Brandon Shores | Anne Arundel Co., MD | 1,273 | 100.0 | 1,273 | 54.1 | Coal | ||||||||||
H. A. Wagner | Anne Arundel Co., MD | 976 | 100.0 | 976 | 19.2 | Coal/Oil/Gas | ||||||||||
C. P. Crane | Baltimore Co., MD | 399 | 100.0 | 399 | 24.2 | Oil/Coal | ||||||||||
Keystone | Armstrong and Indiana Cos., PA | 1,711 | 21.0 | 359 | (5) | 90.4 | Coal | |||||||||
Conemaugh | West Moreland Co., PA | 1,711 | 10.6 | 181 | (5) | 81.1 | Coal | |||||||||
Perryman | Harford Co., MD | 347 | 100.0 | 347 | 2.2 | Oil/Gas | ||||||||||
Riverside | Baltimore Co., MD | 228 | 100.0 | 228 | 0.7 | Oil/Gas | ||||||||||
Handsome Lake | Rockland Twp, PA | 268 | 100.0 | 268 | 2.7 | Gas | ||||||||||
Notch Cliff | Baltimore Co., MD | 101 | 100.0 | 101 | 2.0 | Gas | ||||||||||
Westport | Baltimore City, MD | 116 | 100.0 | 116 | 0.5 | Gas | ||||||||||
Gould Street | Baltimore City, MD | 97 | 100.0 | 97 | 2.6 | Gas | ||||||||||
Philadelphia Road | Baltimore City, MD | 61 | 100.0 | 61 | 0.5 | Oil | ||||||||||
Safe Harbor | Safe Harbor, PA | 417 | 66.7 | 278 | 27.1 | Hydro | ||||||||||
Criterion | Oakland, MD | 70 | 100.0 | 70 | 2.5 | Wind | ||||||||||
Grande Prairie | Alberta, Canada | 93 | 100.0 | 93 | 8.4 | Gas | ||||||||||
West Valley | Salt Lake City, UT | 200 | 100.0 | 200 | 10.6 | Gas | ||||||||||
Hillabee Energy Center | Alexander City, Alabama | 740 | 100.0 | 740 | 36.8 | Gas | ||||||||||
Colorado Bend Energy Center | Wharton, Texas | 550 | 100.0 | 550 | 17.0 | Gas | ||||||||||
Quail Run Energy Center (2) | Odessa, Texas | 550 | 100.0 | 550 | 15.3 | Gas | ||||||||||
Panther Creek | Nesquehoning, PA | 80 | 50.0 | 40 | 96.6 | Waste Coal | ||||||||||
Colver | Colver Township, PA | 102 | 25.0 | 26 | 99.2 | Waste Coal | ||||||||||
Sunnyside | Sunnyside, UT | 51 | 50.0 | 26 | 84.5 | Waste Coal | ||||||||||
ACE | Trona, CA | 102 | 31.1 | 32 | 88.0 | Coal | ||||||||||
Jasmin | Kern Co., CA | 35 | 50.0 | 18 | 87.7 | Coal | ||||||||||
POSO | Kern Co., CA | 35 | 50.0 | 18 | 92.0 | Coal | ||||||||||
Rocklin | Placer Co., CA | 24 | 50.0 | 12 | 80.6 | Biomass | ||||||||||
Fresno | Fresno, CA | 24 | 50.0 | 12 | 83.6 | Biomass | ||||||||||
Chinese Station | Jamestown, CA | 22 | 45.0 | 10 | 58.6 | Biomass | ||||||||||
Malacha | Muck Valley, CA | 32 | 50.0 | 16 | 10.6 | Hydro | ||||||||||
Constellation Solar (6) | Various | 9 | 100.0 | 9 | — | Solar | ||||||||||
SEGS IV | Kramer Junction, CA | 33 | 12.2 | 4 | 27.1 | Solar | ||||||||||
SEGS V | Kramer Junction, CA | 24 | 4.2 | 1 | 33.0 | Solar | ||||||||||
SEGS VI | Kramer Junction, CA | 34 | 8.8 | 3 | 28.4 | Solar | ||||||||||
Total Generating Facilities (3)(4) | 14,559 | 9,030 | ||||||||||||||
In January 2011, we completed the acquisition of Boston Generating's 2,950MW nameplate capacity (2,656 MW of summer seasonal claimed capacity) fleet of generating plants: four natural gas-fired plants, including Mystic 8 and 9 (1,580 MW), Fore River (787 MW), and Mystic 7 (574 MW) as well as a fuel oil plant, Mystic Jet (9 MW). After this acquisition, our total summer seasonal claimed capacity owned increased to approximately 11,686 MW.
In December 2009, we were selected by the State of Maryland to develop an approximately 17 MW solar photovoltaic power installation in Emmitsburg, Maryland. This $60 million solar facility will be constructed, owned, operated and maintained by us. We expect the project to be completed by December 2012.
* The sum
24
Table of the individual plant capacity MWs may not equal the totals due to the effectsContents
As of rounding.
In February 2008,December 31, 2010, we acquiredalso have a partially completed 774 MW gas-fired combined-cycle power generation50% ownership interest in a waste coal processing facility located in Alabama, which we plan to complete and have ready for commercial operation in early 2010. We discuss this acquisition in more detail inNote 15 to Consolidated Financial Statements.Hazelton, Pennsylvania.
The following table describes our processing facilities:
* Facility to be decommissioned in 2008.
We discuss our legal proceedings inNote 12 to Consolidated Financial Statements.
Item 4. Submission of Matters to Vote of Security Holders[Removed and Reserved]
Not applicable.
Executive Officers of the Registrant
Name | Age | Present Office | Other Offices or Positions Held During Past Five Years | |||
---|---|---|---|---|---|---|
Mayo A. Shattuck III | Chairman of the Board (since July 2002), President and Chief Executive Officer (since November 2001) of Constellation Energy | Chairman of the Board of | ||||
Michael J. Wallace (1) | 63 | Vice Chairman (since March 2008), Executive Vice President (since January 2004) and Chief Operating Officer (since May | President and Chief | |||
Henry B. Barron | ||||||
James L. Connaughton | ||||||
Chairman of the White House Council on Environmental Quality and Director of the White House Office of Environmental Policy | ||||||
Paul J. Allen | 59 | Senior Vice President (since January 2004) and Chief Environmental Officer (since June 2007) of Constellation Energy | ||||
Charles A. Berardesco | Senior Vice President (since | Vice | ||||
Brenda L. | Senior Vice President | Global Head of Strategy and Global Head of Derivative Services, Alternative Investment Services and Head of Treasury Services Risk Management—J.P. Morgan Chase & Company | ||||
Kenneth W. DeFontes, Jr. | 60 | Senior Vice President of Constellation Energy (since October 2004); and President and Chief Executive Officer of Baltimore Gas and Electric Company (since October 2004) | None | |||
Andrew L. Good | 43 | Senior Vice President, Corporate Strategy and Development of Constellation Energy (since November 2009) | Senior Vice President and Chief Financial Officer—Constellation Energy Resources; Senior Vice President and Chief Financial Officer—Constellation Energy Commodities Group; and Senior Vice President, Finance—Constellation Energy | |||
Kathleen W. Hyle | 52 | Senior Vice President of Constellation Energy (since September 2005); and Chief Operating Officer of Constellation Energy Resources (since November 2008) | Senior Vice President, Finance, and Chief Financial Officer—Constellation Energy Nuclear Group; Chief Financial Officer—UniStar Nuclear Energy; Senior Vice President, Finance—Constellation Energy; and Chief Financial Officer, Constellation NewEnergy | |||
Mary L. Lauria | 46 | Senior Vice President and Chief Human | Vice President and Chief Talent Officer—Constellation Energy; Vice President, Talent Management and Leadership Development—Wyeth; Director, Global Talent Management—Johnson & Johnson | |||
Jonathan W. Thayer | 39 | Senior Vice President and Chief Financial Officer of Constellation Energy (since October 2008) | Vice President and Managing Director, Corporate Strategy and Development—Constellation Energy; Treasurer—Constellation Energy; and Senior Vice President and Chief Financial Officer—Baltimore Gas and Electric Company |
Officers are elected by, and hold office at the will of, the Board of Directors and do not serve a "term of office" as such. There is no arrangement or understanding between any director or officer and any other person pursuant to which the director or officer was selected.
Item 5. Market for Registrant's Common Equity, Related Shareholder Matters, and Issuer Purchases of Equity Securities, and Unregistered Sales of Equity and Use of Proceeds
Stock Trading
Constellation Energy's common stock is traded under the ticker symbol CEG. It is listed on the New York and Chicago stock exchanges.
As of January 31, 2008,2011, there were 39,18633,239 common shareholders of record.
Dividend Policy
Constellation Energy pays dividends on its common stock after its Board of Directors declares them. There are no contractual limitations on Constellation Energy paying common stock dividends.dividends, unless Constellation Energy elects to defer interest payments on the 8.625% Series A Junior Subordinated Debentures due June 15, 2063, and any deferred interest remains unpaid.
Dividends have been paid continuously since 1910 on the common stock of Constellation Energy, BGE, and their predecessors. Future dividends depend upon future earnings, our financial condition, and other factors.
In January 2008,2011, we announced an increase in oura quarterly dividend from $0.435 to $0.4775of $0.24 per share payable April 1, 20082011 to holders of record at the close of business on March 10, 2008.2011. This is equivalent to an annual rate of $1.91$0.96 per share.
Quarterly dividends were declared on our common stock during 20072010 and 20062009 in the amounts set forth below.
BGE pays dividends on its common stock after its Board of Directors declares them. However, pursuant to the order issued by the Maryland PSC on October 30, 2009 in connection with its approval of the transaction with EDF, BGE cannot pay common dividends to Constellation Energy if (a) after the dividend payment, BGE's equity ratio would be below 48% as calculated under the Maryland PSC's ratemaking precedents or (b) BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. There are no contractualother limitations on BGE paying common stock dividends unless:
Common Stock Dividends and Price Ranges
| 2007 | 2006 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Price | | Price | ||||||||||||||
| Dividend Declared | Dividend Declared | ||||||||||||||||
| High | Low | High | Low | ||||||||||||||
First Quarter | $ | 0.435 | $ | 88.20 | $ | 68.78 | $ | 0.3775 | $ | 60.55 | $ | 54.01 | ||||||
Second Quarter | 0.435 | 95.57 | 82.71 | 0.3775 | 55.68 | 50.55 | ||||||||||||
Third Quarter | 0.435 | 98.20 | 76.64 | 0.3775 | 60.79 | 53.70 | ||||||||||||
Fourth Quarter | 0.435 | 104.29 | 85.81 | 0.3775 | 70.20 | 59.00 | ||||||||||||
Total | $ | 1.74 | $ | 1.51 | ||||||||||||||
| 2010 | 2009 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Price | | Price | |||||||||||||||
| Dividend Declared | Dividend Declared | |||||||||||||||||
| High | Low | High | Low | |||||||||||||||
First Quarter | $ | 0.24 | $ | 36.99 | $ | 31.08 | $ | 0.24 | $ | 27.97 | $ | 15.05 | |||||||
Second Quarter | 0.24 | 38.73 | 32.09 | 0.24 | 28.05 | 20.18 | |||||||||||||
Third Quarter | 0.24 | 35.10 | 28.21 | 0.24 | 33.37 | 25.76 | |||||||||||||
Fourth Quarter | 0.24 | 33.18 | 27.64 | 0.24 | 36.55 | 30.24 | |||||||||||||
Total | $ | 0.96 | $ | 0.96 | |||||||||||||||
Purchases of Equity Securities by the Issuer and Affiliated Purchases
Purchasers
The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.
Period | Total Number of Shares Purchased(1) | Average Price Paid for Shares | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Dollar Amount of Shares that May Yet Be Purchased Under the Plans and Programs (at month end)(2) | ||||||
---|---|---|---|---|---|---|---|---|---|---|
October 1 – October 31, 2007 | — | $ | — | — | $ | 1.0 billion | ||||
November 1 – November 30, 2007 | 200,000 | 96.31 | 2,023,527 | (3) | 750 million | |||||
December 1 – December 31, 2007 | 250,218 | 103.24 | — | 750 million | ||||||
Total | 450,218 | $ | 100.16 | 2,023,527 | — | |||||
Period | Total Number of Shares Purchased (1) | Average Price Paid for Shares | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Dollar Amount of Shares that May Yet Be Purchased Under the Plans and Programs (at month end) | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
October 1 - October 31, 2010 | 113 | $ | 32.34 | — | — | ||||||||
November 1 - November 30, 2010 | — | — | — | — | |||||||||
December 1 - December 31, 2010 | 92,643 | 30.84 | — | — | |||||||||
Total | 92,756 | $ | 30.84 | — | — | ||||||||
26(2)In October 2007, our board
Table of Constellation Energy Group, Inc. and Subsidiaries Summary of Operations Total Revenues Total Expenses Equity investment earnings (losses) Gain on Sale of Interest in CENG Net Gain (Loss) on Divestitures (Loss) Income From Operations Gains on Sales of CEP LLC equity Other (Expense) Income Fixed Charges (Loss) Income Before Income Taxes Income Tax (Benefit) Expense (Loss) Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles (Loss) Income from Discontinued Operations, Net of Income Taxes Net (Loss) Income Net Loss (Income) Attributable to Noncontrolling Interests and BGE Preference Stock Dividends Net (Loss) Income Attributable to Common Stock (Loss) Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles Assuming Dilution (Loss) Income from Discontinued Operations (Loss) Earnings Per Common Share Assuming Dilution Dividends Declared Per Common Share Summary of Financial Condition Total Assets Current Portion of Long-Term Debt Capitalization: Long-Term Debt Noncontrolling Interests BGE Preference Stock Not Subject to Mandatory Redemption Common Shareholders' Equity Total Capitalization Financial Statistics at Year End Ratio of Earnings to Fixed Charges Book Value Per Share of Common Stock N/A—Calculation is not applicable as a result of the net loss for 2010 and 2008. We discuss items that affect comparability between years, including acquisitions and dispositions, accounting changes and other items, inItem 7. Management's Discussion and Analysis.directors approved a common share repurchase program for up to $1 billion of our outstanding common shares. The program is expected to be executed over the 24 months following approval in a manner that preserves flexibility to pursue additional strategic investment opportunities.(3)Represents shares repurchased pursuant to an accelerated share repurchase agreement entered into with a financial institution. The final price of the shares repurchased was determined based on a discount to the volume-weighted average trading price of $100.53 per share of our common stock. In January 2008, the financial institution delivered 514,376 additional shares to us at the completion of the transaction.SeeNote 9 to Consolidated Financial Statements for a further description of our common share repurchase program and the accelerated share repurchase agreement.
Item 6. Selected Financial Data 2007 2006 2005 2004 2003 (In millions, except per share amounts) Summary of Operations Total Revenues $ 21,193.2 $ 19,284.9 $ 16,968.3 $ 12,127.2 $ 9,342.8 Total Expenses 19,858.8 18,025.2 16,023.8 11,209.1 8,395.5 Gain on Sale of Gas-Fired Plants — 73.8 — — — Income From Operations 1,334.4 1,333.5 944.5 918.1 947.3 Gain on sales of CEP equity 63.3 28.7 — — — Other Income 158.6 66.1 65.5 25.5 20.6 Fixed Charges 305.6 328.7 310.2 326.8 336.3 Income Before Income Taxes 1,250.7 1,099.6 699.8 616.8 631.6 Income Taxes 428.3 351.0 163.9 118.4 222.2 Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles 822.4 748.6 535.9 498.4 409.4 (Loss) Income from Discontinued Operations, Net of Income Taxes (0.9 ) 187.8 94.4 41.3 66.3 Cumulative Effects of Changes in Accounting Principles, Net of Income Taxes — — (7.2 ) — (198.4 ) Net Income $ 821.5 $ 936.4 $ 623.1 $ 539.7 $ 277.3 Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles Assuming Dilution $ 4.51 $ 4.12 $ 2.98 $ 2.88 $ 2.45 (Loss) Income from Discontinued Operations (0.01 ) 1.04 0.53 0.24 0.40 Cumulative Effects of Changes in Accounting Principles — — (0.04 ) — (1.19 ) Earnings Per Common Share Assuming Dilution $ 4.50 $ 5.16 $ 3.47 $ 3.12 $ 1.66 Dividends Declared Per Common Share $ 1.74 $ 1.51 $ 1.34 $ 1.14 $ 1.04
Summary of Financial Condition
Total Assets $ 21,945.7 $ 21,801.6 $ 21,473.9 $ 17,347.1 $ 15,593.0 Current Portion of Long-Term Debt $ 380.6 $ 878.8 $ 491.3 $ 480.4 $ 343.2 Capitalization Long-Term Debt $ 4,660.5 $ 4,222.3 $ 4,369.3 $ 4,813.2 $ 5,039.2 Minority Interests 19.2 94.5 22.4 90.9 113.4 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 190.0 190.0 190.0 Common Shareholders' Equity 5,340.2 4,609.3 4,915.5 4,726.9 4,140.5 Total Capitalization $ 10,209.9 $ 9,116.1 $ 9,497.2 $ 9,821.0 $ 9,483.1
Financial Statistics at Year End
Ratio of Earnings to Fixed Charges 3.84 4.05 3.04 2.71 2.69 Book Value Per Share of Common Stock $ 29.93 $ 25.54 $ 27.57 $ 26.81 $ 24.68 2010 2009 2008 2007 2006 (In millions, except per share amounts) $ 14,340.0 $ 15,598.8 $ 19,741.9 $ 21,185.1 $ 19,271.1 15,853.8 14,588.5 20,821.9 19,858.8 18,025.2 25.0 (6.1 ) 76.4 8.1 13.8 — 7,445.6 — — — 245.8 (468.8 ) 25.5 — 73.8 (1,243.0 ) 7,981.0 (978.1 ) 1,334.4 1,333.5 — — — 63.3 28.7 (76.7 ) (140.7 ) (69.5 ) 157.4 66.8 277.8 350.1 349.1 292.4 315.5 (1,597.5 ) 7,490.2 (1,396.7 ) 1,262.7 1,113.5 (665.7 ) 2,986.8 (78.3 ) 428.3 351.0 (931.8 ) 4,503.4 (1,318.4 ) 834.4 762.5 — — — (0.9 ) 187.8 $ (931.8 ) $ 4,503.4 $ (1,318.4 ) $ 833.5 $ 950.3 50.8 60.0 (4.0 ) 12.0 13.9 $ (982.6 ) $ 4,443.4 $ (1,314.4 ) $ 821.5 $ 936.4 $ (4.90 ) $ 22.19 $ (7.34 ) $ 4.51 $ 4.12 — — — (0.01 ) 1.04 $ (4.90 ) $ 22.19 $ (7.34 ) $ 4.50 $ 5.16 $ 0.96 $ 0.96 $ 1.91 $ 1.74 $ 1.51 $ 20,018.5 $ 23,544.4 $ 22,284.1 $ 21,742.3 $ 21,801.6 $ 305.3 $ 56.9 $ 2,591.5 $ 380.6 $ 878.8 $ 4,448.8 $ 4,814.0 $ 5,098.7 $ 4,660.5 $ 4,222.3 88.8 75.3 20.1 19.2 94.5 190.0 190.0 190.0 190.0 190.0 7,829.2 8,697.1 3,181.4 5,340.2 4,609.3 $ 12,556.8 $ 13,776.4 $ 8,490.2 $ 10,209.9 $ 9,116.1 N/A 14.76 N/A 3.84 4.05 $ 39.19 $ 43.27 $ 15.98 $ 29.93 $ 25.54
Baltimore Gas and Electric Company and Subsidiaries
| 2007 | 2006 | 2005 | 2004 | 2003 | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||||||||
Summary of Operations | ||||||||||||||||||
Total Revenues | $ | 3,418.5 | $ | 3,015.4 | $ | 3,009.3 | $ | 2,724.7 | $ | 2,647.6 | ||||||||
Total Expenses | 3,084.2 | 2,646.3 | 2,612.8 | 2,353.3 | 2,262.6 | |||||||||||||
Income From Operations | 334.3 | 369.1 | 396.5 | 371.4 | 385.0 | |||||||||||||
Other Income (Expense) | 26.8 | 6.0 | 5.9 | (6.4 | ) | (5.4 | ) | |||||||||||
Fixed Charges | 125.3 | 102.6 | 93.5 | 96.2 | 111.2 | |||||||||||||
Income Before Income Taxes | 235.8 | 272.5 | 308.9 | 268.8 | 268.4 | |||||||||||||
Income Taxes | 96.0 | 102.2 | 119.9 | 102.5 | 105.2 | |||||||||||||
Net Income | 139.8 | 170.3 | 189.0 | 166.3 | 163.2 | |||||||||||||
Preference Stock Dividends | 13.2 | 13.2 | 13.2 | 13.2 | 13.2 | |||||||||||||
Earnings Applicable to Common Stock | $ | 126.6 | $ | 157.1 | $ | 175.8 | $ | 153.1 | $ | 150.0 | ||||||||
Summary of Financial Condition | ||||||||||||||||||
Total Assets | $ | 5,783.0 | $ | 5,140.7 | $ | 4,742.1 | $ | 4,662.9 | $ | 4,706.6 | ||||||||
Current Portion of Long-Term Debt | $ | 375.0 | $ | 258.3 | $ | 469.6 | $ | 165.9 | $ | 330.6 | ||||||||
Capitalization | ||||||||||||||||||
Long-Term Debt | $ | 1,862.5 | $ | 1,480.5 | $ | 1,015.1 | $ | 1,359.5 | $ | 1,343.7 | ||||||||
Minority Interest | 16.8 | 16.7 | 18.3 | 18.7 | 18.9 | |||||||||||||
Preference Stock Not Subject to Mandatory Redemption | 190.0 | 190.0 | 190.0 | 190.0 | 190.0 | |||||||||||||
Common Shareholder's Equity | 1,671.7 | 1,651.5 | 1,622.5 | 1,566.0 | 1,487.7 | |||||||||||||
Total Capitalization | $ | 3,741.0 | $ | 3,338.7 | $ | 2,845.9 | $ | 3,134.2 | $ | 3,040.3 | ||||||||
Financial Statistics at Year End | ||||||||||||||||||
Ratio of Earnings to Fixed Charges | 2.84 | 3.60 | 4.22 | 3.75 | 3.36 | |||||||||||||
Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends | 2.42 | 2.99 | 3.45 | 3.08 | 2.82 |
| 2010 | 2009 | 2008 | 2007 | 2006 | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||||||||
Summary of Operations | ||||||||||||||||||
Total Revenues | $ | 3,461.7 | $ | 3,579.0 | $ | 3,703.7 | $ | 3,418.5 | $ | 3,015.4 | ||||||||
Total Expenses | 3,107.5 | 3,310.6 | 3,521.2 | 3,084.2 | 2,646.3 | |||||||||||||
Income From Operations | 354.2 | 268.4 | 182.5 | 334.3 | 369.1 | |||||||||||||
Other Income | 20.8 | 25.4 | 29.6 | 26.9 | 6.0 | |||||||||||||
Fixed Charges | 130.3 | 139.3 | 139.9 | 125.3 | 102.6 | |||||||||||||
Income Before Income Taxes | 244.7 | 154.5 | 72.2 | 235.9 | 272.5 | |||||||||||||
Income Taxes | 97.1 | 63.8 | 20.7 | 96.0 | 102.2 | |||||||||||||
Net Income | 147.6 | 90.7 | 51.5 | 139.9 | 170.3 | |||||||||||||
Preference Stock Dividends | 13.2 | 13.2 | 13.2 | 13.2 | 13.2 | |||||||||||||
Net Income Attributable to Common Stock before Noncontrolling Interests | $ | 134.4 | $ | 77.5 | $ | 38.3 | $ | 126.7 | $ | 157.1 | ||||||||
Net Loss (Income) Attributable to Noncontrolling Interests | — | 7.3 | — | (0.1 | ) | — | ||||||||||||
Net Income Attributable to Common Stock | $ | 134.4 | $ | 84.8 | $ | 38.3 | $ | 126.6 | $ | 157.1 | ||||||||
Summary of Financial Condition | ||||||||||||||||||
Total Assets | $ | 6,667.3 | $ | 6,453.1 | $ | 6,086.2 | $ | 5,783.0 | $ | 5,140.7 | ||||||||
Current Portion of Long-Term Debt | $ | 81.7 | $ | 56.5 | $ | 90.0 | $ | 375.0 | $ | 258.3 | ||||||||
Capitalization | ||||||||||||||||||
Long-Term Debt | $ | 2,059.9 | $ | 2,141.4 | $ | 2,197.7 | $ | 1,862.5 | $ | 1,480.5 | ||||||||
Noncontrolling Interest | — | 17.6 | 16.9 | 16.8 | 16.7 | |||||||||||||
Preference Stock Not Subject to Mandatory Redemption | 190.0 | 190.0 | 190.0 | 190.0 | 190.0 | |||||||||||||
Common Shareholder's Equity | 2,073.2 | 1,938.8 | 1,538.2 | 1,671.7 | 1,651.5 | |||||||||||||
Total Capitalization | $ | 4,323.1 | $ | 4,287.8 | $ | 3,942.8 | $ | 3,741.0 | $ | 3,338.7 | ||||||||
Financial Statistics at Year End | ||||||||||||||||||
Ratio of Earnings to Fixed Charges | 2.80 | 2.07 | 1.50 | 2.84 | 3.60 | |||||||||||||
Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends | 2.41 | 1.80 | 1.33 | 2.42 | 2.99 |
We discuss items that affect comparability between years, including accounting changes and other items, inItem 7. Management's Discussion and Analysis.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Introduction and Overview
Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various subsidiaries includingand joint ventures organized around three business segments: a merchant energygeneration business (Generation), a customer supply business (NewEnergy), and Baltimore Gas and Electric Company (BGE). We describe our operating segments inNote 3 to Consolidated Financial Statements..
This report 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. We discuss our business in more detail inItem 1. Business section and the risk factors affecting our business inItem 1A. Risk Factors section.
In this discussion and analysis, we will explain the general financial condition of 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 (Loss), which present the results of our operations for 2007, 2006,2010, 2009, and 2005.2008. We analyze and explain the differences between periods in the specific line items of our Consolidated Statements of Income.Income (Loss).
We have organized our discussion and analysis as follows:
We are pursuing aOur strategy of is to provide innovative and risk-mitigating energy products and solutions to North American wholesale and retail customers. Overall, we strive to serve our customers with diverse products and solutions to meet their energy needs.
In executing this strategy, we leverage our core strengths of:
Our merchant energyNewEnergy business focuses on short-term and long-term purchases and sales of energy, capacity,electricity, natural gas, and related products to various customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, commercial,governmental, and governmental customers.residential customers in competitive markets. The retail NewEnergy customer supply operation combines a unified sales force with a customer-centric model that leverages technology to broaden the range of products and services we offer, which we believe promotes stronger customer relationships. This model focuses on efficiency and cost reduction, which we believe will provide a platform that is scalable and able to capitalize on opportunities for future growth.
We obtain thisNewEnergy obtains energy throughfrom both owned and contracted supply resources.resources and actively manages these physical and contractual assets in order to derive incremental value. Additionally, NewEnergy is involved in the development, exploration and exploitation of natural gas properties.
Our generationGeneration business has a fleet of plants that is strategically located in deregulated markets that support our customer-facing business and includes various fuel types, such as nuclear, coal, natural gas, oil, nuclear, and renewable sources. In additionWe generally have load obligations greater than our generation output. Going forward, we intend to owning generating facilities,invest in generation assets in the markets where we contract for power from other merchant providers, typically through power purchase agreements. We will use bothserve load to provide a more efficient and balanced profile between our owned generation production and our contractedcustomer load obligations.
Our strategy is enabled by a fleet of generation to supportfacilities and our competitive supply operations.
In addition, our merchant energy business is active in both upstream and downstream natural gas areas as well as coal sourcing and logistics services for the variable and fixed supply needs of global customers.
We are a leading national competitive supplier of energy. In our wholesale and commercial and industrial retail marketing activities we are leveraging our recognized expertise in providing full requirements energy and energy-related services to enter markets, capture market share, and organically grow these businesses. Through the application of technology, intellectual capital, process improvement, and increased scale, we are seeking to reduce the cost of delivering full requirements energy and energy related services and managing risk.
We are also responding proactively to customer needs by expanding the variety of products we offer. Our wholesale competitive supply activities include a growing operation that markets physical energy products and risk management and logistics services to generators, distributors, producers of coal, natural gas and fuel oil, and other consumers.
We trade energy and energy-related commodities and deploy risk capital in the managementcapabilities. This combination of our portfolioGeneration and NewEnergy businesses also allows us to operate in order to earn additional returns. These activities are managed through daily value at riska manner so we can minimize our collateral requirements. We discuss our collateral requirements in theCollateral section.
BGE, our regulated utility located in central Maryland, provides standard offer service and stop loss limits and liquidity guidelines.
Within our retail competitive supply activities, we are marketing a broader array of products and expanding our markets. Over time, we may consider integrating the sale ofdistributes electricity and natural gas to provide one energy procurement solution for our customers.
Collectively, the integration of owned and contracted electric generation assets with origination, fuel procurement, and risk management expertise, allows our merchant energy business to earn incremental margin and more effectively manage energy and commodity price risk over geographic regions and over time. Our focus BGE is on providing solutions to customers' energy needs, and our wholesale marketing, risk management, and trading operation adds value to our owned and contracted generation assets by providing national market access, market infrastructure, real-time market intelligence, risk management and arbitrage opportunities, and transmission and transportation expertise. Generation capacity supports our wholesale marketing, risk management, and trading operation by providing a source of reliable power supply.
To achieve our strategic objectives, we expect to continue to pursue opportunities that expand our access to customers and to support our wholesale marketing, risk management, and trading operation with generation assets that have diversified geographic, fuel, and dispatch characteristics. We also expect to grow through buying and selling a greater number of physical energy products and services to large energy customers. We expect to
achieve operating efficiencies within our competitive supply operation and our generation fleet by selling more products through our existing sales force, benefiting from efficiencies of scale, adding to the capacity of existing plants, and making our business processes more efficient.
We expect BGE and our other retail energy service businesses to grow through focused and disciplined expansion primarily from new customers. At BGE, we are also focusedfocusing on enhancing reliability and customer satisfaction, and is implementing customer demand response initiatives.initiatives, including a comprehensive smart grid initiative and a full portfolio of conservation programs.
Customer choice,The ability of energy consumers to choose their supplier, regulatory change, and energy market conditions significantly impact our business. In response, we regularly evaluate our strategies with these goals in mind: to improve our competitive position, toposition. We actively anticipate and adapt to the business environment and regulatory changes andthat impact our industry. We are committed to maintainmaintaining a strong balance sheet and investment-grade credit quality.
We are constantly reevaluating our strategies
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quality by making disciplined investment and might consider:
With the evolving regulatory environment surrounding customer choice, increasing competition, and the growth of our merchant energy business, variousVarious factors affect our financial results. We discuss some of these factors in more detail in theItem 1. Business—Competition section. We also discuss these various factors in theForward Looking Statements andItem 1A. Risk Factors sections.
OverThroughout 2008, volatility in the last several years,financial markets intensified, leading to dramatic declines in equity and commodity prices and substantially reduced liquidity in the energycredit markets. Most equity indices declined significantly, the cost of credit default swaps and bond spreads increased substantially, and credit markets have beeneffectively ceased to be accessible for all but the most highly volatile with significant changesrated borrowers. In 2009 and 2010, markets in naturalwhich we operate were affected by declining prices for power, gas, power, oil, coal, and emission allowance prices. The volatilitycapacity. We discuss the impact of the energy markets impactsdeclining commodity prices on our credit portfolio,future earnings in more detail in theGeneration Results section.
During 2009 and 2010, we improved our liquidity and reduced our business risk in response to these market events. We discuss our liquidity and collateral requirements in theFinancial Condition section. We continue to actively manage our credit portfoliorisk to attempt to reduce the impact of a potential counterparty default. We discuss our customer (counterparty) credit and other risks in more detail in theMarket Risk Management section.
In addition, the volatility of the energy marketsCompetition also impacts our liquidity and collateral requirements.business. We discuss our liquidity in theFinancial Condition section.
Competition
We face competition in the sale of electricity, natural gas, and coal in wholesale energy markets and to retail customers.
Various states have moved to restructure their retail electricity and gas markets. The pace of deregulation in these states varies based on historical moves to competition and responses to recent market events. While many states continue to support or expand retail competition and industry restructuring, other states that were considering deregulation have slowed their plans or postponed consideration. In addition, other states are reconsidering deregulation.
Specifically, legislatures in a number of states are considering, to varying degrees, legislation currently to either eliminate or expand retail choice programs. In addition, many states have initiated proceedings to reconsider the method of wholesale procurement for meeting their utilities' default/provider-of-last-resort requirements. Both the reconsideration of retail choice and possible new methodologies for wholesale procurement could affect our customer supply group's future opportunities to service commercial and industrial customers and the ability to provide wholesale products to utilities. The outcome of these efforts cannot be predicted, but they could have a material effect on our financial results.
All BGE electricity and gas customers have the option to purchase electricity and gas from alternate suppliers.
We discuss merchant competition in more detail inItem 1. Business—Competition section.
The impacts of electric deregulationcompetition on BGE in Maryland are discussed inItem 1. Business—Baltimore Gas and Electric Company—Electric Business—Electric Competition section.
Regulation—Maryland
Maryland PSC
In addition to electric restructuring,competition, which is discussedwe discuss inItem 1. Business—Baltimore Gas and Electric Company—Electric Business—Electric Competition section, regulation by the Maryland PSCPublic Service Commission (Maryland PSC) significantly influences BGE's businesses. The Maryland PSC determines the rates that BGE can charge customers of its electric distribution and gas businesses. The Maryland PSC incorporates into BGE's standard offer service rates the transmission rates determined by the Federal Energy Regulatory Commission (FERC). BGE's electric rates are unbundled inshown on customer billings to showas separate components for delivery service (i.e. base rates), electric supply (commodity charge)charge and transmission), transmission, a universal service surcharge, and certain taxes.taxes and surcharges. The rates for BGE's regulated gas business continue to consist of a delivery charge (base rate)rates as well as certain taxes and surcharges) and a commodity charge.
Purchase of Supplier Receivables
Effective July 15, 2010, BGE, pursuant to Maryland PSC requirements, began to purchase receivables at a discount from third party competitive energy suppliers that provide our customers electricity and/or gas. The discount rate applied to the receivables is a regulated rate which is intended to cover BGE's costs associated with purchasing these receivables, such as uncollectibles, and is subject to an annual true-up to reflect actual costs.
Order Approving Membership Interest Sale in CENG to EDF
In October 2009, the Maryland PSC issued an order approving the sale of a 49.99% membership interest in CENG to EDF subject to the following conditions, with which both Constellation Energy and EDF complied or are complying:
Senate Bills 1 and 400Maryland Settlement Agreement
In March 2008, Constellation Energy, BGE, and a Constellation Energy affiliate entered into a settlement agreement with the State of Maryland, the Maryland PSC and certain State of
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Maryland officials to resolve pending litigation and to settle other prior legal, regulatory, and legislative issues. On April 24, 2008, the Governor of Maryland signed enabling legislation, which became effective on June 2006,1, 2008. Pursuant to the terms of the settlement agreement:
In connection with these provisions of Senate Bill 1:
In connection
Further, in April 2007, Senate Bill 400 was enacted, which made certain modifications to Senate Bill 1. Pursuant to Senate Bill 400, the Maryland PSC was required to initiate several studies, including studies relating to stranded costs, the costs and benefits of various options for reregulation, and the structure of the electric industry in Maryland. In addition, the Maryland PSC has indicated that they are studying the relationship between Constellation Energy and BGE.
In December 2007, the Maryland PSC issued an interim report addressing the costs and benefits of various options for reregulation and recommending actions to be taken to address an anticipated shortage of generation and transmission capacity in Maryland, which included implementation of demand response initiatives and requiring utilities to enter into long-term power purchase contracts with suppliers.
In January 2008, the Maryland PSC issued another interim report that indicated that the Maryland PSC would initiate proceedings into payments made by BGE customers for stranded costs resulting from BGE's transfer of generation assets to certain Constellation Energy affiliates in connection with deregulation and into Constellation Energy's management of its nuclear decommissioning funds. This interim report also recommended that the Maryland legislature enact legislation to provide the Maryland PSC with the authority to regulate nuclear decommissioning funds and consider legislation that would provide the Maryland PSC with the authority to consider reallocation of the liability for nuclear decommissioning among Constellation Energy, BGE and customers or to otherwise order relief for customers. Similarly, the interim report also recommended that the Maryland legislature consider legislation to order relief for customers depending on the outcome of the Maryland PSC's stranded cost proceeding.
The Maryland PSC is required to issue a final report in December 2008. We cannot at this time predict the ultimate outcome of these inquiries, studies, and recommendations or their actual effect on our, or BGE's financial results, but it could be material. In addition, one or more parties may challenge in court one or more provisions of Senate Bills 1 and 400. The outcome of any challenges and the uncertainty that could result cannot be predicted.
We discuss the market risk of our regulated electric business in more detail in theMarket Risk section.
Base Rates
Base rates are the rates the Maryland PSC allows BGE to charge its customers for the cost of providing them delivery service, plus a profit. BGE has both electric base rates and gas base rates. Higher electric base rates apply during the summer when the demand for electricity is higher. Gas base rates are not affected by seasonal changes.
BGE may ask the Maryland PSC to increase base rates from time to time. In 2008, BGE planstime, subject to file a combination electric and gas base rate case.limitations in the Maryland PSC's October 2009 order approving our transaction with EDF. The Maryland PSC historically has allowed BGE to increase base rates to recover its utility plant investment and operating costs, plus a profit. Generally, rate increases improve the earnings of our regulated business because they allow us to collect more revenue. However, rate increases are normally granted based on historical data and those increases may not always keep pace with increasing costs. Other parties may petition the Maryland PSC to decrease base rates.
BGE's most recently approvedIn May 2010, BGE filed an application for an increase in its electric and gas base rates with the Maryland PSC. In August 2010, BGE updated its application to request an increase of $47.2 million and $30.4 million in its electric and gas base rates, respectively. The request was based upon an 8.99% rate of return with an 11.65% return on equity and a 52% equity ratio. While BGE demonstrated the need for a $92.3 million increase in electric base rates, distribution rate base was 9.4% (approvedrevenues awarded to BGE in 1993). BGE's most recently approved return on gas rate base was 8.49% (approved in 2005).the case were subject to a 5% cap pursuant to the terms of the 2008 settlement agreement with the State of Maryland as well as the Maryland PSC's order approving the EDF transaction.
InOn December 2005,6, 2010, the Maryland PSC issued an abbreviated order grantingauthorizing BGE to increase electric distribution rates by no more than $31.0 million and increase gas distribution rates by no more than $9.8 million for service rendered on or after December 4, 2010. The electric distribution rate increase was based upon an 8.06% rate of return with a $35.6 million annual9.86% return on equity and a 52% equity ratio. The gas distribution rate increase in its gas base rates. In December 2006,was based upon a 7.90% rate of return with a 9.56% return on equity and a 52% equity ratio. BGE implemented the Baltimore City Circuit Court upheldabbreviated order, will evaluate the comprehensive rate order. However, certain parties have filed an appeal with the Court of Special Appeals. We cannot provide assuranceorder that the Maryland PSC's orderPSC will not be reversedissue in whole or part or that certain issuesthe near future and will not be remanded toassess its alternatives. BGE cannot predict the Maryland PSC for reconsideration.outcome of this assessment.
Revenue Decoupling
Beginning in 2008, BGE willThe Maryland PSC has allowed us to record a monthly adjustment to itsour electric distribution revenues from residential and small commercial customers since 2008 and for the majority of our large commercial and industrial customers since February 2009 to eliminate the effect of abnormal weather and usage patterns per customer on itsour electric distribution volumes, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in accordance with Maryland PSC requirements.consumption levels. This means that BGE's monthly electricBGE recognizes revenues at
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Maryland PSC-approved levels per customer, regardless of what actual distribution revenues from residential and small commercial customers will be based on weather and usage that is considered normalvolumes were for the month.a billing period. Therefore, while these revenues are affected by customer growth, andthey will not be affected by actual weather or usage conditions. We then bill or credit impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings. We have a similar revenue decoupling mechanism in our gas business.
Demand Response and Advanced Metering Programs
In order to implement advanced metering and demand response programs, BGE will deferdefers costs associated with theseits demand response programs as a regulatory asset and recoverrecovers these costs from customers in future periods.
In August 2010, the Maryland PSC approved a comprehensive smart grid initiative for BGE which includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of approximately $480 million. The Maryland PSC's approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is delivered to customers. Under a grant from the United States Department of Energy (DOE) BGE is a recipient of $200 million in federal funding for its smart grid and other related initiatives. This grant allows BGE to be reimbursed for smart grid and other expenditures up to $200 million, substantially reducing the total cost of these initiatives.
We discuss the advanced metering and demand responseBGE's electric load management programs in more detail inItem 1. Business—Baltimore Gas and Electric Company—Electric Load Management. We discuss the associated regulatory assets inNote 6 to Consolidated Financial Statements.
Electric Commodity and Transmission ChargesStandard Offer Service
BGE is obligated by the Maryland PSC to provide market-based standard offer service (SOS) to all of its electric commoditycustomers who elect not to select a competitive energy supplier. The SOS rates charged recover BGE's wholesale power supply costs and transmission charges (standard offer service), includinginclude an administrative fee. The administrative fee includes a shareholder return component and an incremental cost component. However, BGE is required under the impact of the enactmentterms of Senate Bill 1 to provide all residential electric customers a credit for the residential return component of the administrative fee. This credit will be given to customers through December 31, 2016. Currently, BGE is involved in a Maryland are discussed inBusiness Environment—Regulation—Maryland—Senate Bills 1 and 400 section.PSC proceeding to determine the future, on-going structure of the SOS administrative fee charged to all SOS customers.
Gas Commodity Charge
BGE charges its gas customers separately for the natural gas they purchase. The price BGE charges for the natural gas is based on a market-based rates incentive mechanism approved by the Maryland PSC. We discuss market-based rates in more detail in theRegulated Gas Business—Gas Cost AdjustmentsBusiness section and inNote 6.6 to Consolidated Financial Statements.
Potential Reliability and Quality of Service Standards
The State of Maryland is considering legislative and regulatory changes that would impose new reliability and quality of service standards on electric and gas companies, as well as penalties for failure to meet those standards. We cannot at this time predict the final outcome of this process or how such outcome may affect our, or BGE's, financial results.
Federal Regulation
FERC
The FERC has jurisdiction over various aspects of our business, including electric transmission and wholesale natural gas and electricity sales. BGE transmission rates are updated annually based on a formula methodology approved by FERC. The rates also include transmission investment incentives approved by FERC in a number of orders issued in July and November ofcovering various new transmission investment projects since 2007. We believe that FERC's continued commitment to fair and efficient wholesale energy markets should continue to result in improvements to competitive markets across various regions.
Since 1997, operation of BGE's transmission system has been under the authority of PJM Interconnection (PJM), the Regional Transmission Organization (RTO) for the Mid-Atlantic region, pursuant to FERC oversight. As the transmission operator, PJM operatesadministers the energy markets and conducts day-to-day operations of the bulk power system. The liability of transmission owners, including BGE, and power generators is limited to those damages caused by the gross negligence of such entities.
In addition to PJM, RTOs exist in other regions of the country such as the Midwest, New York, Texas, and New England. In additionSimilar to PJM, these RTOs also administer the energy market for their region and are responsible for operation of the transmission system and responsibility for transmission system reliability, these RTOs also operate energy markets for their region pursuant to FERC's oversight.reliability. Our merchant energy business participatesGeneration and NewEnergy businesses participate in these regional energy markets. These markets are continuing to develop, and revisions to market structure are subject to review and approval by FERC. We cannot predict the outcome of any reviews at this time. However, changes to the structure of these markets could have a material effect on our financial results.
FERC Initiatives
Ongoing initiatives at FERC have included a review of its methodology for the granting of market-based rate authority to sellers of electricity. FERC has established interim tests that will be usedit uses to determine the extent to which companies may have market power in certain regions. Where FERC finds that market power is found to exist, FERCexists, it may require companies to implement measures to mitigate the market power in order to maintain market-based rate authority. We believe that our entities selling wholesale power continue to satisfy FERC's test for determining whether to grant a public utility market-based rate authority.
In November 2004, FERC eliminated through and out transmission rates between the Midwest Independent System Operator (MISO) and PJM and put in place Seams Elimination Charge/Cost Adjustment/Assignment (SECA) transition rates, which are paid by the transmission customers of MISO and
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PJM and allocated among the various transmission owners in PJM and MISO. The SECA transition rates were in effect from December 1, 2004 through March 31, 2006. FERC set for hearing the various compliance filings that established the level of the SECA rates and has indicated that the SECA rates are being recovered from the MISO and PJM transmission customers subject to refund by the MISO and PJM transmission owners.
We are a recipient of SECA payments, payer of SECA charges, and supplier to whom such charges may be shifted. Administrative hearings regarding the SECA charges concluded in May 2006, and an initial decision from the FERC administrative law judge (ALJ) was issued in August 2006. The decision of the ALJ generally found in favor of reducing the overall SECA liability. The decision, if upheld, is expected to significantly reduce the overall SECA liability at issueIn May 2010, FERC issued an order approving in this proceeding. However,part and reversing in part the ALJ also alloweddecision. The FERC order results in additional SECA charges to be shifted to upstream suppliers, subject to certain adjustments. Therefore, certain charges could be shifted to our wholesale marketing, risk management, and trading operation. Thisliabilities being imposed on us. In June 2010, we filed a request for rehearing of the FERC order on the ALJ decision, will be reviewed byas did other interested parties. The rehearing requests are pending at FERC. We are unable to predict the timing or final outcomeIn July 2010, BGE filed a petition for review of FERC's SECA rate proceeding. However, as the amounts collected underapproval of the SECA rates are subjectmethodology, and this appeal is being held in abeyance pending action by FERC on the pending rehearing requests. In the interim, PJM and MISO have made filings at FERC to refundcomply with the May 2010 decision and to impose charges accordingly. Depending on the ultimate outcome, of the proceeding establishing SECA rates is uncertain, the result of this proceeding may have a material effect on our financial results.
Capacity Markets
In April 2006, FERC issued an initial order approving PJM's proposal to restructure itsgeneral, capacity market which establishesdesign revisions are routinely proposed and considered on an ongoing basis. Such changes are subject to FERC's review and approval. Currently, we cannot predict the method by which we are paid for making generating plant capacity availableoutcome of these proceedings or the possible effect on our, or BGE's, financial results.
Through 2008 and 2009, PJM made several filings at FERC proposing various revisions to PJM. Theits capacity market, or Reliability Pricing Model (RPM) was approved by, including the determination of the cost-of-new-entry (CONE), which is an important component in determining the price paid to capacity resources in PJM. PJM also proposed revisions relating to the participation of energy efficiency and demand resources, and market power and mitigation rules. Some of these matters are still pending at FERC. While recent RPM design changes have not yet had a material effect on our financial results, we cannot predict the outcome of the issues still pending or on any capacity market design changes that result from new regulatory requirements. Such changes could have a material impact on our financial results.
In May 2008, five state public service commissions, including the Maryland PSC, consumer advocates, and others filed a complaint against PJM at the FERC, in December 2006 after settlement proceedings. FERC in June and November 2007 upheldalleging that the RPM settlement in responseproduced unreasonable prices during the period from June 1, 2008 through May 31, 2011. The complaint requested that FERC establish a refund effective date of June 1, 2008, reject the results of the 2007/08 through 2010/11 RPM capacity auction results, and significantly reduce prices for capacity beginning as of June 1, 2008 through 2011/12. FERC dismissed the complaint and denied rehearing, and ultimately the Maryland PSC and New Jersey Board of Public Utilities appealed the case to requests for rehearing. An appeal of FERC's decisions on RPM was filed in January 2008 in the United States Court of Appeals for the District of Columbia Circuit. Currently, weColumbia. In February 2011, the court denied the petition for review and held that FERC adequately explained why the RPM auction structure was just and reasonable. The petitioners could seek to appeal the court's decision to the United States Supreme Court. We cannot predict with certainty what effectat this time whether the resultspetitioners will seek an appeal or the outcome of these challenges will have on our, or BGE's, financial results.any further proceedings.
AlsoIn April 2009, the Attorney General of Connecticut, the Connecticut Department of Public Utilities and Office of Consumer Counsel (together, the Connecticut Parties) filed complaints at FERC alleging improper energy bidding behavior since December 1, 2006 by generators located in January 2008New York that also received capacity payments within ISO-New England. In May 2009, the Connecticut Parties filed an amended complaint asserting that Constellation Energy Commodities Group, Inc. (CCG) and others received capacity payments while never intending to perform as capacity resources. The revised allegations assert that certain generators engaged in connection"economic withholding" by submitting energy bids at or near the offer cap. Since December 2006, CCG has received approximately $7 million in payments for capacity offered into ISO-New England associated with RPM, PJM filed revisionsConstellation Energy's previously wholly owned nuclear facilities located in NY. In August 2009, FERC issued an order setting this matter for a public hearing before an ALJ to itsdetermine the intent of the capacity market rules to reflect increased construction costs for new entry of generation (CONE). CONE is usedsuppliers (including CCG) in determining the price paid to capacity resources that clearmaking their energy offers in ISO-New England. CCG actively participated in the PJM capacity auction.proceeding, and in September 2010 the ALJ issued an Initial Decision finding that the Connecticut Parties failed to prove their case and dismissed the complaint against CCG. The outcome of thisInitial Decision is pending filing atbefore FERC is uncertain, but it could have a material effect on our financial results.for approval or modification.
Three major, high-voltage transmission lines have been announced that could enhance significantly the transfer capacity of the PJM transmission system from west to east. The siting process, eitherboth in the states orand at FERC, is uncertain, as is the likelihood that one or more of the transmission lines will be ultimately constructed. The construction of the transmission lines, which could depress both capacity and energy prices for generation located in Maryland and elsewhere in the eastern part of PJM, could have a material effect on our financial results.
OtherIn addition to legal challenges to capacity markets and regulatory advocacy before FERC seeking to revise the capacity market changesstructures, states are routinely proposed and considered on an ongoing basis. Such changes will beseeking more direct ways to affect the results of wholesale capacity markets. In January 2011, the New Jersey legislature adopted legislation that would provide for guaranteed cost recovery for the development of up to 2,000 MWs of new base load or mid-merit generation in exchange for the requirement that the new generation clear in the PJM capacity market. Similarly, the Maryland PSC issued a draft Request for Proposals that, subject to FERC's reviewan evidentiary hearing confirming the reliability need for such resources, contemplates having Maryland ratepayers fund the development of new generation and approval. We cannot predictto require that eligible new generation clear in the PJM capacity market. Such state efforts are intended to
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depress capacity prices, and are subject to legal and regulatory challenge. Depending on the outcome of these proceedings or the possiblechallenges, these state efforts could have a material effect on our or BGE's, financial results at this time.results.
NERC Reliability Standards
In compliance with the Energy Policy Act of 2005, FERC has approved the North American Electric Reliability Corporation (NERC) as the national energy reliability organization. NERC will be responsible for the development and enforcement of mandatory reliability and cyber-security standards for the wholesale electric power system. We are responsible for complying with the standards in the regions in which we operate. NERC will have the ability to assess financial penalties for noncompliance, which could be material.
Concerns over the security of the country's energy infrastructure could lead to additional future rules or regulations related to the operation and security requirements of our generating facilities and electric and gas transmission and distribution systems, which could have a material impact on our operations and financial results.
Financial Regulatory Reform
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted in July 2010. While the Dodd-Frank Act is focused primarily on the regulation and oversight of financial institutions, it also provides for a new regulatory regime for derivatives, including mandatory clearing of certain swaps, exchange trading, margin requirements, and other transparency requirements. The Dodd-Frank Act, however, also preserves the ability of end users in our industry to hedge their risks, which we believe results in the new derivatives requirements not being applicable to us for most of our activities. However, there will be several key rulemakings to implement the derivatives requirements, which, depending on the final scope of the regulations, could attempt to impose significant obligations on us nonetheless. Final regulations may address collateral requirements and exchange margin cash postings, which if applicable to us despite being an end user of derivatives, could have the effect of increasing collateral requirements or the amount of exchange margin cash postings in lieu of letters of credit currently issued on over-the-counter contracts. These regulations could also result in additional transactional and compliance costs to the extent they apply to us, and could impact market liquidity.
In addition to new regulation over derivatives, the Dodd-Frank Act amends the Sarbanes-Oxley Act to permanently exempt nonaccelerated filers, including BGE, from the requirement to obtain an audit report on internal controls over financial reporting.
Market Oversight
Regulatory agencies that have jurisdiction over our businesses, including the FERC and Commodity Future Trading Commission (CFTC), possess broad enforcement and investigative authority to ensure well functioning markets and to prohibit market manipulation or violations of the agencies' rules or orders. These agencies also possess significant civil penalty authority, including in the case of FERC and the CFTC, the authority to impose a penalty of up to $1 million per day per violation. We are committed to a culture of compliance and ensuring compliance with all applicable rules, laws and orders. Nonetheless, the regulatory agencies engage in either public or non-public investigations in response to allegations of wrongdoing and we may be involved in certain market activities that become subject to investigations. Even where no wrongdoing is found, the process of participating in a regulatory investigation could have a material effect on our business.
Weather
Merchant Energy BusinessGeneration and NewEnergy Businesses
Weather conditions in the different regions of North America influence the financial results of our merchant energy business.Generation and NewEnergy businesses. Weather conditions can affect the supply of and demand for electricity, natural gas, and fuels. Changes in energy supply and demand may impact the price of these energy commodities in both the spot market and the forward market, which may affect our results in any given period. Typically, demand for electricity and its price are higher in the summer and the winter, when weather is more extreme. The demand for and price of natural gas and oil are higher in the winter. However, all regions of North America typically do not experience extreme weather conditions at the same time, thus we are not typically exposed to the effects of extreme weather in all parts of our business at once.
BGE
Weather affects the demand for electricity and gas for our regulated businesses. Very hot summers and very cold winters increase demand. Mild weather reduces demand. Weather affects residential sales more than commercial and industrial sales, which are mostly affected by business needs for electricity and gas. The Maryland PSC has approved revenue decoupling mechanisms which allow BGE to record monthly adjustments to the majority of our regulated electric and gas business distribution revenues to eliminate the effect of abnormal weather and usage patterns. We discuss this further in theRegulation—Maryland PSC—Maryland—Revenue Decoupling, Regulated Electric Business—Revenue Decoupling andRegulated Gas Business—Gas Revenue Decoupling sections.
Other Factors
A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for our merchant energyNewEnergy business. These factors include:
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These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country as a result of regional differences in:
Other factors also impact the demand for electricity and gas in our regulated businesses. These factors include the number of customers and usage per customer during a given period. We use these terms later in our discussions of regulated electric and gas operations. In those sections, we discuss how these and other factors affected electric and gas sales during the periods presented.
The number of customers in a given period is affected by new home and apartment construction and by the number of businesses in our service territory.
Usage per customer refers to all other items impacting customer sales that cannot be measured separately. These factors include the strength of the economy in our service territory. When the economy is healthy and expanding, customers tend to consume more electricity and gas. Conversely, during an economic downturn, our customers tend to consume less electricity and gas.
Environmental Matters and Legal Proceedings
We discuss details of our environmental matters inNote 12 to Consolidated Financial Statements andItem 1. Business—Environmental Matters section. We discuss details of our legal proceedings inNote 12 to Consolidated Financial Statements. Some of this information is about costs that may be material to our financial results.
Accounting Standards Adopted and Issued
We discuss recently adopted and issued accounting standards inNote 1 to Consolidated Financial Statements.
Our discussion and analysis of financial condition and results of operations is based on our consolidated financial statements that were prepared in accordance with accounting principles generally accepted in the United States of America. Management makes estimates and assumptions when preparing financial statements.
These estimates and assumptions affect various matters, including:
These estimates involve judgments with respect to numerous factors that are difficult to predict and are beyond management's control. As a result, actual amounts could materially differ from these estimates.
Management believes the following accounting policies discussed below represent critical accounting policies as defined by the Securities and Exchange Commission (SEC). The SEC defines critical accounting policies as those that are both most important to the portrayal of a company's financial condition and results of operations and require management's most difficult, subjective, or complex judgment, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods. We discuss our significant accounting policies, including those that do not require management to make difficult, subjective, or complex judgments or estimates, inNote 1 to Consolidated Financial Statements.
Accounting for Derivatives and Hedging Activities
Our merchant energy business originatesWe utilize a variety of derivative instruments in order to manage commodity price risk, interest rate risk, and acquires contracts for energy, other energy-related commodities, and related derivatives. We record merchant energy business revenues using two methodsforeign currency risk. Because of accounting: accrual accounting and mark-to-market accounting. Thethe extensive nature of the accounting requirements that govern both accounting treatment and documentation, as well as the complexity of the transactions within the scope of these requirements, management is required to exercise judgment in several areas, including the following:
as amended, and applying those requirements involvesAs discussed in more detail below, the exercise of management's judgment in evaluating these provisions, as well as related implementation guidance and applying those requirements to complex contracts in a variety of commodities and markets. We record all derivatives subject to the accounting requirements of SFAS No. 133 as "Derivative assets or liabilities" inareas materially impacts our Consolidated Balance Sheets. Within derivative assets and liabilities, we include derivative contracts subject to mark-to-market accounting and derivative contracts that qualify for designation as hedges under SFAS No. 133.
Many fundamental customer contracts in our business, such as those associated with our load-serving activities, must be accounted for on an accrual basis. We may economically hedge these contracts with derivatives and elect cash-flow hedge accounting or apply the normal purchase and normal sale exception in order to match more closely the timing of the recognition of earnings from these transactions. We make these elections because we believe that accrual accounting provides the most transparent presentation to our shareholders of these business activities. If our commercial transactions or related hedges meet the definition of a derivative, we must comply with the provisions of SFAS No. 133 in order to use cash-flow hedge accounting or the normal purchase and normal sale exception. Qualifying for either of these accounting treatments requires ongoing compliance with specific, detailed documentation and other requirements that may be unrelated to the economics of the transactions or how the associated risks are managed.financial statements. While we believe we have appropriate controls in place to comply with theseapply the derivative accounting requirements, the failure to meet all of thosethese requirements, even inadvertently, may result in disqualifyingcould require the use of thesea different accounting treatmentstreatment for those transactions for anythe affected period until all such requirements are satisfied.
The exercise of management's judgment in using cash-flow hedge accounting or electing the normal purchase and sale exception versus mark-to-market accounting, including compliance with all of the associated qualification and documentation requirements, materially impacts our financial results with respect to timing of the recognition of earnings.transactions. In addition, interpretations of SFAS No. 133 couldthese accounting requirements continue to evolve. If there is aevolve, and future change in interpretation or a failure to meet the qualification and documentation requirements, contracts that currently are excluded from the provisions of SFAS No. 133 under the normal purchase and normal sale exception or for which changes in fair valueaccounting requirements also could affect our financial statements materially. We discuss derivatives and hedging activities in more detail inNote 1 andNote 13 to Consolidated Financial Statements.
Identification of Derivatives
We must evaluate new and existing transactions and agreements to determine whether they are recordedderivatives or if they contain embedded derivatives. Identifying derivatives requires us to exercise judgment in other comprehensive income under cash-flow hedgeinterpreting the definition of a derivative and applying that definition to each individual contract. If a contract is not a derivative, we cannot apply derivative accounting, could be deemed to no longer qualify for those accounting treatments. If that were to occur, normal purchase and normal sale contracts could be required to be recorded onwe generally must record the balance sheet at fair value with changeseffects of the contract in value recorded in the income statement, and changes in value of derivatives previously designated as cash-flow hedges could be required to be recorded in the income statement rather than in other comprehensive income.
We record revenues and fuel and purchased energy expenses from the saleour financial statements upon delivery or purchase of energy, energy-related products, and energy servicessettlement under the accrual method of accounting. In contrast, if a contract is a derivative, we must apply derivative accounting,
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which provides for several possible accounting intreatments as discussed more fully underAccounting Treatment below. As a result, the period when we deliverrequired accounting treatment and its impact on our financial statements can vary substantially depending upon whether a contract is a derivative or receive energy commodities, products, and services, or settle contracts. a non-derivative.
Accounting Treatment
We use accrualare permitted several possible accounting treatments for our merchant energy and other nonregulated business transactions, including the generation or purchase and sale of electricity, gas, and coal as part of our physical delivery activities and for power, gas, and coal sales contracts that are not subject to mark-to-market accounting. Contracts that are eligible for accrual accounting include non-derivative transactions and derivatives that meet all of the applicable requirements. Mark-to-market is the default accounting treatment for all derivatives unless they qualify, and we affirmatively designate them, for one of the other accounting treatments. Derivatives designated for any of the other elective accounting treatments must meet specific, restrictive criteria, both at the time of designation and are designated as normal purchases and normal sales of commodities that will be physically delivered. While we generally elect accrual accounting whenever permitted, we sometimes use mark-to-market accounting for physical delivery activities that are managed using economic hedges that do not qualify for accrual accounting.on an ongoing basis.
The use of permissible accounting treatments for derivatives are:
Each of the accounting treatments that we use for derivatives whether they meet the requirements for designationaffects our financial statements in substantially different ways as normal purchases and normal sales. For those derivative contracts that do not meet these criteria, we may also analyze whether theysummarized below:
Recognition and Measurement | ||||
---|---|---|---|---|
Accounting Treatment | ||||
Balance Sheet | Income Statement | |||
Mark-to-market | • Derivative asset or liability recorded at fair value | • Changes in fair value recognized in earnings | ||
Cash flow hedge | • Derivative asset or liability recorded at fair value • Effective changes in fair value recognized in accumulated other comprehensive income | • Ineffective changes in fair value recognized in earnings • Amounts in accumulated other comprehensive income reclassified to earnings when the hedged forecasted transaction affects earnings or becomes probable of not occurring | ||
Fair value hedge | • Derivative asset or liability recorded at fair value • Book value of hedged asset or liability adjusted for changes in its fair value | • Changes in fair value recognized in earnings • Changes in fair value of hedged asset or liability recognized in earnings | ||
NPNS (accrual) | • Fair value not recorded • Accounts receivable or accounts payable recorded when derivative settles | • Changes in fair value not recognized in earnings • Revenue or expense recognized in earnings when underlying physical commodity is sold or consumed | ||
We exercise judgment in determining which derivatives qualify for a particular accounting treatment, including:
We also exercise judgment in selecting the accounting treatment that we believe provides the most transparent presentation of the economics of the underlying transactions. Although contracts may be eligible for hedge accounting or NPNS designation, we are not required to designate and account for all such contracts identically. We generally elect NPNS accrual or hedge accounting for our physical energy delivery activities because accrual accounting more closely aligns the timing of earnings recognition, cash flows, and the underlying business activities. By contrast, we generally apply mark-to-market accounting for risk management and trading activities because changes in fair value more closely reflect the economic performance of the activity. However, we also use mark-to-market accounting for the following activities:
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As a result of making these judgments, the selection of accounting treatments for derivative contracts for which we do not elect to use accrual accounting or hedge accounting.derivatives has a material impact on our financial position and results of operations. These mark-to-market activities include derivative contracts for energyimpacts affect several components of our financial statements, including assets, liabilities, and accumulated other energy-related commodities. Undercomprehensive income (AOCI). Additionally, the mark-to-market methodselection of accounting wetreatment also affects the amount and timing of the recognition of earnings. The following table summarizes these impacts:
Accounting Treatment | ||||||||
---|---|---|---|---|---|---|---|---|
Effect of Changes in Fair Value on: | ||||||||
Mark-to-market | Cash Flow Hedge | Fair Value Hedge | NPNS | |||||
Assets and liabilities | • Increase or decrease in derivatives | • Increase or decrease in derivatives | • Increase or decrease in derivatives • Decrease or increase in hedged asset or liability | • No impact | ||||
AOCI | • No impact | • Increase or decrease for effective portion of hedge | • No impact | • No impact | ||||
Earnings prior to settlement | • Increase or decrease | • Increase or decrease for ineffective portion of hedge | • Increase or decrease for change in derivatives • Decrease or increase for change in hedged asset or liability • Increase or decrease for ineffective portion | • No impact | ||||
Earnings at settlement | • No impact | • Amounts in AOCI reclassified to earnings when hedged forecasted transaction affects earnings or when the forecasted transaction becomes probable of not occurring | • Hedged margin recognized in earnings | • Revenue or expense recognized in earnings when underlying physical commodity is sold or consumed | ||||
Valuation
We record themark-to-market and hedge derivatives at fair value, of these derivatives as assets and liabilities atwhich represents an exit price for the time of contract execution. We recordasset or liability from the changes in these derivative assets and liabilities in our Consolidated Statements of Income.
Derivative assets and liabilities accounted for under the mark-to-market method of accounting consistperspective of a combination of energy and energy-related derivative contracts.market participant. An exit price is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. While some of these contracts representour derivatives relate to commodities or instruments for which quoted market prices are available from external sources, many other commodities and certainrelated contracts are not actively tradedtraded. Additionally, some contracts include quantities and are valued usingother factors that vary over time. In these cases, we must use modeling techniques to determineestimate expected future market prices, contract quantities, or both.both in order to determine fair value.
The market prices, quantities, and quantities usedother factors we use to determine fair value reflect management's best estimate considering various factors. However, futureestimates of inputs a market prices and actual quantities will vary from those used in recording the related derivative assets and liabilities, and it is possible that such variations could be material.
participant would consider. We record valuation adjustments to reflect uncertainties associated with certain estimates inherent in the determination of the fair value of these derivative assets and liabilities. The effect of these uncertainties isthat are not incorporated in market price information or other market-based estimates usedwe use to determine fair value of our mark-to-market energy contracts.value. To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties for which we record valuation adjustments and determining the level of such adjustments and changes in those levels.
We describe below the main types of valuation adjustments we record and the process for establishing each. Generally, increasesdiscuss fair value measurements in valuation adjustments reduce our earnings, and decreases in valuation adjustments increase our earnings. However, all or a portion of the effect on earnings of changes in valuation adjustments may be offset by changes in the value of the underlying positions. As discussed below and more fullydetail inNote 113 to Consolidated Financial Statements, our valuation adjustments will be affected by the adoption of SFAS No. 157,Fair Value Measurements, in 2008..
The level of total close-out valuation adjustments increases as we have larger unhedged positions, bid-offer spreads increase, or market information is not available, and it decreases as we reduce our unhedged positions, bid-offer spreads decrease, or market information becomes available. Prior to the adoption of SFAS No. 157 on January 1, 2008, to the extent that we are not able to obtain observable market information for similar contracts, the close-out adjustment is equivalent to the initial contract margin, thereby resulting in no gain or loss at inception. In the absence of observable market information, there is a presumption that the transaction price is equal to the market value of the contract, and therefore we do not recognize a gain or loss at inception. We recognize such gains or losses in earnings as we realize cash flows under the contract or when observable market data becomes available.
Impacts of Uncertainty
The accounting for derivatives and hedging activities involves significant judgment and requires the use of estimates that are inherently uncertain and may arise due to a numberchange in subsequent periods. The effect of changes in assumptions and estimates could materially impact our reported amounts of revenues and costs and could be affected by many factors including, but not limited to, the termfollowing:
Market prices for energy and energy-related commodities vary based upon a number of factors, and changes in market prices affect both the recorded fair value of our mark-to-market energy contracts and the level of future revenues and costs
associated with accrual-basis activities. Changes in the value of our mark-to-market energy contracts will affect our earnings in the period of the change, while changes in forward market prices related to accrual-basis revenues and costs will affect our earnings in future periods to the extent those prices are realized. We cannot predict whether, or to what extent, the factors affecting market prices may change, but those changes could be material and could affect us either favorably or unfavorably. We discuss our market risk in more detail in theMarket Risk section.
The impact of derivative contracts on our revenues and costs is material and is affected by many factors, including:
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Table of SFAS No. 133, as amended and as interpreted in supplemental guidance,
Evaluation of Assets for Impairment and Other Than Temporary Decline in Value
Long-Lived Assets
We are required to evaluate certain assets that have long lives (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist. SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, provides the accounting requirements for impairments of long-lived assets. We are required to test our long-lived assets for recoverability whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes are:
For long-lived assets that are expected to beclassified as held and used, SFAS No. 144 provides thatfor sale, we recognize an impairment loss shallto the extent their carrying amount exceeds their fair value less costs to sell. For long-lived assets that we expect to hold and use, we recognize an impairment loss only be recognized if the carrying amount of an asset is not recoverable and exceeds its fair value. The carrying amount of an asset is not recoverable under SFAS No. 144 if the carrying amountit exceeds the sum of thetotal undiscounted future cash flows expected to result from the use and eventual disposition of the asset. Therefore, when we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-livedthe asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. This necessarily requires us to estimate uncertain future cash flows.
In order to estimate future cash flows, we consider historical cash flows and changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our other earnings forecasts). If we are considering alternative courses of action to recover the carrying amount of a long-lived asset (such as the potential sale of an asset), we probability-weight the alternative courses of action to estimate the cash flows.
We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
For long-lived assets that can be classified as assets held for sale under SFAS No. 144, an impairment loss is recognized to the extent their carrying amount exceeds their fair value less costs to sell.
If we determine that the undiscounted cash flows from an asset to be held and used are less than the carrying amount of the asset, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. The estimation of fair value under SFAS No. 144, whether in conjunction with an asset to be held and used or with an asset held for sale, also involves judgment. We consider quoted market prices in active markets to the extent they are available. In the absence of such information, we may consider prices of similar assets, consult with brokers, or employ other valuation techniques. Often, we will discount the estimated future cash flows associated with the asset using a single interest rate that is commensurate with the risk involved with such an investment or employ an expected present value method that probability-weights a range of possible outcomes. The use of these methods involves the same inherent uncertainty of future cash flows as discussed above with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in our estimates, and the impact of such variations could be material.
Unproved Gas Properties
We evaluate unproved property at least annually to determine if it is impaired. Impairment for unproved property occurs if there are also requiredno firm plans to continue drilling, the lease is near its expiration, or historical experience necessitates a valuation allowance. The determination of whether to continue to develop the lease is based upon the economics (forward prices and the level of gas reserves) associated with extracting the estimated gas reserves, which necessarily involves the exercise of judgment.
Investments
We evaluate our equity-methodequity method and cost-methodcost method investments (for example, inCENG, UNE (through November 3, 2010), and partnerships that own power projects) to determine whether or not they are impaired. Accounting Principles Board (APB) Opinion No. 18,The Equity Method of Accounting for Investments in Common Stock, provides the accounting requirements for these investments. The standard for determining whether an impairment must be recorded under APB No. 18 is whether the investment has experienced a loss in value that is considered an "other than a temporary" decline in value.
The evaluation and measurement of investment impairments under the APB No. 18 standard involves the same uncertainties as described above for long-lived assets that we own directly and account for in accordance with SFAS No. 144.directly. Similarly, the estimates that we make with respect to our equity and cost-method investments are subject to variation, and the impact of such variations could be material. Additionally, if the projects in which we hold these investments recognize an impairment, under the provisions of SFAS No. 144, we would record our proportionate share of that impairment loss and would evaluate our investment for an other than temporary decline in value under APB No. 18.value.
Gas Properties
We evaluate unproved property at least annually to determine if it is impaired under SFAS No. 19,Financial Accounting and Reporting by Oil and Gas Producing Properties. Impairment for unproved property occurs if there are no firm plans to continue drilling, lease expiration is at risk, or historical experience necessitates a valuation allowance.
Debt and Equity Securities
Ourcontinuously monitor issues that potentially could impact future profitability of our equity method investments in debt andthat own coal, hydroelectric, fuel processing projects, as well as our equity securities, primarily our nuclear decommissioning trust fund assets, are subject to impairment evaluations under FASB Staff Positions SFAS 115-1 and SFAS 124-1 (FSP 115-1 and 124-1),The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments. FSP 115-1 and 124-1 require us to determine whether a decline in fair value of an investment below book value is other than temporary. If we determine that the decline in fair value is judged to be other than temporary, the cost basis of the investment must be written down to fair value as a new cost basis. For securities held in our nuclear decommissioning trust fundjoint venture. These issues include environmental and legislative initiatives. We discuss certain risks and uncertainties in more detail in ourForward Looking Statements andItem 1A. Risk Factors sections. However, should future events cause these investments to become uneconomic, our investments in these projects could become impaired.
California statutes and regulations require load-serving entities to increase their procurement of renewable energy
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resources and mandate statewide reductions in greenhouse gas emissions. Given the need for whichelectric power and the market value is below book value,statutory and regulatory requirements increasing demand for renewable resource technologies, we believe California will continue to foster an environment that supports the declineuse of renewable energy and continues certain subsidies that will make renewable energy projects economical. However, should California legislation and regulatory policies and federal energy policies fail to adequately support renewable energy initiatives, our equity method investments in fair value for these securities is considered other than temporarytypes of projects could become impaired, and mustany losses recognized could be written down to fair value.material.
Goodwill
Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We account for goodwill and other intangibles under the provisions of SFAS No. 142,Goodwill and Other Intangible Assets. We do not amortize goodwill. SFAS No. 142 requires us toWe evaluate goodwill for impairment at least annually or more frequently if events and circumstances indicate the business might be impaired. Goodwill is impaired if the carrying value of the business exceeds fair value. Annually, we estimate the fair value of the businesses we have acquired using techniques similar to those used to estimate future cash flows for long-lived assets as discussed on the previous page, which involves judgment. If the estimated fair value of the business is less than its carrying value, an impairment loss is required to be recognized to the extent that the carrying value of goodwill is greater than its fair value.
Asset Retirement Obligations
We incur legal obligations associated with the retirement of certain long-lived assets. SFAS No. 143,Accounting for Asset Retirement Obligations, provides the accounting for legal obligations associated with the retirement of long-lived assets. We incur such legal obligations as a result of environmental and other government regulations, contractual agreements, and other factors. The application of this standard requires significant judgment due to the large number and diverse nature of the assets in our various businesses and the estimation of future cash flows required to measure legal obligations associated with the retirement of specific assets. FASB Interpretation (FIN) 47,Accounting for Conditional Asset Retirement Obligations—an interpretation of FASB Statement No. 143, clarifies that obligations that are conditional upon a future event are subject to the provisions of SFAS No. 143.
SFAS No. 143 requires the use of an expected present value methodology in measuring asset retirement obligations that involves judgment surrounding the inherent uncertainty of the probability, amount and timing of payments to settle these obligations, and the appropriate interest rates to discount future cash flows. We use our best estimates in identifying and measuring our asset retirement obligations in accordance with SFAS No. 143.
Our nuclear decommissioning costs represent our largest asset retirement obligation. This obligation primarily results from the requirement to decommission and decontaminate our nuclear generating facilities in connection with their future retirement. We utilize site-specific decommissioning cost estimates to determine our nuclear asset retirement obligations. However, given the magnitude of the amounts involved, complicated and ever-changing technical and regulatory requirements, and the long time horizons involved, the actual obligation could vary from the assumptions used in our estimates, and the impact of such variations could be material.
In view of the significant number of assumptions underlying the decommissioning cost estimate, our estimate of the future cost of decommissioning is likely to continue to change over time. For perspective, a 10% increase or decrease in our estimate of the future cost of decommissioning would produce an approximately $80 million change to our asset retirement obligation and an approximately $10 million change in our total annual amortization and accretion expenses.
Significant Events
Common Share Repurchase ProgramSignificant Events
Comprehensive Agreement with EDF
In October 2007,2010, we reached a comprehensive agreement with EDF Group and related entities (EDF) that restructured the relationship between our boardtwo companies, eliminated the outstanding asset put arrangement, and transferred to EDF the full ownership of directors approved a common share repurchase program for up to $1 billionUniStar Nuclear Energy, LLC (UNE). We completed the sale of our outstanding common stock.50% membership interest in UNE in November 2010. We discuss the terms of the comprehensive agreement inNote 4 to Consolidated Financial Statements.
Acquisitions
Criterion Wind Project
In April 2010, we acquired the Criterion wind project to be constructed in Garrett County, Maryland. We have completed construction and placed the 70 MW project in service in December 2010.
Texas Combined Cycle Generation Facilities
In May 2010, we acquired the 550 MW Colorado Bend Energy Center and the 550 MW Quail Run Energy Center natural gas combined cycle generation facilities in Texas for $372.9 million.
Hillabee Energy Center
In June 2010, the Hillabee Energy Center, a 740 MW gas-fired combined cycle power generation facility located in Alabama, began commercial dispatch. We had acquired this common share repurchase programunder construction facility in 2008.
CPower
In October 2010, we acquired CPower, an energy management and demand response provider, for approximately $78 million, subject to closing adjustments.
Boston Generating
In January 2011, we completed the acquisition of Boston Generating's 2,950 MW fleet of generating plants for approximately $1.1 billion, subject to a working capital true-up adjustment. The fleet acquired includes the following four natural gas-fired power plants and one fuel oil plant located in the Boston, Massachusetts area:
We discuss these transactions in more detail inNote 915 to Consolidated Financial Statements..
Dividend IncreaseDivestitures
In January 2008,2010, BGE completed the sale of its interest in a nonregulated subsidiary that owns a district chilled water facility to a third party.
In August 2010, we announced an increasecompleted the sale of our interests in our quarterly dividend to $0.4775 per sharethe Mammoth Lakes geothermal generating facility.
In November 2010, we closed on our common stock.comprehensive agreement with EDF in which we sold our interest in UNE.
In December 2010, we signed an agreement to sell our Quail Run Energy Center, a 550 MW natural gas plant in west Texas, to High Plains Diversified Energy Corporation (HPDEC) for $185.3 million. This agreement is equivalent to an annual ratecontingent upon HPDEC obtaining financing through the sale of $1.91 per share. Previously, our quarterly dividend on our common stock was $0.435 per share, equivalent to an annual rate of $1.74 per share.
CEP
CEP, a limited liability company formed in 2006 by Constellation Energy, issued additional equity to the public in 2007. As a result, in the second quarter of 2007, our ownership percentage in CEP fell below 50 percent, and we deconsolidated CEP and began accounting for our investment using the equity method of accounting.municipal bonds.
We discuss the issuances of CEP's equity and their impact on our financial resultsthese transactions in more detail inNote 2 to Consolidated Financial Statements..
AcquisitionsImpairment Losses and Other Costs
During 2007,2010, we acquired working interestsrecorded impairment losses on our investments in gasCENG and oil producing fields,UNE and an entity that expandedcertain of our retail competitive supply operations. In February 2008, we acquired a partially completed 774 MW gas-fired combined-cycle power generation facility located in Alabama.other equity method investments. We discuss these acquisitions in more detail in theNote 15.
We also acquired a portfolio of energy contracts during 2007. We discuss these energy contracts in more detail in theFinancial Condition section.
Shipping Joint Venture
During 2007, we made cash contributions totaling $57 million to a shipping joint venture in which we have a 50% ownership interest. We discuss this joint venturecharges in more detail inNote 42 to Consolidated Financial Statements.
Electricite de France Joint VentureInternational Coal Contract Dispute Settlement
During 2010, we finalized the settlement of a contract dispute with a third party international coal supplier for a net pre-tax gain of $56.6 million. We discuss this settlement inNote 2 to Consolidated Financial Statements.
Financing Activities
Issuance of Notes
In December 2010, we issued $550 million of 5.15% Notes due December 1, 2020.
Redemption of Notes
In February 2010, we redeemed certain of our 7.00% Notes due April 1, 2012 as part of a cash tender offer launched in January 2010 and in March 2010 we repurchased certain tax exempt notes.
In December 2010, we issued a call notice to redeem $213.5 million, which represents the remaining outstanding 7.00% Notes due April 1, 2012. We redeemed these notes in January 2011.
We discuss these financing transactions in more detailNote 9 to Consolidated Financial Statements.
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Healthcare Reform Legislation
In August 2007, we formed a joint venture, UniStar Nuclear Energy, LLC (UNE) with an affiliateMarch 2010, the Patient Protection and Affordable Care Act and the Healthcare and Education Reconciliation Act of Electricite de France, SA (EDF).2010 (Reconciliation Act) were signed into law. We discuss this joint venturethe impact of these new laws on our earnings in more detail inNote 42 to Consolidated Financial Statements.
Rate Stabilization Bonds
In 2007, BGE formed a special purpose bankruptcy-remote limited liability company to purchase rate stabilization property from BGE and to issue rate stabilization bonds. We discuss this entity and the related financing in more detail inNote 4 andNote 9.
Synthetic Fuel Facilities
Our merchant energy business has investments in facilities that manufacture solid synthetic fuel produced from coal as defined under the Internal Revenue Code (IRC) for which we can claim tax credits on our Federal income tax return through 2007. The IRC provides for a phase-out of synthetic fuel tax credits if average annual wellhead oil prices increase above certain levels. For 2007, we estimate the tax credit reduction would begin if the reference price exceeds approximately $56 per barrel and would be fully phased-out if the reference price exceeds approximately $71 per barrel. Based on monthly EIA published wellhead oil prices for the ten months ended October 31, 2007 and November and December NYMEX prices for light, sweet, crude oil (adjusted for the 2007 difference between EIA and NYMEX prices), we estimate a 70% tax credit phase-out in 2007. We recorded the effect of this phase-out estimate as a reduction in tax credits of $110.3 million during 2007. We discuss how we determine the amount of phase-out in more detail inNote 10.
In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, and then separately discuss earnings for our operating segments. Significant changes in other (expense) income, and expense, fixed charges, and income taxes are discussed in the aggregate for all segments in theConsolidated Nonoperating Income and Expenses section.
As discussed inItem 1 Business—Overview section and in theStrategy andSignificant Events sections, Constellation Energy's 2010, 2009 and 2008 operating results were materially impacted by a number of significant events, transactions, and changes in our strategic direction. The impact of these items has affected the comparability of our 2010, 2009 and 2008 results to prior periods and will alter Constellation Energy's operating results in the future. In this section, we highlight the 2010, 2009 and 2008 impacts of these items.
Overview
Results
| 2007 | 2006 | 2005 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions, after-tax) | ||||||||||
Merchant energy | $ | 679.2 | $ | 580.1 | $ | 359.4 | |||||
Regulated electric | 97.9 | 120.2 | 149.4 | ||||||||
Regulated gas | 28.8 | 37.0 | 26.7 | ||||||||
Other nonregulated | 16.5 | 11.3 | 0.4 | ||||||||
Income from continuing operations and before cumulative effects of changes in accounting principles | 822.4 | 748.6 | 535.9 | ||||||||
(Loss) income from discontinued operations | (0.9 | ) | 187.8 | 94.4 | |||||||
Cumulative effects of changes in accounting principles | — | — | (7.2 | ) | |||||||
Net Income | $ | 821.5 | $ | 936.4 | $ | 623.1 | |||||
Other Items Included in Operations (after-tax) | |||||||||||
Gain on sale of gas-fired plants | $ | — | $ | 47.1 | $ | — | |||||
Non-qualifying hedges | 2.0 | 39.2 | (24.9 | ) | |||||||
Impairment losses and other costs | (12.2 | ) | — | — | |||||||
Workforce reduction costs | (1.4 | ) | (17.0 | ) | (2.6 | ) | |||||
Merger-related costs | — | (5.7 | ) | (15.6 | ) | ||||||
Total Other Items | $ | (11.6 | ) | $ | 63.6 | $ | (43.1 | ) | |||
2007
| 2010 | 2009 | 2008 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions, after-tax) | ||||||||||
Net (Loss) Income: | |||||||||||
Generation | $ | (1,255.3 | ) | $ | 4,766.7 | $ | (357.7 | ) | |||
NewEnergy | 176.2 | (348.2 | ) | (1,011.4 | ) | ||||||
Regulated electric | 110.0 | 79.1 | 11.1 | ||||||||
Regulated gas | 37.6 | 25.5 | 40.4 | ||||||||
Other nonregulated | (0.3 | ) | (19.7 | ) | (0.8 | ) | |||||
Net (Loss) Income | $ | (931.8 | ) | $ | 4,503.4 | $ | (1,318.4 | ) | |||
Net (Loss) Income attributable to common stock | $ | (982.6 | ) | $ | 4,443.4 | $ | (1,314.4 | ) | |||
Change from prior year | $ | (5,426.0 | ) | $ | 5,757.8 | ||||||
Our total net (loss) income attributable to common stock for 20072010 decreased $114.9 million,compared to 2009 by $5.4 billion, or $0.66$27.09 per share, compared to 2006 mostly because of the following:
| Increase/(Decrease) 2010 vs. 2009 | |||
---|---|---|---|---|
(In millions, after-tax) | ||||
Generation gross margin, primarily due to the deconsolidation of CENG | $ | (682 | ) | |
Lower Generation operating expenses, primarily labor and benefit costs due to the deconsolidation of CENG | 390 | |||
Lower Generation accretion expense of asset retirement obligations due to deconsolidation of CENG | 37 | |||
Lower Generation taxes other than income taxes due to deconsolidation of CENG | 27 | |||
Lower Generation depreciation and amortization due to deconsolidation of CENG | 28 | |||
NewEnergy gross margin | 78 | |||
NewEnergy hedge ineffectiveness | (55 | ) | ||
Loss on NewEnergy international coal contract assignments | (25 | ) | ||
Regulated businesses, excluding the effects of the 2009 residential customer credit | (21 | ) | ||
Other nonregulated businesses | 5 | |||
Total change inOther Items Included in Operations per table below | (5,375 | ) | ||
All other changes | 167 | |||
Total Change | $ | (5,426 | ) | |
These decreases were partially offset by the following:
2006
Our total net income attributable to common stock for 2006 increased $313.3 million,2009 improved compared to 2008 by $5.8 billion, or $1.69$29.53 per share, compared to 2005 mostly because of the following:
| Increase/(Decrease) 2009 vs. 2008 | |||
---|---|---|---|---|
(In millions, after-tax) | ||||
Generation gross margin | $ | 27 | ||
NewEnergy gross margin | (134 | ) | ||
Absence of sale of NewEnergy upstream gas assets | (16 | ) | ||
NewEnergy hedge ineffectiveness | 84 | |||
Absence of NewEnergy credit loss—coal supplier bankruptcy | 33 | |||
Regulated businesses, excluding the effects of the 2008 Maryland settlement agreement and the 2009 residential customer credit | 10 | |||
Other nonregulated businesses | (8 | ) | ||
Total change inOther Items Included in Operations per table below | 5,763 | |||
All other changes | (1 | ) | ||
Total Change | $ | 5,758 | ||
40
Other Items Included in Operations (after-tax):
| 2010 | 2009 | 2008 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions, after-tax) | ||||||||||
Impairment losses and other costs | $ | (1,487.1 | ) | $ | (96.2 | ) | $ | (468.4 | ) | ||
Gain on Comprehensive Agreement with EDF | 121.3 | — | — | ||||||||
Amortization of basis difference in CENG | (117.5 | ) | (17.8 | ) | — | ||||||
Impact of power purchase agreement with CENG (1) | (113.3 | ) | — | — | |||||||
International coal contract dispute settlement | 35.4 | — | — | ||||||||
Loss on early retirement of 2012 Notes | (30.9 | ) | — | — | |||||||
Gain on sale of Mammoth Lakes geothermal generating facility | 24.7 | — | — | ||||||||
Credit facility amendment/termination fees | (13.6 | ) | (37.7 | ) | — | ||||||
Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits | (8.8 | ) | — | — | |||||||
Gain on sale of 49.99% interest in CENG | — | 4,456.1 | — | ||||||||
International commodities operation and gas trading operation (2) | — | (371.9 | ) | — | |||||||
BGE residential customer rate credit | — | (67.1 | ) | — | |||||||
Impairment of nuclear decommissioning trust assets | — | (46.8 | ) | (82.0 | ) | ||||||
Merger termination and strategic alternatives costs | — | (13.8 | ) | (1,204.4 | ) | ||||||
Loss on redemption of Zero Coupon Senior Notes | — | (10.0 | ) | — | |||||||
Workforce reduction costs | — | (9.3 | ) | (13.4 | ) | ||||||
Maryland settlement credit | — | — | (110.5 | ) | |||||||
Non-qualifying hedges | — | — | (70.1 | ) | |||||||
Emission allowance write down, net | — | — | (28.7 | ) | |||||||
Total Other Items | $ | (1,589.8 | ) | $ | 3,785.5 | $ | (1,977.5 | ) | |||
Change from prior year | $ | (5,375.3 | ) | $ | 5,763.0 | ||||||
These increases were partially offset by the following:
Merchant EnergyGeneration Business
Background
Our merchant energyGeneration business is a competitive provider of energy solutions for various customers. We discuss the impact of deregulation on our merchant energy businessdiscussed in detail inItem 1. Business—CompetitionOperating Segments section.
Our merchant energyWe have presented the results of this business focusesreflecting that we have hedged 100% of generation output and fuel for generation. This is based on deliveryexecuting hedges at prevailing market prices with the NewEnergy business. Taking into account previously executed hedges at the end of physical, customer-oriented productseach fiscal year, we ensure that the Generation business is fully hedged by the NewEnergy business for the next year. Therefore, all commodity price risk is managed by and presented in the results of our NewEnergy business as discussed below. Generally, changes in the results of our Generation business during the period are due to producerschanges in the availability of the generating assets.
During 2010, power prices continued to decline, reflecting economic conditions and consumers, managesprojected increases in natural gas supplies. However, prices for coal have not declined to the risksame extent as power prices. The relationship between power and optimizesfuel prices directly affects the earnings of our Generation business. Although our NewEnergy business hedges portions of our future power sales and fuel purchases, the amounts we have hedged are higher for the near term and decline over time. We have already locked in prices for our expected generation output for 2011. However, consistent with our hedging approach, we have only hedged a portion of the expected output for 2012, and those hedges are at lower prices. If the current power and fuel price environment continues, we anticipate that our Generation business will have lower earnings in future years, especially in 2012.
Additionally, we evaluated our generating plants for impairment as a result of power price declines in 2010. Although none of our plants were impaired, further decreases in power prices could result in estimated future cash flows declining below the carrying value of our owned generation assets, and uses our portfolio management and trading capabilities both to manage risk and to deploy risk capital to generate additional returns. We continue to identify and pursue opportunitiesplants, which can generate additional returns through portfolio management and trading activities within our business. These opportunities have increased due to the significant growth in scale of our competitive supply operations.
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 theCritical Accounting Policies section and inNote 1. We summarize our revenue and expense recognition policies as follows:
Mark-to-market accounting requireswould require us to make estimates and assumptions using judgment in determining the fair valuerecord an impairment charge.
41
Table of certain contracts and in recording revenues from those contracts. We discuss the effects of mark-to-market accounting on our results in theCompetitive Supply—Mark-to-Market section. We discuss mark-to-market accounting and the accounting policies for the merchant energy business further in theCritical Accounting Policies section and inNote 1.Contents
Our merchant energy business actively transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions. As part of these activities we trade energy and energy-related commodities and deploy risk capital in the management of our portfolio in order to earn additional returns. These activities are managed through daily value at risk and stop loss limits and liquidity guidelines, and may have a material impact on our financial results. We discuss the impact of our trading activities and value at risk in more detail in theCompetitive Supply—Mark-to-Market andMarket Risk sections.
Results
| 2007 | 2006 | 2005 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||
Revenues | $ | 18,744.5 | $ | 17,166.2 | $ | 14,622.4 | |||||
Fuel and purchased energy expenses | (15,501.8 | ) | (14,256.3 | ) | (12,301.8 | ) | |||||
Operating expenses | (1,791.8 | ) | (1,549.4 | ) | (1,346.1 | ) | |||||
Impairment losses and other costs | (20.2 | ) | — | — | |||||||
Workforce reduction costs | (2.3 | ) | (28.2 | ) | (4.4 | ) | |||||
Merger-related costs | — | (13.1 | ) | (11.2 | ) | ||||||
Depreciation, depletion, and amortization | (269.9 | ) | (258.7 | ) | (250.4 | ) | |||||
Accretion of asset retirement obligations | (68.3 | ) | (67.6 | ) | (62.0 | ) | |||||
Taxes other than income taxes | (110.2 | ) | (120.0 | ) | (106.7 | ) | |||||
Gain on sale of gas-fired plants | — | 73.8 | — | ||||||||
Income from Operations | $ | 980.0 | $ | 946.7 | $ | 539.8 | |||||
Income from continuing operations and before cumulative effects of changes in accounting principles (after-tax) | $ | 679.2 | $ | 580.1 | $ | 359.4 | |||||
(Loss) Income from discontinued operations (after-tax) | (0.9 | ) | 186.9 | 73.8 | |||||||
Cumulative effects of changes in accounting principles (after-tax) | — | — | (7.4 | ) | |||||||
Net Income | $ | 678.3 | $ | 767.0 | $ | 425.8 | |||||
Other Items Included in Operations (after-tax) | |||||||||||
Gain on sale of gas-fired plants | $ | — | $ | 47.1 | $ | — | |||||
Non-qualifying hedges | 2.0 | 39.2 | (24.9 | ) | |||||||
Impairment losses and other costs | (12.2 | ) | — | — | |||||||
Workforce reduction costs | (1.4 | ) | (17.0 | ) | (2.6 | ) | |||||
Merger-related costs | — | (4.3 | ) | (10.4 | ) | ||||||
Total Other Items | $ | (11.6 | ) | $ | 65.0 | $ | (37.9 | ) | |||
| 2010 | 2009 | 2008 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||
Revenues | $ | 2,244.3 | $ | 2,774.2 | $ | 2,958.5 | |||||
Fuel and purchased energy expenses | (1,444.8 | ) | (692.0 | ) | (916.1 | ) | |||||
Gross margin | 799.5 | 2,082.2 | 2,042.4 | ||||||||
Operating expenses | (379.7 | ) | (1,008.4 | ) | (969.1 | ) | |||||
Impairment losses and other costs | (2,476.7 | ) | — | (14.0 | ) | ||||||
Workforce reduction costs | — | — | (6.1 | ) | |||||||
Merger termination and strategic alternatives costs | — | (101.8 | ) | (742.3 | ) | ||||||
Depreciation, depletion, and amortization | (136.1 | ) | (176.8 | ) | (174.3 | ) | |||||
Accretion of asset retirement obligations | (1.6 | ) | (62.1 | ) | (67.9 | ) | |||||
Taxes other than income taxes | (23.6 | ) | (67.4 | ) | (69.9 | ) | |||||
Equity investment earnings (losses): | |||||||||||
CENG | 23.6 | 4.3 | — | ||||||||
UNE | (16.8 | ) | (24.7 | ) | (5.9 | ) | |||||
Other | 18.2 | 20.6 | 32.7 | ||||||||
Net gain on divestitures | 242.9 | 7,445.6 | — | ||||||||
(Loss) Income from Operations | $ | (1,950.3 | ) | $ | 8,111.5 | $ | 25.6 | ||||
Net (Loss) Income | $ | (1,255.3 | ) | $ | 4,766.7 | $ | (357.7 | ) | |||
Net (Loss) Income attributable to common stock | $ | (1,255.3 | ) | $ | 4,766.7 | $ | (357.7 | ) | |||
Change from prior year | $ | (6,022.0 | ) | $ | 5,124.4 | ||||||
Other Items Included in Operations (after-tax): | |||||||||||
Impairment losses and other costs | $ | (1,487.1 | ) | $ | — | $ | (8.3 | ) | |||
Gain on Comprehensive Agreement with EDF | 121.3 | — | — | ||||||||
Amortization of basis difference in CENG | (117.5 | ) | (17.8 | ) | — | ||||||
Impact of power purchase agreement with CENG (1) | (113.3 | ) | — | — | |||||||
Loss on early retirement of 2012 Notes | (30.9 | ) | — | — | |||||||
Gain on sale of Mammoth Lakes geothermal generating facility | 24.7 | — | — | ||||||||
Credit facility amendment/termination fees | (9.0 | ) | (13.7 | ) | — | ||||||
Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits | (0.8 | ) | — | — | |||||||
Gain on sale of 49.99% interest in CENG | — | 4,456.1 | — | ||||||||
Impairment of nuclear decommissioning trust assets | — | (46.8 | ) | (82.0 | ) | ||||||
Loss on redemption of Zero Coupon Senior Notes | — | (10.0 | ) | — | |||||||
Merger termination and strategic alternatives costs | — | (9.7 | ) | (742.3 | ) | ||||||
Workforce reduction costs | — | — | (3.7 | ) | |||||||
Total Other Items | $ | (1,612.6 | ) | $ | 4,358.1 | $ | (836.3 | ) | |||
Change from prior year | $ | (5,970.7 | ) | $ | 5,194.4 | ||||||
Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.
Effects of 2009 Transaction with EDF on Statement of Income (Loss)
Prior to November 6, 2009, CENG was a 100% owned subsidiary, and we consolidated its financial results within our Consolidated Statements of Income (Loss). On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG to EDF, and we deconsolidated CENG. Accordingly, beginning November 6, 2009, we ceased recording CENG's financial results and began to record equity investment earnings from CENG as well as the effect of our PPA and other transactions with CENG. We discuss our transaction with EDF in more detail inNote 2 to Consolidated Financial Statements.
For the period from January 1, 2009 through November 6, 2009, our Generation results included the following financial results of CENG:
For the period from January 1, 2009 through November 6, 2009 | ||||
---|---|---|---|---|
| (In billions) | |||
Revenues | $ | 1.2 | ||
Fuel and purchased energy expenses | 0.1 | |||
Operating expenses | 0.8 | |||
Depreciation and amortization | 0.1 | |||
Income from operations | 0.2 |
As a result of the deconsolidation, our Generation results after November 6, 2009 differ from historical results primarily due to the following factors:
Additionally, we record our 50.01% share of CENG's financial results and amortization of the CENG basis difference in the "Equity Investment (Losses) Earnings" line in our Consolidated Statements of Income (Loss). We discuss the accounting for our retained investment in CENG in more detail inNote 2 to Consolidated Financial Statements.
Beginning in the fourth quarter of 2010, the amortization of the basis difference in CENG will be lower as the basis difference was reduced by the amount of the impairment charge recorded on our investment in CENG during the quarter ended September 30, 2010. We discuss the impairment charge in more detail in theNote 2 to Consolidated Financial Statements.
42
Revenues
Our Generation revenues decreased $529.9 million in 2010 compared to 2009 and decreased $184.3 million in 2009 compared to 2008 primarily due to the following:
| 2010 vs. 2009 | 2009 vs. 2008 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Decrease in volume of output primarily due to the deconsolidation of CENG nuclear generating assets | $ | (690 | ) | $ | (397 | ) | |
Increase in volume of output due to the beginning of commercial dispatch of the Hillabee Energy Center and the acquisition of the Texas combined cycle generation facilities | 198 | — | |||||
(Decrease) increase in volume of output due to (higher) lower planned and unplanned outages at our generating plants | (127 | ) | 150 | ||||
Increase in higher contracted power prices for the output of our generating plants | 116 | 65 | |||||
All other | (27 | ) | (2 | ) | |||
Total decrease in Generation revenues | $ | (530 | ) | $ | (184 | ) | |
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. As previously discussed, our merchant energy business uses either accrual or mark-to-market accounting to record our revenues and expenses. Mark-to-market results reflect the net impact of amounts recorded in either revenues orGeneration fuel and purchased energy expenses increased $752.8 million in 2010 compared to recognize changes2009 and decreased $224.1 million in fair value of derivative contracts subject2009 compared to mark-to-market accounting during the reporting period.
The difference between revenues and fuel and purchased energy expenses, including all direct 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 may 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.
| 2010 vs. 2009 | 2009 vs. 2008 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Increase in purchased energy costs due to power purchase agreement with CENG compared with nuclear fuel costs | $ | 741 | $ | — | |||
(Decrease) increase in volume of output due to (higher) lower planned and unplanned outages at our generating plants | (87 | ) | 22 | ||||
Increase (decrease) in fuel costs primarily related to higher (lower) contract prices to operate our generating assets | 59 | (273 | ) | ||||
All other | 40 | 27 | |||||
Total increase (decrease) in Generation fuel and purchased energy expenses | $ | 753 | $ | (224 | ) | ||
Plants with Power Purchase Agreements—our generating facilities outside the Mid-Atlantic Region with long-term power purchase agreements. As discussed inOperating ExpensesNote 2, the sale of the High Desert facility resulted in a reclassification of its results of operations
Our Generation business operating expenses decreased $628.7 million during 2010 as compared to discontinued operations.
In December 2006, we completed the sale of these gas-fired plants:
We discuss the sale of these gas-fired generating facilities inNote 2.
We provide a summary of our revenues, fuel and purchased energy expenses, and gross margin as follows:
| 2007 | | 2006 | | 2005 | | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (Dollar amounts in millions) | |||||||||||||||||
Revenues: | ||||||||||||||||||
Mid-Atlantic Region | $ | 3,462.2 | $ | 2,813.5 | $ | 2,283.9 | ||||||||||||
Plants with Power Purchase Agreements | 657.3 | 650.5 | 665.9 | |||||||||||||||
Competitive Supply | ||||||||||||||||||
Retail | 9,086.3 | 8,014.7 | 6,942.3 | |||||||||||||||
Wholesale | 5,469.4 | 5,612.7 | 4,672.3 | |||||||||||||||
Other | 69.3 | 74.8 | 58.0 | |||||||||||||||
Total | $ | 18,744.5 | $ | 17,166.2 | $ | 14,622.4 | ||||||||||||
Fuel and purchased energy expenses: | ||||||||||||||||||
Mid-Atlantic Region | $ | (2,214.4 | ) | $ | (1,727.6 | ) | $ | (1,436.5 | ) | |||||||||
Plants with Power Purchase Agreements | (78.5 | ) | (67.9 | ) | (72.5 | ) | ||||||||||||
Competitive Supply | ||||||||||||||||||
Retail | (8,590.8 | ) | (7,570.2 | ) | (6,668.2 | ) | ||||||||||||
Wholesale | (4,618.1 | ) | (4,890.6 | ) | (4,124.6 | ) | ||||||||||||
Other | — | — | — | |||||||||||||||
Total | $ | (15,501.8 | ) | $ | (14,256.3 | ) | $ | (12,301.8 | ) | |||||||||
Gross margin: | | % of Total | | % of Total | | % of Total | ||||||||||||
Mid-Atlantic Region | $ | 1,247.8 | 39 | % | $ | 1,085.9 | 37 | % | $ | 847.4 | 36 | % | ||||||
Plants with Power Purchase Agreements | 578.8 | 18 | 582.6 | 20 | 593.4 | 25 | ||||||||||||
Competitive Supply | ||||||||||||||||||
Retail | 495.5 | 15 | 444.5 | 15 | 274.1 | 12 | ||||||||||||
Wholesale | 851.3 | 26 | 722.1 | 25 | 547.7 | 24 | ||||||||||||
Other | 69.3 | 2 | 74.8 | 3 | 58.0 | 3 | ||||||||||||
Total | $ | 3,242.7 | 100 | % | $ | 2,909.9 | 100 | % | $ | 2,320.6 | 100 | % | ||||||
Merchant energy gross margin for 2007 includes certain effects of market price changes on derivatives designated as cash-flow and fair value hedges. These market price changes had two primary impacts on 2007:
The merchant energy gross margin impact for 2007which results from the effectabsence of market price changes on derivatives designatedcosts in 2010 due to the deconsolidation of CENG.
Our Generation business operating expenses increased $39.3 million during 2009 as cash-flow and fair value hedges is summarized as follows:
| 2007 | ||||
---|---|---|---|---|---|
| (In millions) | ||||
Ineffectiveness on derivatives that qualified for hedge accounting treatment | $ | (10.8 | ) | ||
Effect of reduced price correlation on derivatives that did not qualify for hedge accounting treatment | |||||
Derivatives that were redesignated as hedges prospectively | (7.3 | ) | |||
Derivatives not eligible for designation as hedges prospectively | (70.8 | ) | |||
Total | $ | (88.9 | ) | ||
We discuss below the impact of these items on the applicable categories of merchant energy gross margin for 2007 compared to 2006. We discuss our hedging activities in more detail inNote 13.
Mid-Atlantic Region
| 2007 | 2006 | 2005 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Revenues | $ | 3,462.2 | $ | 2,813.5 | $ | 2,283.9 | ||||
Fuel and purchased energy expenses | (2,214.4 | ) | (1,727.6 | ) | (1,436.5 | ) | ||||
Gross margin | $ | 1,247.8 | $ | 1,085.9 | $ | 847.4 | ||||
The $161.9 million increase in gross margin in 2007 compared to 2006 is primarily2008 due to approximately $249higher performance-based labor and benefit costs of $74.5 million, in higher margins on new and existing contracts. The increase in gross margin was partially offset by the following:
Impairment Losses and Other Costs
Our Generation business incurred impairment losses recognized on cash-flow hedges due to ineffectiveness and certain cash-flow hedges that no longer qualify for hedge accounting, and
The increase of $238.5 million in gross margin in 2006 compared to 2005 is primarily due to approximately $340 million in higher gross margin mostly from favorable portfolio management, including higher margins on existing contracts and new contracts that began in 2006.
Our wholesale marketing, risk management, and trading operation was awarded contracts in 2006 to supply a substantial portion of BGE's standard offer service obligation to residential customers beginning July 1, 2006 through May 31, 2007. The increase in gross margin included higher revenues from BGE of approximately $256 million mostly from these new contracts during 2006 compared to 2005. This increase in gross margin was partially offset by the negative impact of higher expenses from serving the original BGE standard offer service obligation during the first six months of 2006 as variable2010. These costs including emissions and coal, continued to increase. We discuss the expiration of the BGE residential rate freeze in more detail in theItem 1.—Business—Baltimore Gas and Electric Company—Electric Competition section. Our wholesale marketing, risk management, and trading operation served fixed-price standard offer service obligations to BGE residential customers during the period from July 1, 2000 until July 1, 2006.
These increases in gross margin were partially offset by:
Plants with Power Purchase Agreements
| 2007 | 2006 | 2005 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Revenues | $ | 657.3 | $ | 650.5 | $ | 665.9 | ||||
Fuel and purchased energy expenses | (78.5 | ) | (67.9 | ) | (72.5 | ) | ||||
Gross margin | $ | 578.8 | $ | 582.6 | $ | 593.4 | ||||
Gross margin from our Plants with Power Purchase Agreements was about the same in 2007 compared to 2006.
Gross margin from our Plants with Power Purchase Agreements decreased slightly in 2006 compared to the same periods of 2005. This was mostly due to approximately $14 million in lower gross margin from the University Park facility, which effective June 2006 until its sale in December 2006 was included in the Mid-Atlantic Region after the expiration of its power purchase agreement in May 2006.
Competitive Supply
We analyze our retail accrual, wholesale accrual, and mark-to-market competitive supply activities below.
Retail
| 2007 | 2006 | 2005 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Accrual revenues | $ | 9,080.5 | $ | 8,000.6 | $ | 6,944.2 | ||||
Fuel and purchased energy expenses | (8,590.8 | ) | (7,577.0 | ) | (6,688.4 | ) | ||||
Retail accrual activities | 489.7 | 423.6 | 255.8 | |||||||
Mark-to-market activities | 5.8 | 20.9 | 18.3 | |||||||
Gross margin | $ | 495.5 | $ | 444.5 | $ | 274.1 | ||||
The $66.1 million increase in accrual gross margin from our retail competitive supply activities during 2007 compared to 2006 is primarily due to approximately $104 million related to the positive impact of higher volumes served at higher contract rates per megawatt hour and lower costs to serve load in our retail electric operations. This increase in gross margin was partially offset by approximately $38 million related to losses at our retail gas operations recognized during 2007 on hedges due to ineffectiveness and on certain hedges that did not qualify for hedge accounting compared to 2006.
The increase in accrual gross margin of $167.8 million from our retail activities during 2006 compared to 2005 is primarily due to:
Wholesale
| 2007 | 2006 | 2005 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Accrual revenues | $ | 4,932.5 | $ | 5,232.7 | $ | 4,281.8 | ||||
Fuel and purchased energy expenses | (4,618.1 | ) | (4,890.6 | ) | (4,124.6 | ) | ||||
Wholesale accrual activities | 314.4 | 342.1 | 157.2 | |||||||
Mark-to-market activities | 536.9 | 380.0 | 390.5 | |||||||
Gross margin | $ | 851.3 | $ | 722.1 | $ | 547.7 | ||||
Our wholesale marketing, risk management, and trading operation had $27.7 million of lower accrual gross margin during 2007 compared to 2006, primarily due to:
Depreciation, Depletion and Amortization Expense
Our Generation business incurred lower depreciation, depletion and amortization expenses of $40.7 million during 2010 compared to 2009 due to a decrease of $94.0 million in depreciation on the nuclear generating facilities resulting from the deconsolidation of CENG on November 6, 2009, partially offset by an increase of $53.4 million in depreciation on our other generating facilities primarily related to the installation of emission control equipment at our Brandon Shores coal-fired generating plant that went into service in the fourth quarter of 2009, the Texas combined cycle generation facilities we acquired in 2010, and the Hillabee Energy Center, which began commercial dispatch in 2010.
Our Generation business incurred higher depreciation, depletion and amortization expenses of $2.5 million during 2009 compared to 2008 due to an increase of $12.0 million in depreciation on our non-nuclear generating assets primarily related to environmental additions at our Brandon Shores coal-fired generating plant that went into service in the fourth quarter of 2009, partially offset by a $9.5 million decrease in depreciation on our nuclear generating assets resulting from the deconsolidation of CENG on November 6, 2009.
Accretion of Asset Retirement Obligations
Our Generation business incurred lower accretion of asset retirement obligations expense of $60.5 million in 2010 compared to 2009, which represents the absence of costs from deconsolidating CENG on November 6, 2009.
Our Generation business incurred lower accretion of asset retirement obligations expense of $5.8 million in 2009 compared to 2008, which represents the absence of costs from deconsolidating CENG on November 6, 2009.
Taxes Other Than Income Taxes
Our Generation business incurred lower taxes other than income taxes of $43.8 million in 2010 compared to 2009 and $2.5 million in 2009 compared with 2008, primarily due to lower property taxes as a result of the deconsolidation of CENG on November 6, 2009.
Equity Investment Earnings (Losses)
During 2010, our equity investment earnings increased $24.8 million as compared to 2009, primarily due to $19.3 million of higher earnings from our investment in CENG, $7.9 million of lower losses from our investment in UNE, which was sold in 2010, partially offset by $2.4 million of lower earnings on investments in power projects.
During 2009, our equity investment earnings decreased $26.6 million from 2008 primarily due to $18.8 million of higher losses from our investment in UNE and $12.1 million of lower earnings on investments in power projects, partially offset by $4.3 million in earnings related to our investment in CENG.
Additionally, CENG is involved in negotiations with certain tax jurisdictions in New York State with respect to agreements
43
covering property tax payments on the Nine Mile Point nuclear generating facility. These negotiations may result in an increase in future property tax expenses for CENG, which in turn would reduce our equity investment earnings in CENG based on our 50.01% ownership interest. We are unable to determine the outcome of these negotiations at this time.
Net Gain on Divestitures
During 2010, we sold our Mammoth Lakes geothermal generating facility, recognizing a $38.0 million pre-tax gain, and our 50% interest in UNE in connection with our comprehensive agreement with EDF recognizing a $202.0 million pre-tax gain. We discuss our divestitures in more detail inNote 132 to Consolidated Financial Statements.
. During 2009, we completed the sale of a 49.99% membership interest in CENG to EDF. As a result of thosethis sale, we recognized a $7.4 billion pre-tax gain. We discuss this transaction inNote 2 to Consolidated Financial Statements.
NewEnergy Business
Background
Our NewEnergy business is a competitive provider of energy solutions for various customers. We discuss the impact of competition on our NewEnergy business inItem 1. Business—Competition section.
Our NewEnergy business focuses on delivery of physical, customer-oriented energy products and services to energy producers and consumers, manages the risk and optimizes the value of our owned and contracted generation assets and NewEnergy activities, and uses our portfolio management and trading capabilities both to manage risk and to deploy limited risk capital. Our NewEnergy business actively transacts in energy and energy-related commodities in order to manage our portfolio of energy purchases and sales to customers through structured transactions.
We record NewEnergy revenues and expenses in our financial results in different periods depending upon the appropriate accounting treatment that represents the economics of the underlying transactions we determined thatin our business. We discuss our revenue recognition policies in theCritical Accounting Policies section andNote 1 to Consolidated Financial Statements.
Results
| 2010 | 2009 | 2008 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||
Revenues | $ | 10,121.4 | $ | 11,509.2 | $ | 15,851.7 | |||||
Fuel and purchased energy expenses | (8,877.6 | ) | (10,430.0 | ) | (14,812.2 | ) | |||||
Gross margin | 1,243.8 | 1,079.2 | 1,039.5 | ||||||||
Operating expenses | (758.7 | ) | (763.6 | ) | (932.7 | ) | |||||
Impairment losses and other costs | (0.1 | ) | (98.1 | ) | (727.8 | ) | |||||
Workforce reduction costs | — | (12.6 | ) | (9.5 | ) | ||||||
Merger termination and strategic alternatives costs | — | (44.0 | ) | (462.1 | ) | ||||||
Depreciation, depletion, and amortization | (83.4 | ) | (82.5 | ) | (118.7 | ) | |||||
Accretion of asset retirement obligations | (0.3 | ) | (0.2 | ) | (0.5 | ) | |||||
Taxes other than income taxes | (52.8 | ) | (41.2 | ) | (54.4 | ) | |||||
Equity investment (losses) earnings | — | (6.3 | ) | 49.6 | |||||||
Net gain (loss) on divestitures | 2.5 | (468.8 | ) | 25.5 | |||||||
Income (Loss) from Operations | $ | 351.0 | $ | (438.1 | ) | $ | (1,191.1 | ) | |||
Net Income (Loss) | $ | 176.2 | $ | (348.2 | ) | $ | (1,011.4 | ) | |||
Net Income (Loss) attributable to common stock | $ | 138.6 | $ | (402.3 | ) | $ | (994.2 | ) | |||
Change from prior year | $ | 540.9 | $ | 591.9 | |||||||
| |||||||||||
International coal contract dispute settlement | $ | 35.4 | $ | — | $ | — | |||||
Credit facility amendment/termination fees | (4.6 | ) | (24.0 | ) | — | ||||||
Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits | (0.1 | ) | — | — | |||||||
International commodities operation and gas trading operation (1) | — | (371.9 | ) | — | |||||||
Impairment losses and other costs | — | (84.7 | ) | (460.1 | ) | ||||||
Workforce reduction costs | — | (9.3 | ) | (5.8 | ) | ||||||
Merger termination and strategic alternatives costs | — | (4.1 | ) | (462.1 | ) | ||||||
Non-qualifying hedges | — | — | (70.1 | ) | |||||||
Emission allowance write-down, net | — | — | (28.7 | ) | |||||||
Total Other Items | $ | 30.7 | $ | (494.0 | ) | $ | (1,026.8 | ) | |||
Change from prior year | $ | 524.7 | $ | 532.8 | |||||||
Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.
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Table of losses of approximately $22 million from "Accumulated other comprehensive loss" into earnings, andContents
certain amended nonderivative contracts which are now derivatives accounted for as mark-to-market. This resulted in the recognition of approximately $12Revenues
Our NewEnergy revenues decreased $1,387.8 million in losses from related cash-flow hedges previously deferred in "Accumulated other comprehensive loss." We discuss these contracts in more detail in theMark-to-Market section on the next page.
These decreases were partially offset by approximately $167 million of gross margin from new contracts executed, including the portfolio of contracts acquired in the southeast region during 2007, and higher gross margin associated with existing contracts.
Our wholesale marketing, risk management, and trading operation had $184.9 million of higher gross margin from accrual activities during 20062010 compared to 2005 due to:
| 2010 vs. 2009 | 2009 vs. 2008 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Realization of lower wholesale load sales | $ | (917 | ) | $ | (2,138 | ) | |
(Decrease) increase in volume and contract prices related to our domestic coal operation | (508 | ) | 280 | ||||
Realization of higher (lower) retail power load sales | 349 | (1,491 | ) | ||||
Decrease due to the assignment of international coal and freight contracts, which we divested throughout 2009 | (321 | ) | (647 | ) | |||
Gain on sale of in-the-money wholesale load contract in the second quarter of 2009 | (106 | ) | 106 | ||||
Decrease in volumes at our retail gas and wholesale gas operation | (77 | ) | (283 | ) | |||
Increase (decrease) in wholesale mark-to-market revenues due to changes in power and gas prices | 77 | (215 | ) | ||||
Realization of higher revenues from our Maryland retail residential electric business | 49 | — | |||||
Realization of construction and energy efficiency project revenues | 35 | — | |||||
All other | 31 | 45 | |||||
Total decrease in NewEnergy revenues | $ | (1,388 | ) | $ | (4,343 | ) | |
Fuel and higher realized gross margin on existing contracts,Purchased Energy Expenses
Our NewEnergy fuel and
These increases in gross margin were partially offset by the following:
| 2010 vs. 2009 | 2009 vs. 2008 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Realization of fuel and purchased energy from wholesale power purchases | $ | (641 | ) | $ | (2,541 | ) | |
Decrease due to international coal and freight contracts, which we divested throughout 2009 | (540 | ) | (397 | ) | |||
(Decrease) increase in volume and contract prices related to our domestic coal operation | (498 | ) | 259 | ||||
Increase (decrease) in volumes of retail power load purchases | 217 | (1,467 | ) | ||||
Decrease in volumes at our retail gas and wholesale gas operation | (83 | ) | (220 | ) | |||
All other | (7 | ) | (16 | ) | |||
Total decrease in NewEnergy fuel and purchased energy expenses | $ | (1,552 | ) | $ | (4,382 | ) | |
Mark-to-Market
Mark-to-market results include net gains and losses from origination, trading,risk management, certain physical energy delivery activities, and risk managementtrading 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 theCritical Accounting Policies section and inNote 1 to Consolidated Financial Statements.
As a result of theThe nature of our operations and the use of mark-to-market accounting for certain activities create fluctuations in mark-to-market earnings will fluctuate.earnings. We cannot predict these fluctuations, but the impact on our earnings could be material. We discuss our market risk in more detail in theMarket Risk Management section. The primary factors that cause fluctuations in our mark-to-market results are:
Mark-to-marketDuring 2009 and 2010, we focused our activities on reducing capital requirements, reducing long-term economic risk, and reducing short- and interim-term liquidity requirements. These actions may impact the future results were as follows:
| 2007 | 2006 | 2005 | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||
Unrealized mark-to-market results | ||||||||||||
Origination gains | $ | 41.9 | $ | 13.5 | $ | 61.6 | ||||||
Risk management and trading—mark-to-market | ||||||||||||
Unrealized changes in fair value | 500.8 | 387.4 | 347.2 | |||||||||
Changes in valuation techniques | — | — | — | |||||||||
Reclassification of settled contracts to realized | (369.3 | ) | (372.1 | ) | (257.7 | ) | ||||||
Total risk management and trading—mark-to-market | 131.5 | 15.3 | 89.5 | |||||||||
Total unrealized mark-to-market* | 173.4 | 28.8 | 151.1 | |||||||||
Realized mark-to-market | 369.3 | 372.1 | 257.7 | |||||||||
Total mark-to-market results | $ | 542.7 | $ | 400.9 | $ | 408.8 | ||||||
* Total unrealizedof the NewEnergy business, particularly the size of and potential for changes in fair value of activities subject to mark-to-market is the sumaccounting.
The primary components of mark-to-market results are origination transactionsgains and totalgains and losses from risk management and trading—mark-to-market.trading activities.
Origination gains arise primarily from contracts that our wholesale marketing, risk management, and trading operationNewEnergy business structures to meet the risk management needs of our customers or relate to our trading activities. 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. Origination gains arose primarily from:
As noted above, the recognition of origination gains is dependent on sufficient observable market data that validates the initial fair value of the contract. 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 gains 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.
During 2007, our wholesale marketing, risk management, and trading operation amended certain nonderivative power sales contracts such that the new contracts became derivatives subject to mark-to-market accounting under SFAS No. 133. Simultaneous with the amending of the nonderivative contracts, we executed at current market prices several new offsetting derivative power purchase contracts subject to mark-to-market accounting. The combination of these transactions resulted in substantially all of the origination gains presented for 2007 in the table on the preceding page, as well as mitigated our risk exposure under the amended contracts.
The origination gain from these transactions was partially offset by approximately $12 million of losses in our accrual portfolio due to the reclassification of losses related to cash-flow hedges previously established for the amended nonderivative contracts from "Accumulated other comprehensive loss" into earnings as discussed in ourCompetitive Supply-Wholesale Accrual section on the previous page. In the absence of these transactions, the economic value represented by the origination gain and the losses associated with cash-flow hedges would have been recognized over the remaining term of the contracts, which extended through the first quarter of 2009.
Risk management and trading—mark-to-market represents both realized and unrealized gains and losses from changes in the value of our portfolio, including the recognitioneffects of gains associated with decreaseschanges in the close-out adjustment when we are able to obtain sufficient market price information.valuation adjustments. In addition to our fundamental risk management and trading activities, we also use non-trading derivative contracts subject to mark-to-market accounting to manage our exposure to changes in market prices, primarily as a result of our gas transportation and storage activities, while in general the underlying physical transactions related to our gasthese activities are accounted for on an accrual basis.
We discuss the changes in mark-to-market results below. We show the relationship between our mark-to-market results and the change in our net mark-to-market energy asset later in this section.
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Mark-to-market results were as follows:
| 2010 | 2009 | 2008 | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||
Unrealized mark-to-market results | ||||||||||||
Origination gains | $ | — | $ | — | $ | 73.8 | ||||||
Risk management and trading—mark-to-market | ||||||||||||
Unrealized changes in fair value | 9.6 | (212.3 | ) | 159.8 | ||||||||
Changes in valuation techniques | — | — | — | |||||||||
Reclassification of settled contracts to realized | (139.0 | ) | (265.4 | ) | 48.2 | |||||||
Total risk management and trading—mark-to-market | (129.4 | ) | (477.7 | ) | 208.0 | |||||||
Total unrealized mark-to-market (1) | (129.4 | ) | (477.7 | ) | 281.8 | |||||||
Realized mark-to-market | 139.0 | 265.4 | (48.2 | ) | ||||||||
Total mark-to-market results (2) | $ | 9.6 | $ | (212.3 | ) | $ | 233.6 | |||||
Total mark-to-market results increased $141.8$221.9 million during 2007the year ended December 31, 2010 compared to 2006 mostly becausethe same period of an increase in2009 due to unrealized changes in fair value of approximately $113 million and an increase in origination gains previously discussed. The increase in unrealized changes in fair value was primarily due to:
These increases were partially offset by approximately $62the absence of $40 million in results from lower mark-to-market results related to the impact of certain economic hedges, primarily related to gas transportationour international coal and storage contracts that do not qualify for or are not designated as cash-flow hedges. These mark-to-market results will be offsetfreight operations, which we divested in future periods as we realize the related accrual load-serving positions in cash.
The close-out adjustments are determined by the change in open positions, new transactions where we did not have observable market price information, and existing transactions where we have now observed sufficient market price information and/or we realized cash flows since the transactions' inception. We discuss the close-out adjustment in more detail in theCritical Accounting Policies section.2009.
Total mark-to-market results decreased $7.9$445.9 million in 2006during the year ended December 31, 2009 compared to 2005 becausethe same period of a decrease in origination gains of $48.1 million, mostly offset by an increase in unrealized changes in fair value of $40.2 million. Unrealized changes in fair value increased, primarily due to higher pre-tax gains of approximately $105 million related to the positive impact of certain economic hedges primarily related to gas transportation and storage contracts.
This increase2008. The period-to-period variance in unrealized changes in fair value was partially offset by:due to decreased unrealized risk management and trading results of $372.1 million and the decrease in origination gains of $73.8 million. We discuss the decrease in origination gains below.
The decrease in risk management and trading results of $372.1 million was primarily due to:
These decreases were partially offset by the following:
We did not record any origination gains during 2010 and 2009. During 2008, our NewEnergy business amended certain nonderivative contracts to mitigate counterparty performance risk under the existing contracts. As a result of these amendments, the revised contracts became derivatives subject to mark-to-market accounting. The change in accounting for these contracts from nonderivative to derivative resulted in substantially all of the origination gains for 2008 presented in the unrealized mark-to-market results table above.
The recognition of origination gains is generally dependent on sufficient available market data that validates the initial fair value of the contract. Liquidity and market conditions impact our ability to identify sufficient, objective market price information to permit recognition of origination gains. As a result, the level of origination gains 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.
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Derivative Assets and Liabilities
Derivative assets and liabilities consisted of the following:
At December 31, | 2010 | 2009 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Current assets | $ | 534.4 | $ | 639.1 | |||
Noncurrent assets | 258.9 | 633.9 | |||||
Total assets | 793.3 | 1,273.0 | |||||
Current liabilities | 622.3 | 632.6 | |||||
Noncurrent liabilities | 353.0 | 674.1 | |||||
Total liabilities | 975.3 | 1,306.7 | |||||
Net derivative position | $ | (182.0 | ) | $ | (33.7 | ) | |
Composition of net derivative exposure: | |||||||
Hedges | $ | (504.5 | ) | $ | (591.0 | ) | |
Mark-to-market | 350.3 | 524.3 | |||||
Net cash collateral included in derivative balances | (27.8 | ) | 33.0 | ||||
Net derivative position | $ | (182.0 | ) | $ | (33.7 | ) | |
Derivative balances above include noncurrent assets related to our Generation business of $35.7 million and $35.8 million at December 31, 2010 and December 31, 2009, respectively. Derivative balances related to our Generation business consist of interest rate contracts accounted for as fair value hedges.
As discussed in ourCritical Accounting Policies section, our "Derivative assets and liabilities" include contracts accounted for as hedges and those accounted for on a mark-to-market basis. These amounts are presented in our Consolidated Balance Sheets after the impact of netting, which is discussed in more detail in
DerivativeNote 1 to Consolidated Financial Statements. Due to the impacts of commodity prices, the number of open positions, master netting arrangements, and offsetting risk positions on the presentation of our derivative assets and liabilities consistedin our Consolidated Balance Sheets, we believe an evaluation of the following:net position is the most relevant measure, and is discussed in more detail below. However, we present our gross derivatives inNote 13 to Consolidated Financial Statements.
At December 31, | 2007 | 2006 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Current Assets | $ | 961.2 | $ | 1,556.5 | |||
Noncurrent Assets | 1,030.2 | 949.1 | |||||
Total Assets | 1,991.4 | 2,505.6 | |||||
Current Liabilities | 1,137.1 | 2,411.7 | |||||
Noncurrent Liabilities | 1,118.9 | 1,099.7 | |||||
Total Liabilities | 2,256.0 | 3,511.4 | |||||
Net Derivative Position | $ | (264.6 | ) | $ | (1,005.8 | ) | |
Portion of net derivative position accounted for as hedges | $ | (937.6 | ) | $ | (1,459.9 | ) | |
Portion of net derivative position accounted for as mark-to-market | $ | 673.0 | $ | 454.1 | |||
The decrease of $86.5 million in our net derivative liability subject to hedge accounting since December 31, 2006 of $522.3 million2009 was due primarily to an approximate $355$700.0 million change inof realization of out-of-the-money cash-flow hedges at the time the forecasted transaction occurred, partially offset by $613.5 million of increases on our out-of-the-money cash-flow hedge positions which include both increasesprimarily related to decreases in power, natural gas, and coal prices that increased the fair value of our cash-flow hedge positions and settlements of cash-flow hedges during 2007, and approximately $167 million of net cash-flow hedge assets acquired as part of a contract and portfolio acquisition in June 2007. We discuss this contract and portfolio acquisition in more detail inFinancial Condition—Contract and Portfolio Acquisitions.2010.
While some of our mark-to-market contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. We discuss our modeling techniques later in this section. The following are the primary sources of the change in our net derivative asset subject to mark-to-market accounting during 20072010 and 2006:2009:
| 2007 | 2006 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||||
Fair value beginning of year | $ | 454.1 | $ | 167.5 | ||||||||||
Changes in fair value recorded in earnings | ||||||||||||||
Origination gains | $ | 41.9 | $ | 13.5 | ||||||||||
Unrealized changes in fair value | 500.8 | 387.4 | ||||||||||||
Changes in valuation techniques | — | — | ||||||||||||
Reclassification of settled contracts to realized | (369.3 | ) | (372.1 | ) | ||||||||||
Total changes in fair value recorded in earnings | 173.4 | 28.8 | ||||||||||||
Changes in value of exchange-listed futures and options | 18.6 | 277.8 | ||||||||||||
Net change in premiums on options | (19.0 | ) | (29.8 | ) | ||||||||||
Contracts acquired | 83.8 | — | ||||||||||||
Other changes in fair value | (37.9 | ) | 9.8 | |||||||||||
Fair value at end of year | $ | 673.0 | $ | 454.1 | ||||||||||
| 2010 | 2009 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||||
Fair value beginning of year | $ | 524.3 | $ | 1,485.9 | ||||||||||
Changes in fair value recorded in earnings | ||||||||||||||
Origination gains | $ | — | $ | — | ||||||||||
Unrealized changes in fair value | 9.6 | (212.3 | ) | |||||||||||
Changes in valuation techniques | — | — | ||||||||||||
Reclassification of settled contracts to realized | (139.0 | ) | (265.4 | ) | ||||||||||
Total changes in fair value | (129.4 | ) | (477.7 | ) | ||||||||||
Changes in value of exchange-listed futures and options | (197.1 | ) | 97.8 | |||||||||||
Net change in premiums on options | 17.7 | 84.9 | ||||||||||||
Contracts acquired | 5.4 | (35.8 | ) | |||||||||||
Dedesignated contracts and other changes in fair value | 129.4 | (630.8 | ) | |||||||||||
Fair value at end of year | $ | 350.3 | $ | 524.3 | ||||||||||
Changes in our net derivative asset subject to mark-to-market accounting that affected earnings were as follows:
OurThe net derivative asset subject to mark-to-market accounting also changed due to the following items recorded in accounts other than in our Consolidated Statements of Income:Income (Loss):
47
amounts are settled through our margin account with a third-partythird party broker.
The settlement terms of the portion of our net derivative asset subject to mark-to-market accounting and sources of fair value based on the fair value hierarchy are as follows as of December 31, 2007 are as follows:2010:
| Settlement Term | | ||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2008 | 2009 | 2010 | 2011 | 2012 | 2013 | Thereafter | Fair Value | ||||||||||||||||
| (In millions) | |||||||||||||||||||||||
Prices provided by external sources (1) | $ | 359.0 | $ | 50.6 | $ | 26.2 | $ | 30.3 | $ | 28.0 | $ | 6.8 | $ | 3.0 | $ | 503.9 | ||||||||
Prices based on models | (1.8 | ) | 71.1 | 74.4 | 36.5 | (11.4 | ) | (1.3 | ) | 1.6 | 169.1 | |||||||||||||
Total net mark-to-market energy asset | $ | 357.2 | $ | 121.7 | $ | 100.6 | $ | 66.8 | $ | 16.6 | $ | 5.5 | $ | 4.6 | $ | 673.0 | ||||||||
| Settlement Term | | |||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2011 | 2012 | 2013 | 2014 | 2015 | 2016 | Thereafter | Fair Value | |||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
Level 1 | $ | 1.1 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 1.1 | |||||||||
Level 2 | 321.5 | 214.2 | 4.1 | 2.0 | 8.0 | 0.7 | (0.1 | ) | 550.4 | ||||||||||||||||
Level 3 | 43.2 | (232.0 | ) | (14.0 | ) | 6.0 | 5.0 | 4.2 | (13.6 | ) | (201.2 | ) | |||||||||||||
Total net derivative asset (liability) subject to mark-to-market accounting | $ | 365.8 | $ | (17.8 | ) | $ | (9.9 | ) | $ | 8.0 | $ | 13.0 | $ | 4.9 | $ | (13.7 | ) | $ | 350.3 | ||||||
Management uses its best estimates to determine the fair value of commodity and derivative contracts actively quotedit holds and contracts valuedsells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. 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. Future market prices and actual quantities will vary from other external sources.
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 on the preceding page 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 our net derivative asset subject to mark-to-market accounting 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.
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 ofmany contracts used in the wholesale marketing, risk management, and trading operation are direct contracts between market participants and are not exchange-traded or financially settling contracts that can be readily liquidatedoffset 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 preceding 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 an amount different from the entire value reflected in the preceding table. However, based upon the nature of the wholesale marketing, risk management, and trading operation,our NewEnergy business, we generally 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. In general,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 December 31, 2007 and could change significantly as a result of future changes in these factors. Additionally, because the depth and liquidity of the power markets vary 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 our net derivative assets and liabilities subject to mark-to-market accounting, and it is possible that such variations could be material.
In 2006, the Financial Accounting Standards Board issued SFAS No. 157 that will impact our accounting for derivative instruments. We discuss this in more detail inNote 1.
Other
| 2007 | 2006 | 2005 | ||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Revenues | $ | 69.3 | $ | 74.8 | $ | 58.0 | |||
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 based on the facilities' energy source or the use of a cogeneration process. In addition, during 2007, our merchant energy business obtained and currently holds a 50% interest in a joint venture to develop, own, and operate new nuclear projects in the United States and Canada (UniStar Nuclear Energy, LLC (UNE)). Earnings from these investments were $2.8 million in 2007, $13.8 million in 2006, and $3.6 million in 2005.
Investments
Our investment in qualifying facilities and domestic power projects, CEP, and joint ventures consisted of the following:
Book Value at December 31, | 2007 | 2006 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Project Type | |||||||
Coal | $ | 119.6 | $ | 125.7 | |||
Hydroelectric | 54.7 | 55.1 | |||||
Geothermal | 37.6 | 40.5 | |||||
Biomass | 43.6 | 46.6 | |||||
Fuel Processing | 26.8 | 33.7 | |||||
Solar | 7.0 | 7.0 | |||||
CEP | 143.0 | — | |||||
Joint ventures: | |||||||
Shipping JV | 56.6 | — | |||||
UNE | 52.2 | — | |||||
Other | 1.1 | — | |||||
Total | $ | 542.2 | $ | 308.6 | |||
We believe the current market conditions for our equity-method investments that own geothermal, coal, hydroelectric, fuel processing projects, as well as our equity investments in our joint ventures and CEP 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 certain risks and uncertainties in more detail in ourForward Looking Statements andItem 1A. Risk Factors sections. However, should future events cause these investments to become uneconomic, our investments in these projects could become impaired under the provisions of APB No. 18.
Current California statutes and regulations require load-serving entities to increase their procurement of renewable energy resources and mandate statewide reductions in greenhouse gas emissions. Given the need for electric power and the statutory and regulatory requirements increasing demand for renewable resource technologies, we believe California will continue to foster an environment that supports the use of renewable energy and continues certain subsidies that will make renewable energy projects economical. However, should California legislation and regulatory policies and federal energy policies fail to adequately support renewable energy initiatives, our equity-method investments in these types of projects could become impaired under the provisions of APB No. 18, and any losses recognized could be material.
Operating Expenses
Our merchant energyNewEnergy business operating expenses increased $242.4decreased $169.1 million during 20072009 as compared to 2006 mostly2008 due to an increase at our competitive supply operations totaling $218.4 million, primarily related to the continued growth of this operation and higher compensation and benefit costs.
Our merchant energy business operating expenses increased $203.3 million in 2006 compared to 2005 mostly due to the following:
Impairment Losses and Other Costs2009.
Our impairment losses and other costs are discussed in more detail in
48Note 2.
Workforce Reduction Costs
Our merchant energy business recognized expenses associated with our workforce reduction efforts as discussed in more detail inNote 2.
Merger-Related Costs
We discuss costs related to the proposed merger with FPL Group, which has been terminated, inNote 15.Table of Contents
Depreciation, Depletion and Amortization Expense
Merchant energyOur NewEnergy business incurred lower depreciation, depletion and amortization expenses increased $11.2of $36.2 million in 2007during 2009 compared to 2006 mostly2008 due to:
These increases were partially offset by $29.0 million primarily related to the absence of depreciation associated withdepletion expenses of $43.0 million as a result of divestitures made in 2008 in our upstream gas operations, partially offset by an increase of $6.8 million in other amortization primarily related to computer software placed in service in the gas plants that were sold in December 2006.fourth quarter of 2008.
Taxes Other Than Income Taxes
Taxes other than income taxes decreased $9.8 million in 2007 compared to 2006, primarily due to $5.8 million lower gross receipts tax at our retail competitive supply operation and a $4.2 million decrease due to the sale of our gas-fired plants.
Merchant energyOur NewEnergy business incurred higher taxes other than income taxes increased $13.3of $11.6 million in 20062010 compared to 2005 mostly2009, primarily due to $5.3 million related to higher gross receipts taxes at ourrelated to an increase in retail competitive supply operationrevenues, primarily in Pennsylvania.
Our NewEnergy business incurred lower taxes other than income taxes of $13.2 million in 2009 compared to 2008, due to $8.1 million of lower gross receipts taxes resulting from a significant decrease in retail load revenues and $3.1$5.8 million of lower production taxes related to our workingupstream gas producing properties, partially offset by $0.7 million of higher property, franchise, and other taxes.
Equity Investment (Losses) Earnings
During 2009, our equity investment earnings decreased $55.9 million from 2008 primarily due to $39.1 million of lower earnings from our shipping joint venture as a result of the sale of our interests in gas producing properties.July 2009, $12.3 million of lower earnings from our investment in CEP, and the absence of $4.5 million in earnings from investments in synfuel facilities.
Net Gain (Loss) on Divestitures
The table below summarizes the net gain (loss) on divestitures for our NewEnergy business:
| 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Majority of our international commodities operation | $ | — | $ | (334.5 | ) | $ | — | |||
Houston-based gas trading operation | — | (102.5 | ) | — | ||||||
Uranium market participant | — | (27.2 | ) | — | ||||||
Portfolio of contracts in our retail gas operations | 2.0 | — | — | |||||||
Various working interests in oil and natural gas producing properties and working interests in proved natural gas reserves and unproved properties | — | — | 25.5 | |||||||
Other | 0.5 | (4.6 | ) | — | ||||||
Total net gain (loss) on divestiture | $ | 2.5 | $ | (468.8 | ) | $ | 25.5 | |||
We discuss these divestitures in more detail inNote 2 to Consolidated Financial Statements.
Regulated Electric Business
Our regulated electric business is discussed in detail inItem 1. Business—Electric Business section.
Results
| 2007 | 2006 | 2005 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||
Revenues | $ | 2,455.7 | $ | 2,115.9 | $ | 2,036.5 | |||||
Electricity purchased for resale expenses | (1,500.4 | ) | (1,167.8 | ) | (1,068.9 | ) | |||||
Operations and maintenance expenses | (376.1 | ) | (351.3 | ) | (318.4 | ) | |||||
Merger-related costs | — | (3.3 | ) | (4.0 | ) | ||||||
Depreciation and amortization | (187.4 | ) | (181.5 | ) | (185.8 | ) | |||||
Taxes other than income taxes | (140.2 | ) | (134.9 | ) | (135.3 | ) | |||||
Income from Operations | $ | 251.6 | $ | 277.1 | $ | 324.1 | |||||
Net Income | $ | 97.9 | $ | 120.2 | $ | 149.4 | |||||
Other Items Included in Operations (after-tax) | |||||||||||
Merger-related costs | $ | — | $ | (0.8 | ) | $ | (3.7 | ) | |||
| 2010 | 2009 | 2008 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||
Revenues | $ | 2,752.3 | $ | 2,820.7 | $ | 2,679.7 | |||||
Electricity purchased for resale expenses | (1,680.9 | ) | (1,840.9 | ) | (1,880.1 | ) | |||||
Operations and maintenance expenses | (449.3 | ) | (399.0 | ) | (380.5 | ) | |||||
Workforce reduction costs | — | — | (4.6 | ) | |||||||
Depreciation and amortization | (205.2 | ) | (218.1 | ) | (184.2 | ) | |||||
Taxes other than income taxes | (149.1 | ) | (142.9 | ) | (139.1 | ) | |||||
Income from Operations | $ | 267.8 | $ | 219.8 | $ | 91.2 | |||||
Net Income | $ | 110.0 | $ | 79.1 | $ | 11.1 | |||||
Net Income attributable to common stock | $ | 99.8 | $ | 68.9 | $ | 1.1 | |||||
| |||||||||||
Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits | $ | (3.1 | ) | $ | — | $ | — | ||||
Residential customer rate credit | — | (56.7 | ) | — | |||||||
Maryland settlement credit | — | — | (110.5 | ) | |||||||
Workforce reduction costs | — | — | (2.8 | ) | |||||||
Total Other Items | $ | (3.1 | ) | $ | (56.7 | ) | $ | (113.3 | ) | ||
Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.
Net income attributable to common stock from the regulated electric business decreased $22.3increased $30.9 million in 20072010 compared to 2006, primarily2009, mostly due to the following:
The decrease was partially offset by an increase in revenues less electricity purchased for resale expenses of $4.4 million after-tax, which includes the impact of Senate Bill 1 credits.expenses.
Net income attributable to common stock from the regulated electric business decreased $29.2increased $67.8 million in 20062009 compared to 2005 mostly because of the following:
49
Electric Revenues
The changes in electric revenues in 20072010 and 20062009 compared to the respective prior year were caused by:
| 2007 | 2006 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Distribution volumes | $ | 19.5 | $ | (40.9 | ) | ||
Standard offer service | 267.8 | 433.7 | |||||
Rate stabilization credits | 34.6 | (321.9 | ) | ||||
Rate stabilization recovery | 36.1 | — | |||||
Financing credits | (7.5 | ) | — | ||||
Senate Bill 1 credits | (29.7 | ) | — | ||||
Total change in electric revenues from electric system sales | 320.8 | 70.9 | |||||
Other | 19.0 | 8.5 | |||||
Total change in electric revenues | $ | 339.8 | $ | 79.4 | |||
| 2010 vs. 2009 | 2009 vs. 2008 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Distribution volumes | $ | 32.7 | $ | (6.3 | ) | ||
Base rates | 3.3 | — | |||||
Residential customer rate credit | 95.0 | (95.0 | ) | ||||
Nuclear decommissioning charges | — | 18.7 | |||||
Smart Energy Savers ProgramSM surcharges | (22.0 | ) | 29.3 | ||||
Maryland settlement credit | — | 189.1 | |||||
Revenue decoupling | (30.9 | ) | 22.7 | ||||
Standard offer service | (154.2 | ) | (33.2 | ) | |||
Rate stabilization recovery | 2.5 | (2.7 | ) | ||||
Financing credits | 0.4 | 3.4 | |||||
Senate Bill 1 credits | (12.9 | ) | 6.9 | ||||
Total change in electric revenues from electric system sales | (86.1 | ) | 132.9 | ||||
Other | 17.7 | 8.1 | |||||
Total change in electric revenues | $ | (68.4 | ) | $ | 141.0 | ||
Distribution Volumes
Distribution volumes are the amount of electricity that BGE delivers to customers in its service territory.
The percentage changes in our electric system distribution volumes, by type of customer, in 20072010 and 20062009 compared to the respective prior year were:
| 2007 | 2006 | ||
---|---|---|---|---|
Residential | 3.7 | % | (6.4)% | |
Commercial | 3.6 | (0.6) | ||
Industrial | 0.2 | (7.5) |
| 2010 | 2009 | |||||
---|---|---|---|---|---|---|---|
Residential | 7.6 | % | (1.3 | )% | |||
Commercial | 3.5 | — | |||||
Industrial | (8.0 | ) | (6.7 | ) |
In 2007,2010, we distributed more electricity to residential and commercial customers due to warmer summer and colder winterfourth quarter weather and an increased number of customers. We distributed less electricity to industrial customers partially offset byprimarily due to decreased usage per customer. We
In 2009, we distributed moreless electricity to commercialresidential customers due to increaseddecreased usage per customer, partially offset by colder winter weather and an increased number of customers. We distributed essentially the same amount of electricity to industrial customers.
In 2006, we distributed less electricity to residential customers mostly due to milder weather and decreased usage per customer, partially offset by an increased number of customers. We distributed less electricity to commercial customers mostly due to milder weather, partially offset by an increased number of customers and increased usage per customer. We distributed less electricity to industrial customers mostlyprimarily due to decreased usage per customer.
Base Rates
On December 6, 2010, the Maryland PSC issued an abbreviated order authorizing BGE to increase electric distribution rates by $31.0 million for service rendered on or after December 4, 2010. This increase was based upon an 8.06% rate of return with a 9.86% return on equity and a 52% equity ratio. We discuss BGE's electric base rates in theRegulation—Maryland—Base Rates section.
Residential Customer Rate Credit
On October 30, 2009, the Maryland PSC issued an order approving Constellation Energy's transaction with EDF. Among other things, the order required Constellation Energy to fund a one-time distribution rate credit for BGE residential customers before the end of March 2010 totaling $110.5 million, or approximately $100 per customer, for which BGE recorded a liability in November 2009. In December 2009, BGE filed a tariff with the Maryland PSC stating BGE would give residential customers a rate credit of exactly $100 per customer. As a result, BGE accrued an additional $1.9 million for a total fourth quarter 2009 accrual of $112.4 million. The portion of this total credit allocated to residential electric customers was $95.0 million pre-tax. This credit was accrued in the fourth quarter of 2009 and applied to BGE residential electric customer bills in the first quarter of 2010.
Nuclear Decommissioning Charges
Effective January 1, 2009, BGE and Calvert Cliffs Nuclear Power Plant Inc. (Calvert Cliffs) mutually agreed to terminate the decommissioning funds collection agent agreement, which was effective from July 1, 2000 to December 31, 2008. As a result, BGE ceased transferring funds to provide for the decommissioning of Calvert Cliffs Unit 1 and Unit 2. Calvert Cliffs retains the obligation to provide adequate assurances of funding pursuant to Nuclear Regulatory Commission requirements. Under the 2008 Maryland settlement agreement, BGE will continue to provide certain credits to residential customers and assess certain charges to all customers relating to decommissioning.
Smart Energy Savers ProgramSM Surcharge
Beginning in 2009, the Maryland PSC approved customer surcharges through which BGE recovers costs associated with certain programs designed to help BGE manage peak demand and encourage customer energy conservation through the use of customer bill credits.
Revenues declined in 2010 compared to 2009, primarily due to an increase in customer involvement in our programs. This increased participation increased customer credits and, therefore, decreased revenues.
Revenues increased in 2009 compared to 2008, primarily due to $29.3 million of customer surcharge revenues from the new programs implemented in 2009 that were not in place in 2008.
Maryland Settlement Credit
As discussed in more detail inNote 2 to Consolidated Financial Statements, BGE entered into a settlement agreement with the State of Maryland and other parties, which provided residential electric customers a credit totaling $170 per customer. The estimated settlement of $188.2 million was accrued in the second quarter of 2008 and a total of $189.1 million was credited to customers in the third and fourth quarters of 2008.
50
Revenue Decoupling
The Maryland PSC has allowed us to record a monthly adjustment to our electric distribution revenues from residential and small commercial customers since 2008 and for the majority of our large commercial and industrial customers since February 2009 to eliminate the effect of abnormal weather and usage patterns per customer on our electric distribution volumes, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. This means BGE recognizes revenues at Maryland PSC-approved levels per customer, regardless of what actual distribution volumes were for a billing period. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions. We then bill or credit impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.
Standard Offer Service
BGE provides standard offer service for customers that do not select an alternative supplier. We discuss the provisions of Maryland's Senate Bill 1 related to residential electric rates in theBusiness Environment—Regulation—Maryland—Senate Bills 1 and 400 section.
Standard offer service revenues increaseddecreased in 20072010 compared to 2006, primarily2009 mostly due to an increase in thelower standard offer service rates following the expiration of residential rate freeze service in July 2006, partially offset by lower standard offer serviceand volumes.
Standard offer service revenues were higherdecreased in 20062009 compared to 2005,2008 mostly due to an increase to market prices in the standard offer service rates due to the expiration of the residential rate freeze in July 2006, partially offset by lower standard offer service volumes.
Rate Stabilization Credits
As a result of Senate Bill 1, we were required to defer from July 1, 2006 until May 31, 2007 a portion of the full market rate increase resulting from the expiration of the residential rate freeze. In addition, we offered a plan also required under Senate Bill 1 allowing residential customers the option to defer the transition to market rates from June 1, 2007 until January 1, 2008. The total amount deferred under this additional plan was $6.5 million as of December 31, 2007.
In 2007 compared to 2006, the amount of rate stabilization credits provided to residential electric customers decreased, primarily due to the end of the first deferral period on May 31, 2007,volumes, partially offset by the additional deferrals during the second deferral period, which ended on December 31, 2007.higher standard offer service rates.
Rate Stabilization Recovery
In late June 2007, BGE began recovering amounts deferred during the first rate deferral period that began in July 2006 and ended on May 31, 2007. The recovery of the first rate stabilization plan is occurring over a ten year period. In April 2008, BGE began recovering amounts deferred during the second rate deferral period that began in June 2007 in late Juneand ended on December 31, 2007. The recovery of the second rate deferral occurred over a 21-month period that began April 1, 2008 and ended on December 31, 2009.
Financing Credits
Concurrent with the recovery of the deferred amounts related to the first rate deferral period, we are providing credits to residential customers to compensate them primarily for income tax benefits associated with the financing of the deferred amounts with rate stabilization bonds. We discuss the rate stabilization bonds in more detail inNote 9.
Senate Bill 1 Credits
As a result of Senate Bill 1, beginning January 1, 2007, we were required to provide to residential electric customers a credit equal to the amount collected from all BGE ratepayerselectric customers for the decommissioning of our Calvert Cliffs nuclear power plantNuclear Power Plant and to suspend collection of the residential return component of the Provider of Last Resort (POLR) administrative charge collected through residential POLRSOS rates through May 31, 2007. Under an order issued by the Maryland PSC in May 2007, as of June 1, 2007, we were required to reinstate collection of the residential return component of the POLR administration charge in POLR rates and to provide all residential electric customers a credit for the residential return component of the administrative charge. Under the 2008 Maryland settlement agreement, which is discussed in more detail inNote 2 to Consolidated Financial Statements, BGE was allowed to resume collection of the residential return portion of the administrative charge from June 1, 2008 through May 31, 2010 without having to rebate it to residential customers.
The decrease in revenues during 2010 compared to 2009 is primarily due to the reinstatement of the credit for the residential return component of the administrative charge on June 1, 2010 and higher distribution volumes.
The increase in revenues during 2009 compared to 2008 is primarily due to the absence of the credit for the residential return component of the administrative charge which was suspended under the Maryland settlement agreement, partially offset by lower distribution volumes.
Electricity Purchased for Resale Expenses
Electricity purchased for resale expenses include the cost of electricity purchased for resale to our standard offer service customers. These costs do not include the cost of electricity purchased by delivery service only customers. The following table summarizes our regulated electricity purchased for resale expenses:
| 2007 | 2006 | 2005 | ||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Actual costs | $ | 1,759.2 | $ | 1,489.7 | $ | 1,068.9 | |||
Deferral under rate stabilization plan | (287.3 | ) | (321.9 | ) | — | ||||
Recovery under rate stabilization plans | 28.5 | — | — | ||||||
Electricity purchased for resale expenses | $ | 1,500.4 | $ | 1,167.8 | $ | 1,068.9 | |||
| 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Actual costs | $ | 1,618.3 | $ | 1,781.9 | $ | 1,821.1 | ||||
Recovery under rate stabilization plans | 62.6 | 59.0 | 59.0 | |||||||
Electricity purchased for resale expenses | $ | 1,680.9 | $ | 1,840.9 | $ | 1,880.1 | ||||
Actual Costs
BGE's actual costs for electricity purchased for resale increased $269.5decreased $163.6 million for 20072010 compared to 2006, primarily2009, mostly due to higher contract prices to purchase electricity for our residential customers following the expiration of contracts that were executed in 2000 as part of the implementation of electric deregulation in Maryland, partially offset by lower standard offer service rates and volumes.
BGE's actual costs for electricity purchased for resale increased $420.8decreased $39.2 million in 2006for 2009 compared to 20052008, primarily due to higher contract prices to purchase electricity resulting from the expiration of contracts that were executed in 2000 as part of the implementation of electric deregulation in Maryland, partially offset by lower standard offer service volumes.volumes, partially offset by higher standard offer service rates.
DeferralRecovery under Rate Stabilization PlanPlans
We deferBetween July 2006 and May 31, 2007, we deferred $287.3 million in electricity purchased for resale expenses representing the difference between our actual costs of electricity purchased for resale and what we are allowed to bill customers under Senate Bill 1. In 2007, we deferred $287.3 million in electricity purchased for resale expenses. Since July 1, 2006, we have deferred $609.2 million in electricity purchased for resale expenses. In 2006, we deferred $321.9 million in electricity purchased for resale expenses. These deferred expenses, plus carrying charges, are included in "Regulatory Assets (net)" in our, and BGE's, Consolidated Balance Sheets. We discuss the provisions of Senate Bill 1 related to residential electric rates in theBusiness Environment—Regulation—Maryland—Senate Bills 1 and 400 section.
Recovery under Rate Stabilization Plans
In late June 2007, we began recovering previously deferred amounts from customers. We recovered $28.5$62.6 million, $59.0 million, and $59.0 million in 20072010, 2009, and 2008, respectively, in deferred electricity purchased for resale expenses. As discussed later, theseThese collections secure the payment of principal and interest
51
and other ongoing costs associated with rate stabilization bonds issued by a subsidiary of BGE in June 2007.
Electric Operations and Maintenance Expenses
Regulated electric operations and maintenance expenses increased $24.8$50.3 million in 20072010 compared to 2006 mostly2009, primarily due to increased distribution service restoration expenses of $24.2 million, $13.4 million of higher labor and benefitbenefits costs, and the impact of inflation on other costs of $16.9 million, customer education in relation to rate stabilization of $5.3 million and increased uncollectible accounts receivable expense of $2.9$12.7 million.
Regulated electric operations and maintenance expenses increased $32.9$18.5 million in 20062009 compared to 2005 mostly2008, primarily due to higher labor and benefit costsincreased uncollectible accounts receivable expense of $5.1 million and the impact of inflation on other costs and $13.1 million of incremental distribution service restoration expenses associated with 2006 storms.$8.0 million.
Electric Depreciation and Amortization Expense
Regulated electric depreciation and amortization expense decreased $12.9 million during 2010, compared to 2009, primarily due to decreased amortization of $22.9 million of deferred Smart Energy Savers ProgramSM costs due to a regulatory change in the deferral period associated with these costs, partially offset by a $7.0 million increase in property, plant and equipment depreciation.
Regulated electric depreciation and amortization expense increased $5.9$33.9 million during 2009, compared to 2008, primarily due to $43.3 million in 2007 compared to 2006, primarily due toincreased amortization expense associated with the Smart Energy Savers ProgramSM and additional property placed in service.
Regulated electric depreciation and amortization expense decreased $4.3 millionservice in 2006 compared to 2005 mostly because of the absence of $6.9 million amortization expense associated with certain software,2009, partially offset by $3.0$18.7 million related to additional property placed in service.lower depreciation expense as a result of revised depreciation rates which were implemented on June 1, 2008 for regulatory and financial reporting purposes as part of the Maryland settlement agreement.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $5.3$6.2 million in 2007 in comparison with 2006,during 2010 compared to 2009, primarily due to the absence in 2010 of the impact of lower customer credits on franchise taxes of $95.0 million pre-tax.
Taxes other than income taxes increased property$3.8 million during 2009 compared to 2008, primarily due to the impact of $94.1 million pre-tax in lower customer credits on franchise taxes.
Regulated Gas Business
Our regulated gas business is discussed in detail inItem 1. Business—Gas Business section.
Results
| 2007 | 2006 | 2005 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||
Revenues | $ | 962.8 | $ | 899.5 | $ | 972.8 | |||||
Gas purchased for resale expenses | (639.8 | ) | (581.5 | ) | (687.5 | ) | |||||
Operations and maintenance expenses | (157.5 | ) | (144.8 | ) | (131.8 | ) | |||||
Merger-related costs | — | (1.4 | ) | (1.4 | ) | ||||||
Depreciation and amortization | (46.8 | ) | (46.0 | ) | (46.6 | ) | |||||
Taxes other than income taxes | (36.1 | ) | (33.8 | ) | (33.1 | ) | |||||
Income from Operations | $ | 82.6 | $ | 92.0 | $ | 72.4 | |||||
Net Income | $ | 28.8 | $ | 37.0 | $ | 26.7 | |||||
Other Items Included in Operations (after-tax) | |||||||||||
Merger-related costs | $ | — | $ | (0.4 | ) | $ | (1.3 | ) | |||
| 2010 | 2009 | 2008 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||
Revenues | $ | 709.4 | $ | 758.3 | $ | 1,024.0 | |||||
Gas purchased for resale expenses | (387.5 | ) | (449.9 | ) | (694.5 | ) | |||||
Operations and maintenance expenses | (156.8 | ) | (160.9 | ) | (157.3 | ) | |||||
Workforce reduction costs | — | — | (1.8 | ) | |||||||
Depreciation and amortization | (44.0 | ) | (44.0 | ) | (43.7 | ) | |||||
Taxes other than income taxes | (34.7 | ) | (34.9 | ) | (35.4 | ) | |||||
Income from Operations | $ | 86.4 | $ | 68.6 | $ | 91.3 | |||||
Net Income | $ | 37.6 | $ | 25.5 | $ | 40.4 | |||||
Net Income attributable to common stock | $ | 34.6 | $ | 22.5 | $ | 37.2 | |||||
| |||||||||||
Residential customer rate credit | $ | — | $ | (10.4 | ) | $ | — | ||||
Workforce reduction costs | — | — | (1.0 | ) | |||||||
Total Other Items | $ | — | $ | (10.4 | ) | $ | (1.0 | ) | |||
Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.
Net income attributable to common stock from the regulated gas business increased $12.1 million in 2010 compared to 2009, primarily due to the absence in 2010 of the accrual of a customer rate credit of $10.4 million after-tax recorded in 2009.
Net income attributable to common stock from the regulated gas business decreased $8.2$14.7 million in 20072009 compared to 2006,2008, primarily due to the accrual of a customer rate credit of $10.4 million after-tax and increased operations and maintenance expenses of $7.7 million after-tax.
Net income from the regulated gas business increased $10.3 million in 2006 compared to 2005 mostly due to increased revenues less gas purchased for resale expenses of $19.8 million after-tax, which was primarily due to the increase in gas base rates that was approved by the Maryland PSC in December 2005. This increase was partially offset by higher operations and maintenance expenses of $7.9$2.2 million after-tax.
Gas Revenues
The changes in gas revenues in 20072010 and 20062009 compared to the respective prior year were caused by:
| 2007 | 2006 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Distribution volumes | $ | 19.3 | $ | (38.0 | ) | ||
Base rates | 0.2 | 33.4 | |||||
Gas revenue decoupling | (20.1 | ) | 28.4 | ||||
Gas cost adjustments | 74.4 | (112.3 | ) | ||||
Total change in gas revenues from gas system sales | 73.8 | (88.5 | ) | ||||
Off-system sales | (11.2 | ) | 13.9 | ||||
Other | 0.7 | 1.3 | |||||
Total change in gas revenues | $ | 63.3 | $ | (73.3 | ) | ||
| 2010 vs. 2009 | 2009 vs. 2008 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Distribution volumes | $ | 3.1 | $ | 1.5 | |||
Base rates | 1.6 | — | |||||
Residential customer rate credit | 17.4 | (17.4 | ) | ||||
Conservation surcharge | (1.0 | ) | 1.0 | ||||
Revenue decoupling | (3.1 | ) | (1.8 | ) | |||
Gas cost adjustments | (69.1 | ) | (130.0 | ) | |||
Total change in gas revenues from gas system sales | (51.1 | ) | (146.7 | ) | |||
Off-system sales | (1.2 | ) | (116.6 | ) | |||
Other | 3.4 | (2.4 | ) | ||||
Total change in gas revenues | $ | (48.9 | ) | $ | (265.7 | ) | |
52
Distribution Volumes
The percentage changes in our distribution volumes, by type of customer, in 20072010 and 20062009 compared to the respective prior year were:
| 2007 | 2006 | ||
---|---|---|---|---|
Residential | 17.7 | % | (17.0)% | |
Commercial | 14.6 | (13.3) | ||
Industrial | (11.3 | ) | 3.2 |
| 2010 | 2009 | |||||
---|---|---|---|---|---|---|---|
Residential | 1.1 | % | 0.9 | % | |||
Commercial | (3.2 | ) | (10.6 | ) | |||
Industrial | (5.2 | ) | 12.5 |
In 2007,2010, we distributed more gas to residential customers, mostly due to colder weather, increased usage per customer and an increased number of customers. We distributed moreless gas to commercial customers, mostly due to an increased number of customers and colder weather, partially offset by decreased usage per customer. We distributed less gas to industrial customers, mostly due to decreased usage per customer.
In 2006,2009, we distributed more gas to residential customers due to colder winter weather. We distributed less gas to residential and commercial customers compared to 2005 mostly due to milder weather and decreased usage per customer, partially offset by an increased number of customers.customers and colder weather. We distributed more gas to industrial customers mostly due to increased usage per customer.customer, partially offset by a decreased number of customers.
Base Rates
InOn December 2005,6, 2010, the Maryland PSC issued an abbreviated order authorizing BGE to increase gas distribution rates by $9.8 million for service rendered on or after December 4, 2010. This increase was based upon a 7.90% rate of return with a 9.56% return on equity and a 52% equity ratio. We discuss BGE's gas base rates in theRegulation—Maryland—Base Rates section.
Residential Customer Rate Credit
On October 30, 2009, the Maryland PSC issued an order grantingapproving Constellation Energy's transaction with EDF. Among other things, the order required Constellation Energy to fund a one-time distribution rate credit for BGE residential customers totaling $110.5 million, or approximately $100 per customer, for which BGE recorded a $35.6 million annual increaseliability in its gas base rates.November 2009. In December 2006, the Baltimore City Circuit Court upheld the rate order. However, certain parties have2009, BGE filed an appeala tariff with the Court of Special Appeals. We cannot provide assurance that the Maryland PSC's order will not be reversed in whole or in part or that certain issues will not be remanded to the Maryland PSC stating BGE would give residential customers a rate credit of exactly $100 per customer. As a result, BGE accrued an additional $1.9 million for reconsideration.a total fourth quarter 2009 accrual of $112.4 million. The portion of this total credit allocated to residential gas customers was $17.4 million pre-tax. This credit was accrued in the fourth quarter of 2009 and applied to BGE residential gas customer bills in the first quarter of 2010.
Conservation Surcharge
Beginning February 2009, the Maryland PSC approved a customer surcharge through which BGE recovers costs associated with certain programs designed to help BGE encourage customer conservation.
Gas Revenue Decoupling
The Maryland PSC allows us to record a monthly adjustment to our gas distribution revenues to eliminate the effect of abnormal weather and usage patterns per customer on our gas distribution volumes.volumes, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. This means our monthly gasBGE recognizes revenues at Maryland PSC-approved levels per customer, regardless of what actual distribution revenues are based on weather and usage that is considered "normal"volumes were for the month and, therefore,a billing period. Therefore, while these revenues are affected by customer growth, andthey will not be affected by actual weather or usage conditions. We then bill or credit impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.
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 inNote 1 to Consolidated Financial Statements. However, under the market-based rates mechanism approved by the Maryland PSC, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers.
Customers who do not purchase gas from BGE are not subject to the gas cost adjustment clauses because we are not selling gas to them. However, these customers are charged base rates to recover the costs BGE incurs to deliver their gas through our distribution system, and are included in the gas distribution volume revenues.
Gas cost adjustment revenues increaseddecreased in 2007both 2010 compared to 2006 because we sold more gas at higher prices.
Gas cost adjustment revenues decreased2009 and in 20062009 compared to 20052008 because we sold less gas at lower prices.
Off-System Gas Sales
Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Off-system gas sales, which occur after BGE has satisfied its 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 decreased in 20072010 compared to 20062009 because we sold less gas, at lower prices, partially offset by more gas sold.higher prices.
Revenues from off-system gas sales increaseddecreased in 20062009 compared to 20052008 because we sold moreless gas partially offset byat lower prices.
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 purchased for resale expenses increased $58.3costs decreased $62.4 million in 20072010 compared to 2006 because we purchased more gas, partially offset by lower prices.
Gas purchased for resale expenses2009 and decreased $106.0$244.6 million in 20062009 compared to 20052008 because we purchased less gas at lower prices.
53
Gas Operations and Maintenance Expenses
Regulated gas operationsoperation and maintenance expenses decreased $4.1 million during 2010 compared to 2009, primarily due to decreased uncollectible accounts receivable expense of $4.7 million.
Regulated gas operation and maintenance expenses increased $12.7$3.6 million in 2007during 2009 compared to 2006 mostly2008, primarily due to higher labor and benefit costs and the impact of inflation on other costs of $8.9 million and increased uncollectible accounts receivable expense of $1.2$2.0 million.
Regulated gas operationsHolding Company and maintenance expenses increased $13.0 million in 2006 compared to 2005 mostly due to higher labor and benefit costs and the impact of inflation on other costs.
Gas Taxes Other Than Income Taxes
Gas taxes other than income taxes increased $2.3 million in 2007 compared to 2006, primarily due to increased property taxes.
Other Nonregulated Businesses
Results
| 2007 | 2006 | 2005 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||
Revenues | $ | 249.8 | $ | 231.0 | $ | 207.0 | |||||
Operating expenses | (173.5 | ) | (173.1 | ) | (156.2 | ) | |||||
Merger-related costs | — | (0.5 | ) | (0.4 | ) | ||||||
Depreciation and amortization | (53.7 | ) | (37.7 | ) | (40.2 | ) | |||||
Taxes other than income taxes | (2.4 | ) | (2.0 | ) | (2.0 | ) | |||||
Income from Operations | $ | 20.2 | $ | 17.7 | $ | 8.2 | |||||
Income from continuing operations and before cumulative effects of changes in accounting principles (after-tax) | $ | 16.5 | $ | 11.3 | $ | 0.4 | |||||
Income from discontinued operations (after-tax) | — | 0.9 | 20.6 | ||||||||
Cumulative effects of changes in accounting principles (after-tax) | — | — | 0.2 | ||||||||
Net Income | $ | 16.5 | $ | 12.2 | $ | 21.2 | |||||
Other Items Included In Operations (after-tax) | |||||||||||
Merger-related costs | $ | — | $ | (0.2 | ) | $ | (0.2 | ) | |||
| 2010 | 2009 | 2008 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||
Revenues | $ | 1.2 | $ | 14.4 | $ | 16.1 | |||||
Operating expenses | 53.1 | 56.5 | 54.3 | ||||||||
Impairment losses and other costs | — | (26.6 | ) | — | |||||||
Workforce reduction costs | — | — | (0.2 | ) | |||||||
Depreciation and amortization | (48.9 | ) | (67.7 | ) | (62.3 | ) | |||||
Taxes other than income taxes | (3.7 | ) | (4.0 | ) | (3.0 | ) | |||||
Gain on divestitures | 0.4 | — | — | ||||||||
Income (Loss) from Operations | $ | 2.1 | $ | (27.4 | ) | $ | 4.9 | ||||
Net Loss | $ | (0.3 | ) | $ | (19.7 | ) | $ | (0.8 | ) | ||
Net Loss attributable to common stock | $ | (0.3 | ) | $ | (12.4 | ) | $ | (0.8 | ) | ||
| |||||||||||
Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits | $ | (4.8 | ) | $ | — | $ | — | ||||
Impairment losses and other costs | — | (11.5 | ) | — | |||||||
Workforce reduction costs | — | — | (0.1 | ) | |||||||
Total Other Items | $ | (4.8 | ) | $ | (11.5 | ) | $ | (0.1 | ) | ||
Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. Note 3 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.
Net income from our other nonregulated businesses increased $4.3loss attributable to common stock for 2010 decreased $12.1 million in 2007 compared to 2006,2009 primarily due to higher construction volume at ourthe absence in 2010 of an impairment of a district chilled water energy projects business.plant of $7.1 million after-tax and reduction for noncontrolling interest, and a write-off of an uncollectible advance to an affiliate of $4.3 million after-tax.
Net income from our other nonregulated businesses decreased $9.0loss attributable to common stock for 2009 increased $11.6 million in 2006 compared to 2005,2008 primarily due to increased impairment losses and other costs due to an impairment of a $19.7district chilled water energy plant of $7.1 million decrease in income from discontinued operations, partially offset byafter-tax and reduction for noncontrolling interest, a $10.7write-off of an uncollectible advance to an affiliate of $4.3 million increase in net income from our remaining other nonregulated businesses, including an increase in net income from our continued liquidationafter-tax, and higher depreciation and amortization expense of our real estate investments.$3.2 million after-tax as a result of increased property additions during 2008.
Consolidated Nonoperating Income and Expenses
Gains on Sale of CEP Equity
In November 2006, CEP, a limited liability company formed by Constellation Energy, completed an initial public offering of 5.2 million common units at $21 per unit. As a result of the initial public offering of CEP, we recognized a pre-tax gain of $28.7 million, or $17.9 million after recording deferred taxes on the gain. As a result of subsequent sales of equity by CEP, which reduced our relative ownership percentage, we recognized pre-tax gains totaling $63.3 million in 2007. We discuss the issuances of CEP equity in more detail inNote 2.
Other (Expenses) Income
Other income increasedIn 2010, we had other expenses of $76.7 million and, in 20072009, we had other expenses of $140.7 million. The $64.0 million decrease in 2010 compared to 2006,2009 is mostly due to the absence in 2010 of $62.6 million of other-than-temporary impairment charges related to nuclear decommissioning trust fund assets recorded in 2009.
In 2009, we had other expenses of $140.7 million and, in 2008, we had other expenses of $69.5 million. The $71.2 million increase in 2009 compared to 2008 is mostly due to higher credit facility costs, including amortization of amendment fees.
Other income at BGE decreased $4.6 million in 2010 compared to 2009 primarily due to decreases in interest and investment income due to a higher cash balance.of $3.3 million.
Total other Other income at BGE increaseddecreased $4.2 million in 20072009 compared to 2006,2008 primarily due to carrying charges related to rate stabilization deferralsdecreases in interest and investment income of "Electricity Purchased for Resale" expense. We discuss the rate stabilization deferrals in more detail in theRegulated Electric Business section.$4.2 million.
Fixed Charges
Fixed charges decreased $72.3 million in 20072010 compared to 2006,2009 mostly due to a lower average level of interest expense due to repayments of debt outstanding.made in 2009, partially offset by a $51.6 million loss recognized in February 2010 on the retirement of $486.5 million of our 7.00% Notes due April 1, 2012. We discuss this transaction in more detail inNote 9 to Consolidated Financial Statements.
Fixed charges at BGE increaseddecreased $9.0 million in 20072010 compared to 20062009 mostly due to a lower level of interest expense recognized on debt that was issued in October 2006 and the rate stabilization bonds issued in June 2007.
Fixed charges increased $18.5 million in 2006 compareddue to 2005 mostly because of a higher levelrepayments of debt outstanding, including commercial paper borrowings, and higher interest rates in 2006 compared to 2005.
Total fixed charges for BGE increased $9.1 million in 2006 compared to 2005 mostly because of a higher level of debt outstanding.2009.
Income Taxes
The differencesIncome tax expense decreased $3,652.5 million during 2010 compared to 2009 mostly due to a decrease in income before income taxes resulted fromas a combinationresult of the changesabsence in 2010 of the approximately $7.4 billion gain on sale of our 49.99% membership interest in CENG recorded in 2009 and the recognition of approximately $2.5 billion of impairment charges in 2010.
Income tax expense increased $3,065.1 million during 2009 compared to 2008 mostly due to higher income before income taxes due to the recognition of the $7.4 billion pre-tax gain on closing the transaction to sell a 49.99% membership interest in CENG. Additionally, there was lower income before income taxes for 2008, primarily due to approximately $1.2 billion of non-tax deductible merger termination and strategic alternative costs. However, in 2009, certain of these costs became tax deductible as a result of closing the EDF transaction and we recorded a tax benefit for these items in 2009.
BGE's income tax expense increased $33.3 million during 2010, mostly due to an increase in income andbefore income taxes.
BGE's income tax expense increased $43.1 million during 2009, mostly due to higher pre-tax income. For 2008, BGE had a lower effective tax rate as a result of a reduction in its 2008 taxable income due to the impact of certain provisions of the recognition2008 Maryland settlement agreement, which increased the relative impact of the favorable permanent tax creditsadjustments on theits effective tax rate. We include an analysis
54
Defined Benefit Plans Funded Status
At December 31, 2010, the changestotal projected benefit obligations of our qualified and nonqualified pension plans exceeded the fair value of our qualified pension plan assets by $218.0 million. At December 31, 2009, the total projected benefit obligations of our qualified and nonqualified pension plans exceeded the fair value of our qualified pension plan assets by $411.7 million. The $193.7 million improvement in the effective tax ratefunded status of our pension plans inNote 10. 2010 primarily reflects the following:
Our income taxes increased $77.3
In 2007, the State of Maryland increased its corporate income tax rate from 7% to 8.25%, effective January 1, 2008. The impact of adjusting all existing deferred income tax assets and liabilities for this change in the period of enactment was not material to us. However, this did impact BGE, as discussed below.
Income taxes at BGE decreased $6.2 million in 2007 compared to 2006, primarily due to lower pre-tax incomeThese increases were partially offset by normal growth in the projected benefit obligations of our qualified and nonqualified pension plans, including a 50 basis point decrease in the discount rate at December 31, 2010 compared to December 31, 2009.
At December 31, 2010, our accumulated post retirement benefit obligations totaled $334.9 million compared to $322.3 million at December 31, 2009. The $12.6 million increase in obligations for these unfunded plans primarily reflects the Maryland state tax rate.
Income taxes increased $187.1 million50 basis point decrease in 2006the discount rate at December 31, 2010 compared to 2005,December 31, 2009.
Our other postemployment benefit obligation increased $4.4 million from $50.6 million at December 31, 2009 to $55.0 million as of December 31, 2010, primarily due to a higher level of pre-tax income, including the gain on sale of gas-fired plants and the gain on the initial public offering of CEP, as well as a75 basis point decrease in synthetic fuel tax credits.the discount rate.
Total income taxes for BGE decreased $17.7 million We discuss our defined benefit plans in 2006 comparedfurther detail inNote 7 to 2005 mostly due to lower pre-tax income.Consolidated Financial Statements.
Financial ConditionTable of Contents
Cash Flows
The following table summarizes our 20072010 cash flows by business segment, as well as our consolidated cash flows for 2007, 2006,2010, 2009, and 2005.2008.
| 2007 Segment Cash Flows | Consolidated Cash Flows | ||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Merchant | Regulated | Other | 2007 | 2006 | 2005 | ||||||||||||||
| (In millions) | |||||||||||||||||||
Operating Activities | ||||||||||||||||||||
Net income | $ | 678.3 | $ | 126.7 | $ | 16.5 | $ | 821.5 | $ | 936.4 | $ | 623.1 | ||||||||
Non-cash adjustments to net income | 428.2 | 93.4 | 13.0 | 534.6 | 195.4 | 746.0 | ||||||||||||||
Changes in working capital | (260.9 | ) | (120.9 | ) | 8.6 | (373.2 | ) | (677.7 | ) | (747.6 | ) | |||||||||
Defined benefit obligations* | — | — | — | (53.6 | ) | 40.5 | 3.4 | |||||||||||||
Other | (18.4 | ) | (45.8 | ) | 62.7 | (1.5 | ) | 30.7 | 2.3 | |||||||||||
Net cash provided by operating activities | 827.2 | 53.4 | 100.8 | 927.8 | 525.3 | 627.2 | ||||||||||||||
Investing Activities | ||||||||||||||||||||
Investments in property, plant and equipment | (837.0 | ) | (375.8 | ) | (82.9 | ) | (1,295.7 | ) | (962.9 | ) | (760.0 | ) | ||||||||
Asset acquisitions and business combinations, net of cash acquired | (347.5 | ) | — | — | (347.5 | ) | (137.6 | ) | (237.2 | ) | ||||||||||
Investment in nuclear decommissioning trust fund securities | (659.5 | ) | — | — | (659.5 | ) | (492.5 | ) | (370.8 | ) | ||||||||||
Proceeds from nuclear decommissioning trust fund securities | 650.7 | — | — | 650.7 | 483.7 | 353.2 | ||||||||||||||
Net proceeds from sale of gas-fired plants and discontinued operations | — | — | — | — | 1,630.7 | 289.4 | ||||||||||||||
Issuances of loans receivable | (19.0 | ) | — | — | (19.0 | ) | (65.4 | ) | (82.8 | ) | ||||||||||
Sale of investments and other assets | 3.9 | 0.8 | 9.2 | 13.9 | 43.9 | 14.4 | ||||||||||||||
Contract and portfolio acquisitions | (474.2 | ) | — | — | (474.2 | ) | (2.3 | ) | (336.2 | ) | ||||||||||
Decrease (increase) in restricted funds | (2.9 | ) | (42.3 | ) | (64.7 | ) | (109.9 | ) | 7.7 | (4.0 | ) | |||||||||
Other investments | (44.1 | ) | — | (1.2 | ) | (45.3 | ) | 54.8 | (40.0 | ) | ||||||||||
Net cash (used in) provided by investing activities | (1,729.6 | ) | (417.3 | ) | (139.6 | ) | (2,286.5 | ) | 560.1 | (1,174.0 | ) | |||||||||
Cash flows from operating activities less cash flows from investing activities | $ | (902.4 | ) | $ | (363.9 | ) | $ | (38.8 | ) | (1,358.7 | ) | 1,085.4 | (546.8 | ) | ||||||
Financing Activities* | ||||||||||||||||||||
Net (repayment) issuance of debt | (33.1 | ) | 242.2 | (339.6 | ) | |||||||||||||||
Proceeds from issuance of common stock | 65.1 | 84.4 | 96.9 | |||||||||||||||||
Common stock dividends paid | (306.0 | ) | (264.0 | ) | (228.8 | ) | ||||||||||||||
Reacquisition of common stock | (409.5 | ) | — | — | ||||||||||||||||
Proceeds from initial public offering of CEP | — | 101.3 | — | |||||||||||||||||
Proceeds from contract and portfolio acquisitions | 847.8 | 221.3 | 1,026.9 | |||||||||||||||||
Other | 1.2 | 5.5 | 98.1 | |||||||||||||||||
Net cash provided by financing activities | 165.5 | 390.7 | 653.5 | |||||||||||||||||
Net (decrease) increase in cash and cash equivalents | $ | (1,193.2 | ) | $ | 1,476.1 | $ | 106.7 | |||||||||||||
| 2010 Segment Cash Flows | Consolidated Cash Flows | ||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Generation | NewEnergy | Regulated | Eliminations, Holding Company and Other | 2010 | 2009 | 2008 | |||||||||||||||||
| (In millions) | |||||||||||||||||||||||
Operating Activities | ||||||||||||||||||||||||
Net (loss) income | $ | (1,255.3 | ) | $ | 176.2 | $ | 147.6 | $ | (0.3 | ) | $ | (931.8 | ) | $ | 4,503.4 | $ | (1,318.4 | ) | ||||||
Non-cash merger termination and strategic alternatives costs | — | — | — | — | — | 128.2 | 541.8 | |||||||||||||||||
Derivative contracts classified as financing activities (1) | — | 186.0 | — | — | 186.0 | 1,138.3 | (107.2 | ) | ||||||||||||||||
Gain on sale of 49.99% membership interest in CENG | — | — | — | — | — | (7,445.6 | ) | — | ||||||||||||||||
(Gain) loss on divestitures | (242.9 | ) | (2.5 | ) | — | (0.4 | ) | (245.8 | ) | 468.8 | (38.1 | ) | ||||||||||||
Accrual of BGE residential customer credit | — | — | — | — | — | 112.4 | — | |||||||||||||||||
Impairment losses and other costs | 2,476.7 | 0.1 | — | — | 2,476.8 | 124.7 | 741.8 | |||||||||||||||||
Other non-cash adjustments to net (loss) income | (506.9 | ) | (11.4 | ) | 620.9 | 53.6 | 156.2 | 2,761.0 | 602.9 | |||||||||||||||
Changes in working capital | ||||||||||||||||||||||||
Derivative assets and liabilities, excluding collateral | (1.9 | ) | 452.1 | (0.3 | ) | — | 449.9 | 425.3 | (757.9 | ) | ||||||||||||||
Net collateral and margin | — | 41.3 | 2.9 | — | 44.2 | 1,522.8 | (960.3 | ) | ||||||||||||||||
Accrued taxes | (1,123.2 | ) | (58.6 | ) | (60.8 | ) | 432.7 | (809.9 | ) | 102.1 | 79.7 | |||||||||||||
Other changes | (241.8 | ) | 281.1 | (199.0 | ) | (431.8 | ) | (591.5 | ) | 664.9 | 13.9 | |||||||||||||
Defined benefit obligations (2) | — | — | — | — | (224.5 | ) | (287.2 | ) | (20.8 | ) | ||||||||||||||
Other | 71.9 | (81.6 | ) | (31.9 | ) | 43.3 | 1.7 | 171.7 | (38.5 | ) | ||||||||||||||
Net cash (used in) provided by operating activities | (823.4 | ) | 982.7 | 479.4 | 97.1 | 511.3 | 4,390.8 | (1,261.1 | ) | |||||||||||||||
Investing Activities | ||||||||||||||||||||||||
Investments in property, plant and equipment | (331.9 | ) | (141.6 | ) | (496.8 | ) | (25.3 | ) | (995.6 | ) | (1,529.7 | ) | (1,934.1 | ) | ||||||||||
Asset acquisitions and business combinations, net of cash acquired | (372.9 | ) | (72.9 | ) | — | — | (445.8 | ) | (41.1 | ) | (315.3 | ) | ||||||||||||
Change in cash pool (3) | (2,321.1 | ) | 136.7 | 314.7 | 1,869.7 | — | — | — | ||||||||||||||||
Contributions to nuclear decommissioning trust funds | — | — | — | — | — | (18.7 | ) | (18.7 | ) | |||||||||||||||
Investments in joint ventures | — | — | — | — | — | (201.6 | ) | — | ||||||||||||||||
Proceeds from sale of 49.99% membership interest in CENG | — | — | — | — | — | 3,528.7 | — | |||||||||||||||||
Proceeds from sale of investments and other assets | 212.5 | 9.6 | — | 21.9 | 244.0 | 88.3 | 446.3 | |||||||||||||||||
Proceeds from investment tax credits and grants related to renewable energy investments | 39.0 | 17.5 | — | — | 56.5 | — | — | |||||||||||||||||
Contract and portfolio acquisitions | (1.0 | ) | (207.3 | ) | — | — | (208.3 | ) | (2,153.7 | ) | — | |||||||||||||
(Increase) decrease in restricted funds | (50.0 | ) | (5.8 | ) | (5.1 | ) | 0.6 | (60.3 | ) | 1,003.3 | (942.8 | ) | ||||||||||||
Other investments | (39.6 | ) | 4.1 | — | (0.2 | ) | (35.7 | ) | 0.1 | 21.7 | ||||||||||||||
Net cash (used in) provided by investing activities | (2,865.0 | ) | (259.7 | ) | (187.2 | ) | 1,866.7 | (1,445.2 | ) | 675.6 | (2,742.9 | ) | ||||||||||||
Cash flows from operating activities plus cash flows from investing activities | $ | (3,688.4 | ) | $ | 723.0 | $ | 292.2 | $ | 1,963.8 | (933.9 | ) | 5,066.4 | (4,004.0 | ) | ||||||||||
Financing Activities (2) | ||||||||||||||||||||||||
Net (repayment) issuance of debt | (128.1 | ) | (2,660.4 | ) | 3,447.7 | |||||||||||||||||||
Debt and credit facility costs | (32.8 | ) | (98.4 | ) | (104.8 | ) | ||||||||||||||||||
Proceeds from issuance of common stock | 14.0 | 33.9 | 17.6 | |||||||||||||||||||||
Common stock dividends paid | (183.3 | ) | (228.0 | ) | (336.3 | ) | ||||||||||||||||||
BGE preference stock dividends paid | (13.2 | ) | (13.2 | ) | (13.2 | ) | ||||||||||||||||||
Reacquisition of common stock | — | — | (16.2 | ) | ||||||||||||||||||||
Proceeds from contract and portfolio acquisitions | 52.2 | 2,263.1 | — | |||||||||||||||||||||
Derivative contracts classified as financing activities (1) | (186.0 | ) | (1,138.3 | ) | 107.2 | |||||||||||||||||||
Other | (0.4 | ) | 12.7 | 8.3 | ||||||||||||||||||||
Net cash (used in) provided by financing activities | (477.6 | ) | (1,828.6 | ) | 3,110.3 | |||||||||||||||||||
Net (decrease) increase in cash and cash equivalents | $ | (1,411.5 | ) | $ | 3,237.8 | $ | (893.7 | ) | ||||||||||||||||
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Certain prior-year amounts have been reclassified to conform with the current year's presentation.Table of Contents
Cash Flows from Operating Activities
CashIn 2010, cash provided by operating activities was $927.8 millionof $0.5 billion reflected $0.5 billion from our regulated business, $0.2 billion from our competitive businesses, and $0.1 billion from holding company and other businesses. These were partially offset by $0.3 billion of contributions to our qualified pension plan. The $0.2 billion of operating cash flows from our competitive businesses included $0.8 billion of federal income tax payments on the 2009 EDF transaction.
The $3.9 billion decrease in 2007operating cash flows for 2010 compared to $525.3 million in 2006. This $402.5 million increase was2009 is primarily due to an increase in non-cash adjustments to netto:
Non-cash adjustments to net income increased $339.2 million in 2007 compared to 2006,taxes paid,
Changes in working capital had a negative impact of $373.2 million on cash flows from operations in 2007 compared to a negative impact of $677.7 million in 2006. The improvement in working capital of $304.5 million was due to a $200.8 million change in working capital primarily related to higher fuel stock purchases in 20062010 as compared to 2007.2009 as follows:
| December 31, | ||||||
---|---|---|---|---|---|---|---|
| 2010 | 2009 | |||||
| (In millions) | ||||||
Net collateral and margin held (posted), beginning of year | $ | 77.2 | $ | (1,445.6 | ) | ||
Return of collateral held associated with nonderivative contracts | (16.1 | ) | (17.0 | ) | |||
Net (additional) return of collateral posted associated with nonderivative contracts | (7.4 | ) | 336.3 | ||||
Return of initial and variation margin posted on exchange-traded transactions recorded in accounts receivable | 6.9 | 924.8 | |||||
Return of fair value net cash collateral posted (netted against derivative assets/liabilities)* | 60.8 | 278.7 | |||||
Change in net collateral and margin posted | 44.2 | 1,522.8 | |||||
Net collateral and margin held, end of year | $ | 121.4 | $ | 77.2 | |||
Cash provided by operating activities was $525.3 million$4.4 billion in 20062009 compared to $627.2 millioncash used in 2005.operating activities of $1.3 billion in 2008. This $101.9 million decrease$5.7 billion increase in cash flows was primarily due to:
Non-cash adjustments toliabilities. Changes in derivative assets and liabilities are driven by fluctuations in commodity prices and the realization of contracts at settlement within our NewEnergy business.
the deferred recovery of electricity purchased for resale under the BGE rate stabilization plan. We discuss the rate stabilization plan in more detail in theItem 1.—Business—Baltimore Gas and Electric Company—Electric Business—Electric Competition section andNote 1. In addition, our gains on the sale of gas-fired plants and discontinued operations increased $177.6 million in 2006 compared to 2005. We discuss this in more detail inNote 2.
Changes in working capital had a negative impact of $677.7 million on cash flow from operations in 2006 compared to a negative impact of $747.6 million in 2005. The negative impact of $677.7 million related to working capital was primarily due to the commodity price environment and increased risk management and trading activities that resulted in an increase of approximately $630 million in net cash collateral requirements, primarily for requirements on exchange-settled transactions. This increase in cash collateral requirements was accompanied by a decrease in our letters of credit requirements.
Cash Flows from Investing Activities
Cash used in investing activities was $2,286.5 million$1.4 billion in 20072010 compared to cash provided by investing activities of $560.1 million$0.7 billion in 2006.2009. The $2,846.6 million$2.1 billion increase in cash used in 20072010 compared to 20062009 was primarily due to:
These increases were offset by:
Cash provided by investing activities was $560.1 million$0.7 billion in 20062009 compared to cash used of $2.7 billion in investing activities $1,174.0 million2008. The $3.4 billion increase in 2005. The $1,734.1 million favorable changecash provided in 20062009 compared to 20052008 was primarily due to:
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in 2009 for the repayment of the $1 billion of 14% Senior Notes to MidAmerican in January 2009, and
This increase was partially offset by:
Cash Flows from Financing Activities
Cash provided byused in financing activities was $165.5 million$0.5 billion in 20072010 compared to $390.7 millioncash used in 2006.financing activity of $1.8 billion in 2009. The decrease in cash used for financing activities of $225.2 million$1.3 billion was primarily due to:
This decrease of $101.3 million in proceeds from the initial public offering of CEP in 2006. This was partially offset by an increase in gross$2.2 billion of lower proceeds from contract and portfolio acquisitions related to the structure of $626.5 million, which we discuss below.the divestiture of the majority of our international commodities operation in March 2009.
In October 2007, our board Cash used in financing activities was $1.8 billion in 2009 compared to cash provided of directors approved a common share repurchase program$3.1 billion in 2008. The increase in cash used for upfinancing activities of $4.9 billion was primarily due to:
.
Cash provided by This increase in cash used for financing activities was $390.7 million in 2006 compared to $653.5 million in 2005. The decrease of $262.8 million in cash provided in 2006 compared to 2005 was primarily due to a decrease in proceeds from acquired contracts of $805.6 million, a decrease in other financing activities of $92.6 million, and a $35.2 million increase in our dividends paid in 2006 compared to 2005. We discuss the proceeds from acquired contracts below. These decreases were partially offset by $2.3 billion of cash provided from contract and portfolio acquisitions as a net increasecomponent of our strategic divestitures. As a result of the structure of the divestitures of a majority of our international commodities, Houston-based gas trading and other trading operations, we are required to present financing cash inflows for out-of-the-money contracts on a gross basis separate from investing cash outflows for in-the-money contracts executed simultaneously. We discuss our divestitures in cash relatedmore detail inNote 2 to changesConsolidated Financial Statements. There was no such activity in short-term borrowings and long-term debt of $581.8 million and $101.3 million in proceeds from the initial public offering of CEP.2008.
Contract and Portfolio Acquisitions
During 2007, 2006,2010 and 2005,2009, our merchant energyNewEnergy business acquired several pre-existing energy purchase and sale agreements, which generated significant cash flows at the inception of the contracts. These agreements had contract prices that differed from market prices at closing, which resulted in cash payments to or from the counterparty at the acquisition of the contract. We paid net cash of $156.1 million in 2010 to acquire various contracts. During
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2009, we received net cash of $373.6$109.4 million due to the execution of total return swaps to assist in 2007, $219.0 million in 2006,the execution of our divestitures of our international commodities and $690.7 million in 2005 for various contract and portfolio acquisitions.Houston-based gas trading operations. We reflect the underlying contracts on a gross basis as assets or liabilities in our Consolidated Balance Sheets depending on whether they were at above- or below-market prices at closing; therefore, we have also reflected them on a gross basis in cash flows from investing and financing activities in our Consolidated Statements of Cash Flows as follows:
Year ended December 31, | 2007 | 2006 | 2005 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | | ||||||||
Financing activities—proceeds from contract and portfolio acquisitions | $ | 847.8 | $ | 221.3 | $ | 1,026.9 | ||||
Investing activities—contract and portfolio acquisitions | (474.2 | ) | (2.3 | ) | (336.2 | ) | ||||
Cash flows from contract and portfolio acquisitions | $ | 373.6 | $ | 219.0 | $ | 690.7 | ||||
Year ended December 31, | 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Financing activities—proceeds from contract and portfolio acquisitions | $ | 52.2 | $ | 2,263.1 | $ | — | ||||
Investing activities—contract and portfolio acquisitions | (208.3 | ) | (2,153.7 | ) | — | |||||
Cash flows from contract and portfolio acquisitions | $ | (156.1 | ) | $ | 109.4 | $ | — | |||
We record the proceeds we receive to acquire energy purchase and sale agreements as a financing cash inflow because it constitutes a prepayment for a portion of the market price of energy, which we will buy or sell over the term of the agreements and does not represent a cash inflow from current period operating activities. For those acquired contracts that are derivatives, we record the ongoing cash flows related to the
contract with the counterparties as financing cash inflows in accordance with SFAS No. 149.inflows. For those acquired contracts that are not derivatives, we record the ongoing cash flows related to the contract as operating cash flows.
We discuss certain of these contract and portfolio acquisitions in more detail inNote 5.2 to Consolidated Financial Statements.
Cash Flow Impacts—CENG Joint Venture
Prior to November 6, 2009, we recorded 100% of the revenues, expenses, and cash flows from CENG and the nuclear plants it owns because we wholly owned this entity. On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG to EDF, and we deconsolidated CENG. Accordingly, for periods after November 6, 2009, we ceased recording CENG's cash flows and began to record cash flows from our PPA and other transactions with CENG. We will record any future cash flows from distributions received from CENG based on our 50.01% ownership interest, and we may be required to make capital contributions to help fund CENG's capital program.
As a result of deconsolidation, our Generation business cash flows differed from historical cash flows primarily due to the following factors:
In addition, we entered into a power services agency agreement (PSA) and an administrative service agreement (ASA) with CENG. The PSA is a five-year agreement under which we will provide scheduling, asset management and billing services to CENG and will recognize average annual revenue of approximately $16 million.
The ASA is a one year agreement that is renewable annually under which we provided administrative support services to CENG for a fee of approximately $66 million for 2010. The level of fees for administrative support services will be subject to change in future years based on the level of services provided. The charges under these agreements are intended to represent the actual cost of the services provided to CENG from us. In October 2010, we entered into a comprehensive agreement with EDF. Among other provisions of the agreement, the ASA was extended through 2017. We discuss the comprehensive agreement with EDF in more detail inNote 4 to Consolidated Financial Statements.
Impact of Security Ratings on Our Liquidity
We rely on access to capital markets as a source of liquidity for capital requirements not satisfied by operating cash flows. Independent credit-ratingcredit rating agencies rate Constellation Energy's and BGE's fixed-income securities. The ratings indicate the agencies' assessment of each company's ability to pay interest, distributions, dividends, and principal on these securities. These ratings affect how much it will cost each companyus to sell thesesecurities and, in certain cases, our ability to access capital markets to sell securities. Generally, the better the rating, the lower the cost of the securities to each companyus when theywe sell them.
The factors that credit rating agencies consider in establishing Constellation Energy's and BGE's credit ratings include, but are not limited to, cash flows, liquidity, business risk profile, stock price volatility, political, legislative, and regulatory risk, interest charges relative to operating cash flows and the amountlevel of debt as a componentrelative to total capitalization.
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Table of total capitalization.Contents
At the date of this report, ourthe senior unsecured debt and commercial paper credit ratings for Constellation Energy and BGE were as follows:
| Standard & Rating Group | Moody's Investors Service | Ratings | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Constellation Energy | ||||||||||||||
Senior Unsecured Debt | ||||||||||||||
Commercial Paper | ||||||||||||||
BGE | ||||||||||||||
Senior Unsecured Debt | BBB+ | Baa2 | BBB+ | |||||||||||
Commercial Paper | A-2 | P-2 | F2 | |||||||||||
* Bonds issued by RSB BondCo LLC, a subsidiary of BGE
In February 2008, Fitch Ratings placed both The Constellation Energy and BGE ratings in the above table reflect stable outlooks by all the credit rating agencies, except that Moody's rating of BGE reflects a positive outlook. If any of these credit ratings were to be downgraded, especially below investment grade, our ability to raise capital on Ratings Watch Negative due tofavorable terms, including in the current politicalcommercial paper markets, if available, could be hindered, and regulatory environmentour borrowing costs would increase. Additionally, the business prospects of our wholesale and retail competitive supply businesses, which in Maryland. Additionally, in February 2008, Standard & Poors Rating Group affirmedmany cases rely on the ratingscreditworthiness of both Constellation Energy, and BGE. They kept the outlook on the ratings as negative duewould be negatively impacted. In this regard, we have certain agreements that contain provisions that would require us to the current political and regulatory environment in Maryland.post additional collateral upon a credit rating downgrade.
We discuss the potential effect of a ratings downgrade in theLiquidity ProvisionsCollateral section.
Available Sources We discuss the potential effect of Fundinga ratings downgrade on our ability to maintain ongoing compliance with financial ratios in our existing credit agreements inNote 8 to Consolidated Financial Statements.
We continuously monitor our liquidity requirements and believe that our credit facilities and access As a condition to the capital marketsOctober 2009 Maryland PSC order approving our transaction with EDF, Constellation Energy and BGE were required to implement "ring fencing" measures to provide sufficientbankruptcy protection and credit rating separation of BGE from Constellation Energy. We completed the implementation of these measures in February 2010.
We remain committed to maintaining a stable investment grade credit profile and to meeting our liquidity to meet our business requirements. We discuss our available sources of funding in more detail below.
Constellation EnergyAvailable Sources of Funding
In addition to cash generated from operations, we rely upon access to capital for our cash balance, we have acapital expenditure programs and for the liquidity required to operate and support our commercial paper program under which we can issue short-term notes tobusinesses. Our liquidity requirements are funded by credit facilities and cash. We fund our subsidiaries. At December 31, 2007, we had approximately $3.85 billion of credit under a five-year facility that expires in July 2012. In December 2007, we entered into an additional one-year credit facility totaling $250.0 million. This facility amendedshort-term working capital needs with existing cash and restated a $200.0 million facility that expired in December 2007.
These revolvingwith our credit facilities, allowmany of which support direct cash borrowings and the issuance of commercial paper. We also use our credit facilities to support the issuance of letters of credit, upprimarily for our NewEnergy business.
The primary drivers of our use of liquidity have been our capital expenditure requirements and collateral requirements associated with hedging our generating assets and hedging our NewEnergy business in both power and gas. Significant changes in the prices of commodities, depending on hedging strategies we have employed, could require us to $4.1 billion. At December 31, 2007,post additional letters of credit, that totaled $1.8and thereby reduce the overall amount available under our credit facilities or to post additional cash, thereby reducing our available cash balance. Additional regulation of the derivatives markets could also require us to post additional cash collateral. We discuss the financial reform legislation enacted in 2010 in more detail in theFederal Regulation section.
We discuss our, and BGE's, credit facilities in detail inNote 8 to Consolidated Financial Statements.
Net Available Liquidity
Constellation Energy's (excluding BGE) and BGE's net available liquidity at December 31, 2010 was $3.3 billion were issued under alland $0.6 billion, respectively. We discuss net available liquidity in more detail in theNote 8 to Consolidated Financial Statements.
Collateral
Constellation Energy's collateral requirements generally arise from its NewEnergy business as a result of its participation in certain organized markets, such as Independent System Operators (ISOs) or financial exchanges, as well as from our margining on over-the-counter (OTC) contracts.
To support NewEnergy's wholesale and retail power obligations and our limited trading activities, Constellation Energy posts collateral to ISOs. Forward hedging of our facilities, which resultsGeneration and NewEnergy businesses creates the need to transact with exchanges such as New York Mercantile Exchange and Intercontinental Exchange. We post initial margin based on exchange rules, as well as variation margin related to the change in approximately $2.3 billionvalue of unused credit facilities. Additionally,the net open position with the exchange.
In addition to the collateral posted to ISOs and exchanges, we post collateral with certain OTC counterparties. These collateral amounts may be fixed or may vary with price levels.
There are certain inherent asymmetries relating to the use of collateral that create liquidity requirements for our Generation and NewEnergy businesses. These asymmetries arise from our actions to be economically hedged, as well as market conditions or conventions for conducting business that result in January 2008,some transactions being collateralized while others are not, including:
We enter into these facilities to ensure adequate liquidityour gas trading operation, we have reduced our collateral requirements to support our operations. Currently,retail gas operation. We discuss this gas supply agreement in more detail in
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lowering our collateral requirements. During 2010, we acquired generation assets in Texas, and in January 2011, we acquired generation assets in Massachusetts, which will assist with reducing our collateral requirements.
Finally, collateral types may asymmetrically impact our liquidity. In margining with OTC counterparties, we may post letter of credit primarily(LC) collateral for an out-of-the money counterparty. However, we may receive LC collateral when we are in-the-money with a counterparty. Posting LCs reduces our merchant energy business.liquidity while the receipt of LC collateral does not increase our liquidity.
We expectCustomers of our NewEnergy business rely on the creditworthiness of Constellation Energy. In this regard, we have certain agreements that contain provisions that would require us to fund future acquisitions with an overall goalpost additional collateral upon a credit rating downgrade in the senior unsecured debt of maintaining a strongConstellation Energy. Based on contractual provisions at December 31, 2010, we estimate that if Constellation Energy's senior unsecured debt were downgraded to one level below the investment grade threshold we would have the following additional collateral obligations:
Credit Ratings Downgraded to (1) | Level Below Current Rating | Additional Obligations (2) | |||||
---|---|---|---|---|---|---|---|
| (In billions) | ||||||
Below investment grade | 1 | $ | 1.0 | ||||
Based on market conditions and contractual obligations at the time of a downgrade, we could be required to post additional collateral in an amount that could exceed the obligation amounts specified above, which could be material. We discuss our credit facilities in theAvailable Sources of Funding section. In addition, rulemaking under the Dodd-Frank Act could impose additional collateral requirements. We discuss this rulemaking in theFederal Regulation section.
BGE
BGE currently maintains a $400.0 million five-year revolving credit facility expiring in 2011. BGE can borrow directly from the banks or use the facilities to allow commercial paper to be issued. As of December 31, 2007, BGE had $0.7 million in letters of credit issued, which results in $399.3 million in unused credit facilities.
Capital Resources
Our actual consolidated capital requirements for the years 20052008 through 2007,2010, along with the estimated annual amount for 2008,2011, are shown in the table on the next page.following table.
We will continue to have cash requirements for:
Capital requirements for 20082011 and 20092012 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 on the next pagebelow because of a number of factors including:
Our estimates are also subject to additional factors.
Please see theForward Looking Statements andItem 1A. Risk Factors sections.
| 2005 | 2006 | 2007 | 2008 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||||
Nonregulated Capital Requirements: | ||||||||||||||
Merchant energy (excludes acquisitions) | ||||||||||||||
Generation plants | $ | 182 | $ | 235 | $ | 201 | $ | 450 | ||||||
Environmental controls | 1 | 17 | 157 | 550 | ||||||||||
Portfolio acquisitions/investments | 231 | 227 | 512 | 565 | ||||||||||
Technology/other | 165 | 152 | 160 | 135 | ||||||||||
Nuclear fuel | 130 | 137 | 148 | 200 | ||||||||||
Total merchant energy capital requirements | 709 | 768 | 1,178 | 1,900 | ||||||||||
Other nonregulated capital requirements | 32 | 21 | 85 | 80 | ||||||||||
Total nonregulated capital requirements | 741 | 789 | 1,263 | 1,980 | ||||||||||
Regulated Capital Requirements: | ||||||||||||||
Regulated electric | 241 | 297 | 340 | 415 | ||||||||||
Regulated gas | 50 | 63 | 62 | 80 | ||||||||||
Total regulated capital requirements | 291 | 360 | 402 | 495 | ||||||||||
Total capital requirements | $ | 1,032 | $ | 1,149 | $ | 1,665 | $ | 2,475 | ||||||
| 2008 | 2009 | 2010 | 2011 (Estimate) | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In billions) | ||||||||||||||
Generation and Other Capital Requirements: | |||||||||||||||
Major Environmental | $ | 0.5 | $ | 0.3 | $ | 0.1 | $ | 0.1 | |||||||
Maintenance | 0.5 | 0.6 | 0.1 | 0.1 | |||||||||||
Growth | 0.4 | 0.2 | 0.1 | — | |||||||||||
Total Generation and Other Capital Requirements | 1.4 | 1.1 | 0.3 | 0.2 | |||||||||||
NewEnergy Capital Requirements: | |||||||||||||||
Maintenance | 0.1 | — | — | — | |||||||||||
Growth | 0.2 | 0.1 | 0.1 | 0.2 | |||||||||||
Total NewEnergy Capital Requirements | 0.3 | 0.1 | 0.1 | 0.2 | |||||||||||
Regulated Capital Requirements: | |||||||||||||||
Electric / Gas Distribution | 0.4 | 0.3 | 0.4 | 0.4 | |||||||||||
Electric Transmission | 0.1 | — | 0.1 | 0.1 | |||||||||||
Smart Energy SaversSM Initiatives | — | 0.1 | 0.1 | 0.1 | |||||||||||
Total Regulated Capital Requirements | 0.5 | 0.4 | 0.6 | 0.6 | |||||||||||
Total Capital Requirements | $ | 2.2 | $ | 1.6 | $ | 1.0 | $ | 1.0 | |||||||
Eligible capital projects are shown net of anticipated investment tax credits or grants.
As of the date of this report, we have not completedestimate our 2009 capital budgeting process, but expect our 20092012 capital requirements towill be approximately $2.0$1.0 billion.
Our environmental controls capital requirements are affected by new rules or regulations that require modifications to our facilities. We are in the process of installing additional air emission control equipment at certain of our coal-fired generating facilities in Maryland and plan to install additional air emission control equipment at co-owned coal-fired generating facilities in Pennsylvania. We estimate another $400 million of capital spending from 2009-2012 for environmental controls. We discuss environmental matters in more detail inItem 1. Business—Environmental Matters.
Capital Requirements
Merchant Energy BusinessGeneration and NewEnergy Businesses
Our merchant energy business'Generation and NewEnergy businesses' capital requirements consist of its continuing requirements, including expenditures for:
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In addition, in January 2011, we completed the acquisition of Boston Generating's 2,950 MW fleet of generating plants for approximately $1.1 billion, subject to a working capital adjustment. We funded this acquisition through a mix of available cash and debt.
In December 2009, we were selected by the State of Maryland to construct, own, operate and maintain a 17 MW solar photovoltaic power installation in Emmitsburg, Maryland. We expect this project to cost us approximately $60 million and be completed by December 2012. Renewable electricity produced by the system will be purchased by the State of Maryland at the site of Mount St. Mary's University under a 20-year solar power purchase agreement.
In 2009, we acquired the 70 MW Criterion wind project to be constructed in Garrett County, Maryland. We closed this transaction in the first quarter of 2010 and we placed it in service in the fourth quarter of 2010.
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 and support demand response and conservation initiatives. Further, BGE continues to invest in transmission projects that earn a FERC authorized rate of return.
In August 2010, the Maryland PSC approved a comprehensive smart grid initiative for BGE which includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of approximately $480 million. In 2009, the United States Department of Energy (DOE) selected BGE as a recipient of $200 million in federal funding for our smart grid and other related initiatives. This grant allows BGE to be reimbursed for smart grid and other expenditures up to $200 million, substantially reducing the total cost of these initiatives.
Funding for Capital Requirements
Merchant Energy BusinessGeneration and NewEnergy Businesses
Funding forWe expect to fund the capital requirements of our merchant energy business is expected fromGeneration and NewEnergy businesses with internally generated funds. Ifcash and other available sources. To the extent that internally generated funds arecash is not sufficient to meet fundingthose requirements, we have available sourceswould seek additional funding from commercial paper issuances, issuances of long-term debtthe money markets, capital markets and equity, leases,lease markets, subject to credit conditions and other financing activities.market liquidity, and, if necessary, from draw downs on credit facilities.
The projects that our merchant energy business developsGeneration and NewEnergy businesses develop typically require substantial capital investment. Many of the qualifying facilities and independent power projects that we have an interest in as well as our upstream properties are financed primarily with non-recourse debt that is repaid from the project's cash flows. This debt is collateralized by interests in the physical assets, major project contracts and agreements, cash accounts and, in some cases, the ownership interest in that project.
We expect to fund acquisitions with a mixture of debt and equity with an overall goal of maintaining a strong investment grade credit profile.
Regulated Electric and Gas
Funding forWe expect to fund capital expenditures associated with our regulated electric and gas capital expenditures is expected frombusinesses through a combination of internally and externally generated cash. To the extent that internally generated funds. If internally generated funds arecash is not sufficient to meet fundingthose requirements, we have available sourceswould seek additional funding from commercial paper issuances, available capacity under credit facilities, the issuance ofshort-term and long-term debt,capital markets (including trust preferred securities or preference stock, and/orstock), subject to credit conditions and market liquidity, and, if necessary, from draw downs on credit facilities. BGE may also receive equity contributions from time to time equity contributions from Constellation Energy. BGE also participates in a cash pool administered by Constellation Energy as discussed inNote 16.
Other Nonregulated Businesses
Funding for our other nonregulated businesses is expected from internally generated funds. If internally generated funds are not sufficient to meet funding requirements, we have available sources from commercial paper issuances, issuances of long-term debt of Constellation Energy, sales of securities and assets, and/or from time to time equity contributions from Constellation Energy.
Our ability to sell or liquidate securities and assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made.
Contractual Payment Obligations and Committed Amounts
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 energyGeneration and NewEnergy business activities, and purchases of fuel and transportation to satisfy the fuel requirements of our power generating facilities.
We detail our contractual payment obligations as of December 31, 20072010 in the following table:
| Payments | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2008 | 2009- 2010 | 2011- 2012 | Thereafter | Total | |||||||||||||
| (In millions) | |||||||||||||||||
Contractual Payment Obligations | ||||||||||||||||||
Long-term debt:1 | ||||||||||||||||||
Nonregulated | ||||||||||||||||||
Principal | $ | 5.6 | $ | 501.9 | $ | 742.9 | $ | 1,580.4 | $ | 2,830.8 | ||||||||
Interest | 165.6 | 286.9 | 238.0 | 1,218.5 | 1,909.0 | |||||||||||||
Total | 171.2 | 788.8 | 980.9 | 2,798.9 | 4,739.8 | |||||||||||||
BGE | ||||||||||||||||||
Principal | 350.0 | 121.6 | 254.2 | 1,489.3 | 2,215.1 | |||||||||||||
Interest | 128.9 | 215.6 | 197.4 | 1,411.5 | 1,953.4 | |||||||||||||
Total | 478.9 | 337.2 | 451.6 | 2,900.8 | 4,168.5 | |||||||||||||
BGE preference stock | — | — | — | 190.0 | 190.0 | |||||||||||||
Operating leases2 | 505.6 | 454.6 | 470.7 | 892.5 | 2,323.4 | |||||||||||||
Purchase obligations:3 | ||||||||||||||||||
Purchased capacity and energy4 | 425.2 | 489.6 | 213.8 | 276.4 | 1,405.0 | |||||||||||||
Fuel and transportation | 1,825.1 | 1,503.5 | 649.7 | 918.9 | 4,897.2 | |||||||||||||
Other | 259.1 | 41.8 | 20.3 | 19.3 | 340.5 | |||||||||||||
Other noncurrent liabilities: | ||||||||||||||||||
FIN 48 tax liability | 22.7 | 18.4 | — | 14.0 | 55.1 | |||||||||||||
Pension benefits5 | 84.1 | 170.8 | 162.9 | — | 417.8 | |||||||||||||
Postretirement and post employment benefits6 | 43.0 | 99.6 | 116.2 | 229.1 | 487.9 | |||||||||||||
Total contractual payment obligations | $ | 3,814.9 | $ | 3,904.3 | $ | 3,066.1 | $ | 8,239.9 | $ | 19,025.2 | ||||||||
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Liquidity Provisions
In many cases, customers of tolling contracts and estimated variable payments under unit-contingent power purchase agreements.
the life of the respective plants, we agreed to purchase 50.01% of the available output of CENG's nuclear plants at market prices. We regularly reviewhave included in the table our liquidity needscommitments under this agreement for five years, the time period for which we have more reliable data. Further, we continue to ensureown a 50.01% membership interest in CENG that we have adequate facilities availableaccount for as an equity method investment. See Note 16 in the Consolidated Financial Statements for more details on this agreement.
We have certain agreements that contain provisions that would require additional collateral upon credit rating decreases in the senior unsecured debt of Constellation Energy. Decreases in Constellation Energy's credit ratings would not trigger an early paymentnonqualified pension plans. Refer to Note 7 to Consolidated Financial Statements for more detail on any of our credit facilities.
Under counterparty contractspension plans.
Credit Ratings Downgraded to | Level Below Current Rating | Incremental Obligations | Cumulative Incremental Obligations | |||||
---|---|---|---|---|---|---|---|---|
| | (In millions) | ||||||
BBB/Baa2 | 1 | $ | 327 | $ | 327 | |||
BBB-/Baa3 | 2 | 281 | 608 | |||||
Below investment grade | 3 | 728 | 1,336 |
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. We discuss our credit ratings in theSecurity Ratings section and our credit facilities in theAvailable Sources of Funding section.
The credit facilities of Constellation Energy and BGE have limited material adverse change clauses, none of which would prohibit draws under the existing facilities. The long-term debt indentures of Constellation Energy and BGE do not contain material adverse change clauses or financial covenants.
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 December 31, 2007, the debt to capitalization ratios as defined in the credit agreements were no greater than 46%. The credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At December 31, 2007, the debt to capitalization ratio for BGE as defined in this credit agreement was 47%. At December 31, 2007, BGE had $0.7 million in letters of credit outstanding under this agreement.
Failure by Constellation Energy, or BGE, to comply with these provisions could result in the accelerationdetermination of the maturity of the debt outstanding under these facilities. The credit facilities of Constellation Energy contain usual and customary cross-default provisions that applyrelated liabilities recorded in our Consolidated Balance Sheets as discussed in Note 7 to defaults on debt by Constellation Energy and certain subsidiaries over a specified threshold.Consolidated Financial Statements.
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The BGE credit facility also contains usual and customary cross-default provisions that apply to defaults on debt by BGE over a specified threshold. The indenture pursuant to which BGE has issued and outstanding mortgage bonds provides that a default under any debt instrument issued under the indenture may cause a default of all debt outstanding under such indenture.
Constellation Energy also provides credit support to Calvert Cliffs, Nine Mile Point, and Ginna to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants.
Pursuant to Senate Bill 1, in June 2007, BondCo, a subsidiary of BGE, issued an aggregate principal amount of $623.2 million of rate stabilization bonds to recover deferred power purchase costs. We discuss Senate Bill 1 inBusiness Environment—Regulation—Maryland—Senate Bills 1 and 400 section and BondCo in more detail inNote 4.
We discuss our short-term credit facilities inNote 8, long-term debt inNote 9, lease requirements inNote 11, and commitments and guarantees inNote 12.Table of Contents
Off-Balance Sheet Arrangements
For financing and other business purposes, we utilize certain off-balance sheet arrangements that are not reflected in our Consolidated Balance Sheets. Such arrangements do not represent a significant part of our activities or a significant ongoing source of financing.
We use these arrangements when they enable us to obtain financing or execute commercial transactions on favorable terms. As of December 31, 2007,2010, we have no material off-balance sheet arrangements, including:
At December 31, 2007,2010, Constellation Energy had a total face amount of $14,761.6 million$9.4 billion in guarantees outstanding, of which $13,538.0 million$8.6 billion related to our competitive supply activities.NewEnergy business. These amounts generally do not represent incremental consolidated Constellation Energy obligations; rather, they primarily represent parental guarantees of certain subsidiary obligations to third parties. These guarantees are put into placeparties in order to allow our subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. While the stated limit of these guarantees is $13,538.0 million, our calculated fair value ofOur estimated net exposure for obligations forunder commercial transactions covered by these guarantees was $3,460.6 millionapproximately $1.5 billion at December 31, 2007. If2010, which represents the total amount the parent company wascould be required to fund these subsidiary obligations, the total amount based on December 31, 20072010 market prices would be $3,460.6 million.prices. For those guarantees related to our derivative liabilities, the fair value of the obligation is recorded in our Consolidated Balance Sheets. We believe it is unlikely that we would be required to perform or incur any losses associated with guarantees of our subsidiaries' obligations.
We discuss our other guarantees inNote 12 to Consolidated Financial Statements and our significant variable interests inNote 4 to Consolidated Financial Statements.
Market Risk Management
We areIntroduction
Risk is inherent in our business activities. Constellation Energy is exposed to variousmarket, credit, operational, and liquidity risks including, but not limitedthat are fundamental to our business of providing products and services across the energy commodity pricevalue chain. Additionally, our businesses are subject to business and volatilitystrategic risks, the risks of unsuccessful business performance due to changing economic conditions, competition, regulatory environment, legislation, economic conditions, market liquidity, country or sovereign issues, systems or process failure, and fiscal and monetary policies. These risks exist in our business with varying levels of exposure, and are interrelated and cannot be managed in isolation.
The Company's risk creditmanagement framework and governance structure are intended to provide appropriate controls and ongoing management of the major risks in our business activities. The risk interest ratemanagement framework is also intended to create a culture of risk equity price risk, foreign exchangeawareness and personal accountability for risk-taking across the Company. As a result of the extent and diversity of the risks the Company faces in its business operations, we analyze risk and operations risk.risk concentration at transaction, portfolio, business, and enterprise-wide levels to ensure that material risks are identified and managed effectively. We utilize numerous methods to evaluate and measure risks. In general, we evaluate risks in terms of the impact on our economic value, earnings, liquidity, strategic objectives, credit rating, reputation, and values. We identify and evaluate risks based not only on their probability of occurring and magnitude of impact on the financial statements, but also with respect to the potential for significant or unexpected shifts in market conditions or rules.
We recognize the importance of managing risk as a key differentiator in the energy business and view the active and effective management of the risks in our businesses to be of paramount importance. Our risk management program is based on established policies and procedures to manage these key business risks, with a strong focus on the physical nature of our business. This program is predicated on a strong risk management culture combined with an effectiveextensive system of internal controls. Nevertheless, no system of risk management can cost-effectively eliminate all risks to which an entity is exposed. Thus, in particular environments, the Company may not be able to mitigate risk exposures to the level desired and may have exposures to certain risk factors that cannot be mitigated.
In this section, we will review the Company's risk practices in terms of our:
Risk Governance
Our Board of Directors is responsible for risk oversight of Company activities. The Board of Directors has approved the Company's risk appetite statement and has authorized management to establish risk policies and limits consistent with this statement. The Audit Committee of the Board of Directors periodically reviews compliance with our risk parameters,policies and limits and trading guidelines, and ourthe effectiveness of the related internal controls. The Compensation Committee of the Board of Directors has established a value at risk limit. We have a Risk Management Division that is responsible for monitoringoversight of the keyimpact of compensation policies on risk-taking. Management has established the risk appetite statement in the context of the market environment and the Company's business risks, enforcing compliance withstrategy. In setting the risk appetite, the Company takes into consideration factors such as market volatility, product liquidity, business trends, and management experience.
The Company's Risk Management Committee (RMC) is responsible for approving risk management policies and limits consistent with the risk limits, as well as managing credit risk. The Risk Management Division reports to the Chief Risk Officer (CRO) who provides regular risk management updates to the Audit Committee and the Board of Directors.
We have a Risk Management Committee (RMC) that is responsible for establishing risk management policies,appetite statement, reviewing procedures for the identification, assessment, measurement, and
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management of risks, and the monitoring and reporting of risk exposures. The RMC meets on a regular basis and is chaired by our Chief Risk Officer, and consists ofExecutive Officer. Other committee members are our Chief ExecutiveRisk Officer, our Chief Financial Officer, our Executive Vice PresidentChairman, General Counsel, Chief Human Resources Officer, head of Corporate Strategy the Presidentand Development, head of Constellation Energy Resources, the Chief Commercial Officers of Constellation Energy Resources,Corporate Affairs, Public, and the President of Constellation Energy Nuclear Group.Environmental Policy and business unit leaders. In addition, the CROChief Risk Officer coordinates with the risk management committees atin the major operating subsidiariesbusiness units that meet regularly to identify, assess, and quantify material risk issues and to develop strategies to manage these risks.
Business managers are responsible for managing risks within the established risk appetite, while the Risk Management Group (RMG) is responsible for enforcing compliance with risk management policies and risk limits. The RMG reports to the Chief Risk Officer, who is a member of the Company's Management Committee and who reports to the Chief Executive Officer and the Board of Directors. The Chief Risk Officer provides regular risk management updates to the Audit Committee and the Board of Directors.
In an effort to manage risks, Constellation Energy has established a series of limits at the corporate and business unit level that reflect the Company's risk appetite. Business units are responsible for adhering to established limits, against which exposures are monitored and reported. Limit breaches are reported in a timely manner to senior management, who consults with the business unit on an appropriate course of action.
Interest Rate Risk Functions
Risks are managed at the individual and portfolio level of exposure in each business relative to the Company's risk appetite in aggregate and across all major risk types.
Constellation Energy's RMG is an independent function tasked with providing an independent quantification and assessment of key business risks, as well as providing an evaluation of individual risk components that contribute to the Company's consolidated risk profile. The RMG is also responsible for establishing risk policies, maintaining appropriate risk controls, ensuring compliance with policies and procedures, and monitoring methods according to the risk parameters established by the Board of Directors.
The RMG consists of seven divisions that focus on a specialized area of risk.
Credit Risk Management
Credit Risk Management is responsible for managing the risk of loss inherent in the business units stemming from counterparty or customer failures and adverse market events that effect counterparty creditworthiness. This group supports the business units by establishing credit relationships with various wholesale counterparties and retail customers and facilitating market liquidity with credit limits and appropriate contractual credit terms and conditions. Credit risk managers are responsible for managing credit risk associated with our business activities, including establishing limits and contractual structures, as well as establishing and enforcing credit policies.
Market Risk Management
Market Risk Management is responsible for effectively identifying, quantifying, monitoring, and reporting on impacts of market risk, to include price volatility, correlations, volume uncertainty, market liquidity, interest rate and currency exposure on company businesses. The market risk group also enforces the Market Risk policies and ensures compliance with these policies, including the monitoring, analyzing, and escalating of market risk controls. This group also develops market risk measurement tools, such as stress and scenario tests, gross margin-at-risk, and assists the businesses in implementing market strategies with the highest benefits.
Collateral and Funding Liquidity Risk Management
Collateral Risk Management is responsible for providing an integrated view on credit, market, and company liquidity risks to facilitate Treasury's management of the Company's collateral and overall liquidity position. Funding liquidity risk is the risk that we may be unable to fund our obligations in some future period. This group's responsibilities include measuring and monitoring collateral flows, downgrade collateral needs, and collateral use across the Company. Additionally, this group forecasts expected collateral and liquidity requirements as well as estimates potential collateral requirements due to market shifts, hedging strategies, and adjustments to the Company's credit ratings. Finally, Collateral Risk Management assists the businesses in determining the strategic use of collateral and the appropriate cost of collateral for transactions. The group also works closely with the Treasury function to plan for expected and contingent liquidity needs based on the Company's long-term business plan.
Operational Risk Management
Operational risk is the risk associated with human error, a failure of process and systems or external factors. RMG staff oversee implementation of a common framework for defining, measuring, monitoring, and reporting operational risks. The integrated risk assessment process involves capturing risk and controls holistically. Accountability for the identification of risks in our business processes resides with business management, who must ensure the completeness and effectiveness of controls and level of residual risk.
Corporate Audit
Corporate Audit assists in ensuring that controls put in place by management to mitigate the risks of the business are adequate and functioning appropriately. This group supports the risk assessment process including the analysis of inherent and residual risk, performs risk-based audits as approved by the Audit Committee of the Board of Directors, and supports the improvement of the effectiveness and efficiency of key business processes.
Special Situations Group
Our Special Situations Group is comprised of two departments: receivables management and credit workout. Receivables management seeks to maximize cash flows from collection efforts
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for the Company's business units. Its primary function is to mitigate risk by focusing efforts on all aspects of the accounts receivable process including fees related to early termination of energy supply contracts. Credit workout is responsible for the management of distressed customers. These include counterparties in bankruptcy and contractual default. Credit workout also seeks to generate cash flows by negotiating early settlement on potential losses and through the sale of impaired assets in the secondary market.
Deal Review, Risk Analytics and Risk Capital
Our Deal Review team performs independent reviews of structured transactions and develops standardized risk-adjusted metrics for assessing these transactions. Our Risk Analytics team provides quantitative support to all risk functions, builds key risk models and metrics, and conducts independent validation of models used by the Company. Our Risk Capital team is responsible for the development and implementation of a framework for the measurement of capital adequacy, risk-based transaction pricing and risk-adjusted performance measurement of our business segments and portfolios. Risk capital, or economic capital, is the level of capital required to offset the effect of unexpected specified stress on the economic value of the Company. It is an assessment of the underlying market, credit, operational, and liquidity risks of the Company's business activities, utilizing internal risk assessment methodologies.
Risk Exposures
We manage risks across all of our businesses. We summarize below the risks we manage within each of our businesses.
Generation and NewEnergy Businesses
Our Generation and NewEnergy businesses are exposed to various risks in the competitive marketplace that may materially impact our financial results and affect our earnings. These risks include changes in interest rates ascommodity prices, potential imbalances in supply and demand, credit risk and operational risk.
Regulated Electric Business
BGE does not own or operate any electric generating facilities. Therefore, BGE's regulated electric business is exposed to market price risk. To mitigate this, BGE obtains energy and capacity to provide SOS through a result of financing through our issuance of variable-rate and fixed-rate debt and certain related interest rate swaps. We may use derivative instruments to manage our interest rate risks.
In July 2004, to optimizecompetitive bidding process approved by the mix of fixed and floating-rate debt, we entered into interest rate swaps relating to $450.0 million of our long-term debt. These fair value hedges effectively convert our current fixed-rate debt to a floating-rate instrument tied to the three month London Inter-Bank Offered Rate. Including the $450.0 million in interest rate swaps, approximately 16% of our long-term debt is floating-rate.
Maryland PSC. We discuss our use of derivative instruments to manage our interest rate riskSOS and the impact on base rates in more detail inItem 1. Business—Baltimore Gas and Electric Company—Electric Business section. As a result of this process, BGE's exposure to market price risk is limited, and at December 31, 2010, our exposure to commodity price risk for our regulated electric business was not material. However, BGE may enter into electric futures, options, and swaps to hedge its market price risk if appropriate. We discuss this further inNote 13 to Consolidated Financial Statements.
BGE's regulated electric business is also exposed to wholesale credit risk from its suppliers as well as retail credit risk from its customers. Finally, BGE is subject to operational risks, including potential impacts from storms and distribution asset failures.
Regulated Gas Business
BGE acquires all of its natural gas for delivery to customers from third party suppliers. Therefore, BGE's regulated gas business is exposed to market price risk. However, BGE recovers the costs of purchased gas under the market-based rates incentive mechanism approved by the Maryland PSC. Additionally, BGE may enter into gas futures, options, and swaps to hedge its price risk under our market-based rate incentive mechanism and our off-system gas sales program as appropriate. We discuss this further inNote 13 to Consolidated Financial Statements. At December 31, 2010, our exposure to commodity price risk for our regulated gas business was not material.
BGE's regulated gas business is also exposed to wholesale credit risk from its suppliers as well as retail credit risk from its customers. Finally, BGE is subject to operational risks, including potential impacts from storms and distribution asset failures.
Risk Exposure Categories
The following table provides information about our debt obligationsvarious categories of risk exposures that we manage include, but are sensitivenot limited to, market risk, which includes interest rate changes:risk, security price risk, and foreign currency risk; credit risk, which includes wholesale and retail credit risk; operational risk and collateral and funding liquidity risk. As previously noted, these risks may be common to more than one of our businesses. We discuss each of these primary risk exposure categories separately below.
Principal Payments and Interest Rate Detail by Contractual Maturity Date
| 2008 | 2009 | 2010 | 2011 | 2012 | Thereafter | Total | Fair value at December 31, 2007 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (Dollars in millions) | |||||||||||||||||||||||
Long-term debt | ||||||||||||||||||||||||
Variable-rate debt | $ | — | $ | — | $ | — | $ | 36.0 | $ | 255.2 | $ | 510.4 | $ | 801.6 | $ | 801.6 | ||||||||
Average interest rate | — | % | — | % | — | % | 3.77 | % | 7.59 | % | 4.09 | % | 5.19 | % | ||||||||||
Fixed-rate debt | $ | 355.6 | $ | 566.5 | $ | 56.9 | $ | 81.7 | $ | 624.1 | $ | 2,559.5 | (A) | $ | 4,244.3 | $ | 4,307.5 | |||||||
Average interest rate | 6.20 | % | 6.09 | % | 5.68 | % | 5.95 | % | 6.82 | % | 6.18 | % | 6.26 | % |
CommodityMarket Risk
We are exposed to the impact of market fluctuations in the price and transportation costs of electricity,power, natural gas, coal, and other related commodities. These risks arise from our ownership and operation of power plants, the load-serving activities of BGEour retail and our competitivewholesale customer supply operations, and our origination, risk management, and trading activities. We discuss theseThese commodity price risks separately for our merchant energy and our regulated businesses below.
Merchant Energy Business
Our merchant energy business is exposed to various risks in the competitive marketplace that may materially impact its financial results and affect our earnings. These risks include changes in commodity prices, imbalances in supply and demand, and operations risk.
Commodity Prices
Commodity price risk arisesarise from:
A number of factors associated with the structure and operation of the energy markets significantly influence the level and volatility of prices for energy commodities and related derivative products. We use such commodities and contractsproducts in our merchant energy business,Generation and NewEnergy businesses, and if we do not properly hedge the associated financial exposure, this commodity price volatility could adversely affect our economic value or earnings. These factors include:
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These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country as a result of regional differences in:
Additionally, we have fuel requirements that are subject to future changes in coal, natural gas, uranium, and oil prices. Our power generation facilities purchase fuel under contracts or in the spot market. Fuel prices may be volatile, and the price that can be obtained from powerelectricity sales may not change at the same rate or in the same direction as changes in fuel costs. This could have a material adverse impact on our financial results.
Supply and Demand Risk
We are exposed to the risk that available sources of supply may differ from the amount of power demanded by our customers under fixed-price load-serving contracts. During periods of high demand, our power supplies may be insufficient to serve our customers' needs and could require us to purchase additional energy at higher prices. Alternatively, during periods of low demand, our power supplies may exceed our customers' needs and could result in us selling that excess energy at lower prices. Either of those circumstances could have a negative impact on our financial results.
We are also exposed to variations in the prices and required volumes of natural gas, oil, and coal we burn at our power plants to generate electricity. During periods of high demand on our generation assets, our fuel supplies may be insufficient and could require us to procure additional fuel at higher prices. Alternatively, during periods of low demand on our generation assets, our fuel supplies may exceed our needs, and could result in us selling the excess fuels at lower prices. Either of these circumstances will have a negative impact on our financial results.
Operations Risk
Operations risk is the risk that a generating plant will not be available to produce energy and the risks related to physical delivery of energy to meet our customers' needs. If one or more of our generating facilities is not able to produce electricity when required due to operational factors, we may have to forego sales opportunities or fulfill fixed-price sales commitments through the operation of other more costly generating facilities or through the purchase of energy in the wholesale market at higher prices. We purchase power from generating facilities we do not own. If one or more of those generating facilities were unable to produce electricity due to operational factors, we may be forced to purchase electricity in the wholesale market at higher prices. This could have a material adverse impact on our financial results.
Our nuclear plants produce electricity at a relatively low marginal cost. The Nine Mile Point facility and the Ginna facility sell 90% and 80% of their respective output under unit-contingent power purchase agreements (we have no obligation to provide power if the units are not available) to the previous owners. However, if an unplanned outage were to occur at Calvert Cliffs during periods when demand was high, we may have to purchase replacement power at potentially higher prices to meet our obligations, which could have a material adverse impact on our financial results.
Risk Management and Trading
As part of our overall portfolio, we manage the commodity price risk of our competitive supply activities and our electric generation facilities, including power sales, fuel and energy purchases, emission credits, interest rate and foreign currency risks, weather risk, and the market risk of outages. In order to manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales and purchases of energy, including:
The objectives for entering into such hedges include:
The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operational, and other factors.
While some of the contracts we use to manage risk represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. We use our best estimates to determine the fair value of commodity and derivative contracts we hold and sell. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors, historical price relationships, and credit exposure. However, it is likely that future market prices could vary from those used in recording derivative assets and liabilities subject to mark-to-market accounting, and such variations could be material.
We measurePower, gas, coal, and other related commodity trading risks involve the sensitivity of our wholesale marketing and risk management mark-to-market energy contractspotential decline in net income or financial condition due to potentialadverse changes in market prices, usingwhether arising from customer activities, generating plants, or proprietary positions taken by the Company. We assess and monitor market risk with a variety of tools, including EVaR, VaR, scenario analysis, and stress testing.
EVaR:
EVaR measures the potential pre-tax loss in the fair value at risk. Value atof the Generation and NewEnergy businesses due to changes in market risk factors. EVaR is a statistical model that attempts to predict riskone-day value-at-risk measure calculated at a 95% confidence level assuming a standard normal distribution of loss based on historical market price volatility. We calculate value at risk using a historical variance/covariance technique that models option positions using a linear approximation of their value. Additionally, we estimate variances and correlation using historical commodity price changesprices over the most recent rolling three-month3-month period. Our value at risk calculationEVaR includes all wholesale marketingpositions over a forward rolling 60-month time horizon that expose us to market price risk, regardless of business line.
Positions included in EVaR are comprised of mark-to-market and nonderivative accrual positions that create market risk including:
We include the positions related to physical assets to provide a more complete presentation of our commodity market risk exposures. EVaR includes illiquid products and positions for which there is limited price discovery. Modeling the positions in our Generation and NewEnergy businesses involves a number of assumptions, and includes projections of generation, emission rates and costs, customer load growth, load response to weather, and customer response to competitive supply. Changes in our forecast or management estimates will affect the fair value of these positions in a manner not captured by EVaR.
EVaR reflects the risk of loss due to market prices under normal market conditions. An inherent limitation of our value-at-risk measures is the reliance on historical prices. A sudden shift in market conditions can cause the future behavior of market prices to differ materially from the past. We use stress tests and scenario analysis to better understand extreme events as a complement to EVaR. This includes exposure to unlikely but plausible events in abnormal markets, sensitivity to changes in management projections of customer demand or forecasted generation output, and price sensitivity to illiquid points and regional basis spreads.
EVaR is monitored daily and is subject to regional and overall guidelines for the NewEnergy business. We place guidelines on the risk associated with illiquid delivery locations and regional basis within our NewEnergy business. Additionally, we monitor generation plant hedge ratios relative to guidelines specified by management. Stress tests and scenario analysis are conducted regularly and the results, trends, and explanations are reviewed by senior management and risk management derivative assetscommittees.
The EVaR amounts below represent the potential pre-tax change in the fair values of our Generation and liabilitiesNewEnergy businesses positions over a one-day holding period.
EVaR
For the year ended December 31, | 2010 | 2009 | ||||||
---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||
95% Confidence Level, One-Day Holding Period | ||||||||
Year end | $ | 36.3 | $ | 73.0 | ||||
Average | 52.2 | 92.8 | ||||||
High | 71.6 | 122.8 | ||||||
Low | 34.4 | 64.1 |
At December 31, 2010, our EVaR was approximately $36.3 million, which represents a 50% decline from its level of $73 million on December 31, 2009, mainly due to lower price levels and lower volatilities as well as a decrease in our ownership of nuclear generation as a result of our 2009 sale of a 49.99% membership interest in CENG to EDF.
VaR:
VaR measures the potential pre-tax loss in the fair value of mark-to-market energy contracts due to changes in market risk factors. VaR is calculated assuming a standard normal distribution of prices over the most recent rolling 3-month period. VaR includes all positions subject to mark-to-market accounting, including contracts for energy commodities and derivatives that result in physical settlement andnot only contracts that require cash settlement.hedge the economics of NewEnergy nonderivative power and fuel contracts and which do not receive hedge accounting treatment, but also contracts designated for trading. Thus, the positions for which we monitor VaR are included within, and are not incremental, to the positions subject to EVaR.
VaR and EVaR have similar limitations. VaR may include some products and positions for which there is limited price discovery or market depth. The modeling of option positions
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included in VaR involves a number of assumptions and approximations. An inherent limitation of our VaR measures is the reliance on historical prices. A sudden shift in market conditions can cause the future behavior of market prices to differ materially from that of the past.
The value at risk calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and our competitive supply load-serving activities. We manage these risks by monitoring our fuel and energy purchase requirements and our estimated contract sales volumes compared to associated supply arrangements. We also engage in hedging activities to manage these risks. We describe those risks and our hedging activities earlier in this section.
The value at riskVaR amounts on the next pagebelow represent the potential pre-tax loss in the fair value of our wholesale marketing and risk management derivative assets and liabilities subject to mark-to-market accounting over one and ten-day holding periods.
Total Wholesale Value at Risk
For the year ended December 31, | 2007 | 2006 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
99% Confidence Level, One-Day Holding Period | |||||||
Year end | $ | 20.4 | $ | 13.4 | |||
Average | 15.4 | 16.7 | |||||
High | 26.8 | 28.0 | |||||
Low | 8.2 | 9.6 | |||||
95% Confidence Level, One-Day Holding Period | |||||||
Year end | $ | 15.5 | $ | 10.2 | |||
Average | 11.7 | 12.7 | |||||
High | 20.4 | 21.3 | |||||
Low | 6.2 | 7.3 | |||||
95% Confidence Level, Ten-Day Holding Period | |||||||
Year end | $ | 49.1 | $ | 32.3 | |||
Average | 37.0 | 40.2 | |||||
High | 64.6 | 67.4 | |||||
Low | 19.7 | 23.0 |
Based on a 99% confidence interval, we would expect a one-day change in the fair value of the portfolio greater than or equal to the daily value at risk approximately once in every 100 days. In 2007, we did not experience any instance where the actual daily mark-to-market change in portfolio value exceeded the predicted value at risk. However, published market studies conclude that exceeding daily value at risk less than seven times in a one-year period is considered consistent with a 99% confidence interval.
The table above is the value at risk associated with our wholesale marketing, risk management, and trading operation's derivative assets and liabilitiesNewEnergy business positions subject to mark-to-market accounting, including both trading and non-trading activities. activities, over one and ten-day holding periods.
Total Mark-to-Market VaR
For the year ended December 31, | 2010 | 2009 | ||||||
---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||
99% Confidence Level, One-Day Holding Period | ||||||||
Year end | $ | 13.6 | $ | 8.0 | ||||
Average | 7.3 | 18.1 | ||||||
High | 13.8 | 55.5 | ||||||
Low | 4.8 | 5.0 | ||||||
95% Confidence Level, One-Day Holding Period | ||||||||
Year end | $ | 10.4 | $ | 6.1 | ||||
Average | 5.6 | 13.8 | ||||||
High | 10.5 | 42.2 | ||||||
Low | 3.6 | 3.8 | ||||||
95% Confidence Level, Ten-Day Holding Period | ||||||||
Year end | $ | 32.9 | $ | 19.2 | ||||
Average | 17.7 | 43.7 | ||||||
High | 33.2 | 133.6 | ||||||
Low | 11.4 | 12.0 |
Constellation Energy's proprietary trading activities are substantially reduced from previous years and remain immaterial. These activities continue to be managed with daily VaR limits, stop loss limits and position limits.
Interest Rate Risk
We experienced higher value at risk for the year endedare exposed to changes in interest rates as a result of financing through our issuance of variable-rate and fixed-rate debt and certain related interest rate swaps. We may use derivative instruments to manage our interest rate risks.
As of December 31, 2007 compared2010, we have interest rate swaps relating to $400.0 million of our long-term debt. These fair value hedges effectively convert our current fixed-rate debt to a floating-rate instrument tied to the year ended December 31, 2006, primarily duethree month London Inter-Bank Offered Rate (LIBOR). Including the $400.0 million in interest rate swaps, approximately 11.1% of our long-term debt is floating-rate.
During January 2011, as part of retiring the remainder of our 7.00% Notes, we terminated $200.0 million of interest rate swaps.
During February 2011, we entered into $500 million of interest rate swaps related to fixed rate long-term debt, effectively converting the debt to a higher number of economicfloating-rate instrument tied to LIBOR. Of these swaps, $350 million qualify for and have been designated as fair value hedges of accrual positions, increased volatility of commodityand $150 million do not qualify as fair value hedges and will be marked to market prices, and an increase in our trading activities discussed below.through earnings.
We discuss our mark-to-market resultsuse of derivative instruments, including interest rate swaps, to manage our interest rate risk in more detail in theCompetitive SupplyNote 13 to Consolidated Financial Statements section..
The following table detailsprovides information about our value at risk for the trading portion of our wholesale marketing and risk management derivative assets and liabilities subjectdebt obligations that are sensitive to mark-to-market accounting over a one-day holding period at a 99% confidence level for 2007 and 2006:
Wholesale Trading Value at Risk
For the year ended December 31, | 2007 | 2006 | ||||
---|---|---|---|---|---|---|
| (In millions) | |||||
Average | $ | 11.0 | $ | 11.2 | ||
High | 17.4 | 17.6 |
Our trading positions can be used to manage the commodity price risk of our competitive supply activities and our generation facilities. We also engage in trading activities for profit. These activities are managed through daily value at risk and stop loss limits and liquidity guidelines.
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 derivative assets and liabilities subject to mark-to-market accounting could differ from the calculated value at risk, and such changes could have a material impact on our financial results.interest rate changes:
Principal Payments and Interest Rate Detail by Contractual Maturity Date
| 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | Fair value at December 31, 2010 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (Dollars in millions) | ||||||||||||||||||||||||
Long-term debt | |||||||||||||||||||||||||
Variable-rate debt | $ | 209.6 | $ | 18.0 | $ | — | $ | — | $ | 226.2 | $ | 74.9 | $ | 528.7 | $ | 528.7 | |||||||||
Average interest rate (A) | 1.24 | % | 4.50 | % | — | % | — | % | 2.36 | % | 2.13 | % | 1.95 | % | |||||||||||
Fixed-rate debt | $ | 95.7 | $ | 174.2 | $ | 466.6 | $ | 90.4 | $ | 424.5 | $ | 2,977.9 | $ | 4,229.3 | $ | 4,518.4 | |||||||||
Average interest rate | 6.10 | % | 6.37 | % | 6.06 | % | 5.33 | % | 4.75 | % | 6.60 | % | 6.31 | % |
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Security Price Risk
Our wholesale marketing, risk management, and trading operation provided BGE 100% of the energy and capacityWe are exposed to meet its residential standard offer service obligationsprice fluctuations in financial markets primarily through June 30, 2006. Bidding to supply BGE's standard offer service to all customers occurs from time to time through a competitive bidding process approved by the Maryland PSC. Our wholesale marketing, risk management, and trading operation is supplying a portion of BGE's standard offer service obligation to all customers.our pension plan assets. In 2010, our actual gain on pension plan assets was $148.8 million. We discuss standard offer service and the impact on base ratesdescribe our pension funding requirements in more detail inItem 1. Business—Baltimore GasNote 7 to Consolidated Financial Statements.
Foreign Currency Risk
Our Generation and Electric Company—Electric Business
BGE may receive performance assurance collateral from suppliers to mitigate suppliers' credit risks in certain circumstances. Performance assurance collateral is designed to protect BGE's potential exposure over the term of the supply contracts and will fluctuate to reflect changes in market prices. In additionNewEnergy businesses are exposed to the collateral provisions, there are supplier "step-up" provisions,impact of foreign exchange rate fluctuations. This foreign currency risk arises from our activities in countries where we transact in currencies other suppliers can step in ifthan the early termination of a full-requirements service agreement with a supplier should occur, as well as specific mechanisms for BGE to otherwise replace defaulted supplier contracts. All costs incurred by BGE to replace the supply contract are to be recovered from the defaulting supplier or from customers through rates. Finally, BGE's exposure to uncollectible expense or credit risk from customers for the commodity portion of the bill is covered by the administrative fee included in Provider of Last Resort rates.
Our regulated electric business may enter into electric futures, options, and swaps to hedge its price risk. We discuss this further inNote 13. At December 31, 2007 and 2006,U.S. dollar. In 2010, our exposure to commodity priceforeign currency risk for our regulated electric business was not material.
Regulated Gas Business
Our regulated gas business may enter into gas futures, options, and swaps to hedge its price risk under our market-based rate incentive mechanism and our off-system gas sales program. We discuss this further inNote 13. At December 31, 2007 and 2006,manage our exposure to commodity priceforeign currency exchange rate risk forusing a foreign currency hedging program. We will continue to have limited exposure to the Canadian dollar due to our regulatedCanadian gas business was not material.and power operations.
Credit Risk
We are exposed to credit risk through our merchant energy businessGeneration and NewEnergy businesses and BGE's operations. Credit risk is the loss that may
result from counterparties' nonperformance and retail collections.customer accounts receivable and forward value payment risk arising from contracted power and gas supply agreements. We evaluate theour credit risk of our wholesale marketing, risk management, and trading operation and our retail activities separately as discussed below.
Wholesale Credit Risk
We measure wholesale credit risk as the replacement cost for open energy commodity and derivative transactions (both mark-to-market and accrual) adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where we have a legally enforceable right of setoff. We monitor and manage the credit risk of our wholesale marketing, risk management, and trading operationNewEnergy business through credit policies and procedures, which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral, or prepayment arrangements, and the use of master netting agreements.
As of December 31, 20072010, our total exposure across our entire wholesale portfolio is $2.5 billion, net of collateral, and 2006,includes accrual positions and derivatives. This total exposure has declined from the credit portfolio$2.8 billion as of December 31, 2009, primarily driven by a change in commodity prices and the decrease in our exposure to CENG throughout 2010.
The top ten counterparties account for 55% of our wholesale marketing,total exposure with none of that exposure being non-investment grade. We consider a significant concentration of credit risk management,to be any single obligor or counterparty whose concentration exceeds 10% of total credit exposure. At December 31, 2010, two counterparties, a large power cooperative and trading operationCENG, comprised a total exposure concentration of 25%.
As of December 31, 2010 and 2009, counterparties in our NewEnergy credit portfolio had the following public credit ratings:ratings, shown as a percentage of the total portfolio exposure:
At December 31, | 2007 | 2006 | ||||
---|---|---|---|---|---|---|
Rating | ||||||
Investment Grade1 | 44 | % | 61 | % | ||
Non-Investment Grade | 7 | 3 | ||||
Not Rated | 49 | 36 |
At December 31, | 2010 | 2009 | ||||||
---|---|---|---|---|---|---|---|---|
Rating | ||||||||
Investment Grade (1) | 47 | % | 43 | % | ||||
Non-Investment Grade | 4 | 2 | ||||||
Not Rated | 49 | 55 |
Our exposure to "Not Rated" counterparties was $2.1$1.2 billion at December 31, 20072010 compared to $1.1$1.5 billion at December 31, 2006.2009. This increasedecrease was mostly due to an increasedriven by a reduction in our CENG credit portfolio related to natural gas, international coal customers, and freight companies that doexposure, which is not have public credit ratings. Althoughexternally rated.
Many of our not rated many of these counterparties (including CENG) are considered investment grade equivalent based on our internal credit ratings.
We utilize internal credit ratings to evaluate the creditworthiness of our wholesale customers, including those companies that do not have public credit ratings. Based on internal credit ratings, approximately $682.9 million$1.1 billion or 33%87% of the exposure to unrated"Not Rated" counterparties was rated investment grade equivalent at December 31, 20072010 and approximately $643.8 million$1.2 billion or 59%81% was rated investment grade equivalent at December 31, 2006.2009.
The following table provides the breakdown of the credit quality of our wholesale credit portfolio based on our internal credit ratings.
At December 31, | 2007 | 2006 | ||
---|---|---|---|---|
Investment Grade Equivalent | 62% | 82% | ||
Non-Investment Grade | 38 | 18 |
The credit quality of our wholesale credit portfolio declined during 2007 This includes those counterparties which are externally rated and those in the "Not Rated" category as a resultpercentage of the continued growth of our global coal and freight business combined with significant increases in coal prices and freight rates.total portfolio exposure.
At December 31, | 2010 | 2009 | |||||
---|---|---|---|---|---|---|---|
Investment Grade Equivalent | 89 | % | 88 | % | |||
Non-Investment Grade Equivalent | 11 | 12 |
A portion of our total 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, risk management, and trading 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 December 31, 2007:
Rating | Total Exposure Before Credit Collateral | Credit Collateral | Net Exposure | Number of Counterparties Greater than 10% of Net Exposure | Net Exposure of Counterparties Greater than 10% of Net Exposure | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (Dollars in millions) | |||||||||||||
Investment grade | $ | 1,544 | $ | 278 | $ | 1,266 | — | $ | — | |||||
Split rating | 73 | — | 73 | — | — | |||||||||
Non-investment grade | 88 | 48 | 40 | — | — | |||||||||
Internally rated—investment grade | 321 | 70 | 251 | — | — | |||||||||
Internally rated—non-investment grade | 395 | 48 | 347 | — | — | |||||||||
Total | $ | 2,421 | $ | 444 | $ | 1,977 | — | $ | — | |||||
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, risk management, and trading 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 on its contractual obligations and we were to liquidate all contractstransactions with that entity, our potential credit loss would include all forward and settlement exposure plus any additional costs related to termination and replacement of the loss in value of derivativepositions. This would include contracts recorded at fair value,accounted for using the mark-to-market, hedge, and accrual accounting methods, the amount owed foror due from settled transactions, and additional payments, ifless any that we would have to make to settle unrealized losses on accrual contracts.collateral held from the counterparty. In addition, if a counterparty were to default under an accrual contract that is currently favorable to us, we may recognize a material adverse impact inon our results in the future delivery period to the extent that we are required to replace the contract that is in default with another contract at current market prices. These potential losses would be limited to the extent that the in-the-money amount exceeded any credit mitigants such as cash, letters of credit, or parental guarantees supporting the counterparty obligation. To reduce our credit risk
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with counterparties, we attempt to enter into agreements that allow us to obtain collateral on a contingent basis, seek third party guarantees of the counterparty's obligation, and enter into netting agreements that allow us to offset receivables and payables with forward exposure across many transactions.
Due to 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 power we had contracted for), we could incur a loss that could have a material impact on our financial results.
We also enter into various wholesale transactions through ISOs. These ISOs are exposed to counterparty credit risks. Any losses relating to counterparty defaults impacting the ISOs are allocated to and borne by all other market participants in the ISO. These ISOs have established credit policies and practices to mitigate the exposure of counterparty credit risks. As a market
participant, we continuously assess our exposure to the credit risks of each ISO.
BGE is exposed to wholesale credit risk of its suppliers for electricity and gas to serve its retail customers. BGE may receive performance assurance collateral to mitigate electricity suppliers' credit risks in certain circumstances. Performance assurance collateral is designed to protect BGE's potential exposure over the term of the supply contracts and will fluctuate to reflect changes in market prices. In addition to the collateral provisions, there are supplier "step-up" provisions, where other suppliers can step in if the early termination of a full-requirements service agreement with a supplier should occur, as well as specific mechanisms for BGE to otherwise replace defaulted supplier contracts. All costs incurred by BGE to replace the supply contract are to be recovered from the defaulting supplier or from customers through rates.
Retail Credit Risk
We are exposed to retail credit risk through our competitiveNewEnergy electricity and natural gas supply activities, which serve commercial and industrial companies and governmental entities, and through BGE's electricity and natural gas distribution operations. Retail credit risk results when customers default on their contractual obligations.obligations or fail to pay for service rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers of our nonregulated retail businesses.
Retail credit risk is managed through established credit approval policies, monitoring customer exposures, and the use of credit mitigation measures such as letters of credit or prepayment arrangements. In addition, we have taken steps to augment our credit staff in response to current economic conditions. In accordance with our credit policy we do not have a significant exposure concentration with any one customer, geographic area or industry.
Our retail credit portfolio is well diversified with no significant company or industry concentrations. During 2007, we did not experience a material change in the credit quality of our retail credit portfolio compared to 2006. Retail credit quality is dependent on the economy and the ability of our customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, our retail credit risk may be adversely impacted. However, we have organized a dedicated credit workout function whose job is to work with distressed customers and recover receivables owed to the company. This also involves negotiating early termination settlements and selling impaired assets in the secondary market.
As a regulated entity, BGE is generally ablesubject to recover all prudently incurredretail credit risk associated with both the delivery portion of a customer's bill as well as the uncollectible expense or credit risk from the gas and/or electric commodity portion of the bills of those customers to whom BGE sells the gas and electric commodity. BGE is also exposed to credit risk associated with the timing of the collection of receivables from those customers who have contracted with a third party supplier where BGE has purchased that supplier's receivables. Although both BGE's delivery and commodity rates include some level of costs includingfor uncollectible customer accounts receivable expenses.
Foreign Currency Risk
Our merchant energy businessexpenses, full recovery is contingent on amounts approved by the Maryland PSC in customer rates and, therefore is not guaranteed and BGE is exposed to the impact of foreign exchange rate fluctuations. This foreign currency risk arises from our activities in countries where we transact in currencies other than the U.S. dollar. In 2007, our exposure to foreign currency risk was not material. However, we expect our foreign currency exposure to grow due to our Canadian operations, global power, coal, freight,these potential losses and natural gas operations, and our shipping and UniStar ventures. We manage our exposure to foreign currency exchange rate risk using a comprehensive foreign currency hedging program. While we cannot predict currency fluctuations, the impact of foreign currency exchange rate risk could be material.related carrying costs.
Equity PriceOperational Risk
Operational risk is the risk associated with human error or a failure of process and systems, or external factors, as well as the risk of operating owned and contractually controlled generating assets, electric transmission and distribution systems, and gas distribution systems. We are exposed to price fluctuationsmany types of operational risks, including fraud by employees, clerical and record-keeping errors, and unauthorized data access. Additionally, our asset operations can be effected by those events that are partially or wholly out of our control, like natural disasters, acts of terrorism, and computer application viruses, which may cause losses in equity markets primarily throughgeneration or service to customers resulting in revenue loss.
We own, have ownership interests in, and operate power generation facilities, which use a diverse mix of fuels including fossil fuels, nuclear and biomass. We are also exposed to variations in the prices for, and required volumes of, natural gas, oil, and coal required to fuel our pension planpower plants that generate electricity. Therefore, high commodity prices increase the impact of generator outages and variable load, but as long as the electricity and fuel prices move in tandem, we have limited exposure to changing commodity prices. During periods of high demand on our generation assets, our nuclear decommissioning trust funds,fuel supplies may be insufficient and trustcould require us to procure additional fuel at higher prices. Alternatively, during periods of low demand on our generation assets, securing certain executive benefits.our fuel supplies may exceed our needs, and could result in us selling the excess. These scenarios could potentially lead to a material adverse impact on our financial results.
We are exposed to risk on both sides of the distribution chain, from fuel to end customer delivery, due to inability to produce energy. If one or more of our generating facilities is not able to produce electricity when required due to operational factors, we may have to forego sales opportunities or fulfill fixed-price sales commitments through the operation of other more
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costly generating facilities or through the purchase of energy in the wholesale market at higher prices. In addition, we are exposed to the risk that available sources of supply may differ from the amount of power demanded by our customers under fixed-price load-serving contracts. During periods of high demand, our power supplies may be insufficient to serve our customers' needs and could require us to purchase additional energy at higher prices. Alternatively, during periods of low demand, our electricity supplies may exceed our customers' needs and potentially result in selling excess energy at lower prices. This could have a material adverse impact on our financial results.
Collateral and Funding Liquidity Risk
Funding liquidity risk relates to the ability to fund current and future obligations of the company given variability in collateral requirements as well as variability around working capital requirements and other cash flows that may affect our liquidity. To assess funding liquidity risk, we distinguish between sources and uses of liquidity. Sources of liquidity include projected net available cash and the unused capacity available from our credit facilities. Uses include expected and contingent collateral requirements as well as any unexpected variation of cash flows from projected levels. We define contingent requirements to be any incremental or decremental requirements to expected requirement levels.
To manage liquidity risk, we quantify sources of liquidity and the expected and contingent uses of liquidity both over a short-term and long-term horizon. Contingent uses of liquidity are determined by stress-testing our portfolio using a simulation of extreme, adverse price stresses and measuring their combined impact on collateral needs and on cash flows related to losses due to market and credit risk. Liquidity stresses related to operational risks (weather, plant outages) and other business risks not directly linked to price moves are assessed on a regular basis using scenario analysis. Results of the liquidity assessment are shared regularly with senior management.
Liquidity risk assessment has been integrated into our strategic planning process. Expected and contingent funding needs implied by the NRC to maintain externally funded trusts for the costs of decommissioning our nuclear power plants. We discuss our nuclear decommissioning trust funds in more detail inNote 1.
A hypothetical 10% decrease in equity prices would result in an approximate $140 million reduction in the fair valuebusiness plans of our financial investmentsvarious business units are first aggregated and compared to available liquidity sources over the planning horizon. Capital and liquidity sources are then allocated to business units based on their business plans, taking into account the cost of providing liquidity. We believe that are classified as trading or available-for-sale securities. In 2007,this integrated view on sources and uses of liquidity allows us to ensure proper funding of the business in accordance with our actual return on pension plan assets was $71.3 million due to advances in the markets in which plan assets are invested. We describe our financial investments in more detail inNote 4, and our pension plans inNote 7.business plan.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
The information required by this item with respect to market risk is set forth inItem 7 of Part II of this Form 10-K under the headingMarket Risk Management.
Item 8. Financial Statements and Supplementary Data
Financial Statements
The management of Constellation Energy Group, Inc. and Baltimore Gas and Electric Company (the "Companies") is responsible for the information and representations in the Companies' financial statements. The Companies prepare the financial statements in accordance with accounting principles generally accepted in the United States of America based upon available facts and circumstances and management's best estimates and judgments of known conditions.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited the financial statements and expressed their opinion on them. They performed their audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).
The Audit Committee of the Board of Directors, which consists of fivefour independent Directors, meets periodically with management, internal auditors, and PricewaterhouseCoopers LLP to review the activities of each in discharging their responsibilities. The internal audit staff and PricewaterhouseCoopers LLP have free access to the Audit Committee.
Management's Report on Internal Control Over Financial
Reporting—Constellation Energy Group, Inc.
The management of Constellation Energy Group, Inc. (Constellation Energy), under the direction of its principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f).
Constellation Energy's system of internal control over financial reporting is designed to provide reasonable assurance to Constellation Energy's management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America.
The management of Constellation Energy conducted an evaluation of the effectiveness of Constellation Energy's internal control over financial reporting using the framework inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). As noted in the COSO framework, an internal control system, no matter how well conceived and operated, can provide only reasonable-not absolute-assurancereasonable, not absolute, assurance to management and the Board of Directors regarding achievement of an entity's financial reporting objectives. Based upon the evaluation under this framework, management concluded that Constellation Energy's internal control over financial reporting was effective as of December 31, 2007.2010.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, has audited the effectiveness of Constellation Energy's internal control over financial reporting as of December 31, 2007,2010, as stated in their report on the next page.
Mayo A. Shattuck III Chairman of the Board, President and Chief Executive Officer | Financial Officer |
Management's Report on Internal Control Over Financial
Reporting—Baltimore Gas and Electric Company
The management of Baltimore Gas and Electric Company (BGE), under the direction of its principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f).
BGE's system of internal control over financial reporting is designed to provide reasonable assurance to BGE's management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America.
The management of BGE conducted an evaluation of the effectiveness of BGE's internal control over financial reporting using the framework inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). As noted in the COSO framework, an internal control system, no matter how well conceived and operated, can provide only reasonable-not absolute-assurancereasonable, not absolute, assurance to management and the Board of Directors regarding achievement of an entity's financial reporting objectives. Based upon the evaluation under this framework, management concluded that BGE's internal control over financial reporting was effective as of December 31, 2007.2010.
This annual report does not include an attestation report of BGE's independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by BGE's independent registered public accounting firm pursuant to temporary rules ofan exemption for non-accelerated filers set forth in the SecuritiesDodd-Frank Wall Street Reform and Exchange Commission that permit BGE to provide only management's report in this annual report.Consumer Protection Act.
Kenneth W. DeFontes, Jr. President and Chief Executive Officer |
REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Constellation Energy Group, Inc.
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a) (1) present fairly, in all material respects, the financial position of Constellation Energy Group, Inc. and its subsidiaries (the Company) at December 31, 20072010 and 2006,2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20072010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a) (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007,2010, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on these financial statements, on the financial statement schedule and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements includeincluded examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed inNote 1 to the consolidated financial statements, in 20072010 the Company changed its method of accounting for uncertain tax positions.and presenting variable interest entities. As discussed inNote 713 to the consolidated financial statements, in 20062008 the Company changed its method of accounting for defined benefit pensionthe measurement of fair value and other postretirement plans. As discussed inNote 1 to the consolidated financial statements, in 2005 the Company changed its method of accounting for conditional asset retirement obligations and for stock based compensation.classifying certain collateral balances.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
We have also previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets and statements of capitalization of Constellation Energy Group, Inc. and its subsidiaries as of December 31, 2005, 2004, and 2003, and the related consolidated statements of income, cash flows, and common shareholders' equity and comprehensive income for the years ended December 31, 2004 and 2003 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Summary of Operations and Summary of Financial Condition of Constellation Energy Group, Inc. and its subsidiaries included in the Selected Financial Data appearing under Item 6 for each of the five years in the period ended December 31, 2007, is fairly stated, in all material respects, in relation to the consolidated financial statements from which it has been derived.
PricewaterhouseCoopers LLP
Baltimore, MarylandFebruary 26, 2008March 1, 2011
To Board of Directors and Shareholder of Baltimore Gas and Electric Company
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a) (1) present fairly, in all material respects, the financial position of Baltimore Gas and Electric Company and its subsidiaries (the Company) at December 31, 20072010 and 2006,2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20072010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a) (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed inNote 1 to the consolidated financial statements, in 20072010 the Company changed its method of accounting for uncertain tax positions.
We have also previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Baltimore Gas and Electric Company and its subsidiaries as of December 31, 2005, 2004 and 2003, and the related consolidated statements of income, cash flows, and comprehensive income for the years ended December 31, 2004 and 2003 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forthpresenting variable interest entities. As discussed in the Summary of Operations and Summary of Financial Condition of Baltimore Gas and Electric Company and its subsidiaries included in the Selected Financial Data appearing under Item 6 for each of the five years in the period ended December 31, 2007, is fairly stated, in all material respects, in relationNote 13 to the consolidated financial statements, from which it has been derived.in 2008 the Company changed its method of accounting for the measurement of fair value.
PricewaterhouseCoopers LLP
Baltimore, MarylandFebruary 26, 2008March 1, 2011
(This page has been left blank intentionally.)
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CONSOLIDATED STATEMENTS OF INCOME (LOSS)
Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, | 2007 | 2006 | 2005 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions, except per share amounts) | ||||||||||
Revenues | |||||||||||
Nonregulated revenues | $ | 17,794.6 | $ | 16,279.0 | $ | 13,970.1 | |||||
Regulated electric revenues | 2,455.6 | 2,115.9 | 2,036.5 | ||||||||
Regulated gas revenues | 943.0 | 890.0 | 961.7 | ||||||||
Total revenues | 21,193.2 | 19,284.9 | 16,968.3 | ||||||||
Expenses | |||||||||||
Fuel and purchased energy expenses | 16,473.9 | 14,930.7 | 13,239.6 | ||||||||
Operating expenses | 2,447.4 | 2,165.8 | 1,900.7 | ||||||||
Impairment losses and other costs | 20.2 | — | — | ||||||||
Workforce reduction costs | 2.3 | 28.2 | 4.4 | ||||||||
Merger-related costs | — | 18.3 | 17.0 | ||||||||
Depreciation, depletion, and amortization | 557.8 | 523.9 | 523.0 | ||||||||
Accretion of asset retirement obligations | 68.3 | 67.6 | 62.0 | ||||||||
Taxes other than income taxes | 288.9 | 290.7 | 277.1 | ||||||||
Total expenses | 19,858.8 | 18,025.2 | 16,023.8 | ||||||||
Gain on Sale of Gas-Fired Plants | — | 73.8 | — | ||||||||
Income from Operations | 1,334.4 | 1,333.5 | 944.5 | ||||||||
Gain on Sales of CEP Equity | 63.3 | 28.7 | — | ||||||||
Other Income, primarily interest income | 158.6 | 66.1 | 65.5 | ||||||||
Fixed Charges | |||||||||||
Interest expense | 311.8 | 329.2 | 306.9 | ||||||||
Interest capitalized and allowance for borrowed funds used during construction | (19.4 | ) | (13.7 | ) | (9.9 | ) | |||||
BGE preference stock dividends | 13.2 | 13.2 | 13.2 | ||||||||
Total fixed charges | 305.6 | 328.7 | 310.2 | ||||||||
Income from Continuing Operations Before Income Taxes | 1,250.7 | 1,099.6 | 699.8 | ||||||||
Income Tax Expense | 428.3 | 351.0 | 163.9 | ||||||||
Income from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles | 822.4 | 748.6 | 535.9 | ||||||||
(Loss) Income from discontinued operations, net of income taxes of$1.5, $107.7, and $61.6, respectively | (0.9 | ) | 187.8 | 94.4 | |||||||
Cumulative effects of changes in accounting principles, net of income taxes of $(4.7) | — | — | (7.2 | ) | |||||||
Net Income | $ | 821.5 | $ | 936.4 | $ | 623.1 | |||||
Earnings Applicable to Common Stock | $ | 821.5 | $ | 936.4 | $ | 623.1 | |||||
Average Shares of Common Stock Outstanding—Basic | 180.2 | 179.4 | 177.5 | ||||||||
Average Shares of Common Stock Outstanding—Diluted | 182.5 | 181.4 | 179.7 | ||||||||
Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles—Basic | $ | 4.56 | $ | 4.17 | $ | 3.02 | |||||
(Loss) Income from discontinued operations | (0.01 | ) | 1.05 | 0.53 | |||||||
Cumulative effects of changes in accounting principles | — | — | (0.04 | ) | |||||||
Earnings Per Common Share—Basic | $ | 4.55 | $ | 5.22 | $ | 3.51 | |||||
Earnings Per Common Share from Continuing Operations and Before Cumulative Effects of Changes in Accounting Principles—Diluted | $ | 4.51 | $ | 4.12 | $ | 2.98 | |||||
(Loss) Income from discontinued operations | (0.01 | ) | 1.04 | 0.53 | |||||||
Cumulative effects of changes in accounting principles | — | — | (0.04 | ) | |||||||
Earnings Per Common Share—Diluted | $ | 4.50 | $ | 5.16 | $ | 3.47 | |||||
Dividends Declared Per Common Share | $ | 1.74 | $ | 1.51 | $ | 1.34 | |||||
See Notes to Consolidated Financial Statements. |
Year Ended December 31, | 2010 | 2009 | 2008 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions, except per share amounts) | ||||||||||
Revenues | |||||||||||
Nonregulated revenues | $ | 10,883.0 | $ | 12,024.3 | $ | 16,057.6 | |||||
Regulated electric revenues | 2,752.1 | 2,820.7 | 2,679.5 | ||||||||
Regulated gas revenues | 704.9 | 753.8 | 1,004.8 | ||||||||
Total revenues | 14,340.0 | 15,598.8 | 19,741.9 | ||||||||
Expenses | |||||||||||
Fuel and purchased energy expenses | 10,001.7 | 11,013.1 | 15,521.3 | ||||||||
Fuel and purchased energy expenses from affiliate | 900.8 | 122.5 | — | ||||||||
Operating expenses | 1,691.1 | 2,228.0 | 2,378.8 | ||||||||
Merger termination and strategic alternatives costs | — | 145.8 | 1,204.4 | ||||||||
Impairment losses and other costs | 2,476.8 | 124.7 | 741.8 | ||||||||
Workforce reduction costs | — | 12.6 | 22.2 | ||||||||
Depreciation, depletion, and amortization | 517.6 | 589.1 | 583.2 | ||||||||
Accretion of asset retirement obligations | 1.9 | 62.3 | 68.4 | ||||||||
Taxes other than income taxes | 263.9 | 290.4 | 301.8 | ||||||||
Total expenses | 15,853.8 | 14,588.5 | 20,821.9 | ||||||||
Equity Investment Earnings (Losses) | 25.0 | (6.1 | ) | 76.4 | |||||||
Gain on Sale of Interest in CENG | — | 7,445.6 | — | ||||||||
Net Gain (Loss) on Divestitures | 245.8 | (468.8 | ) | 25.5 | |||||||
(Loss) Income from Operations | (1,243.0 | ) | 7,981.0 | (978.1 | ) | ||||||
Other Expenses | (76.7 | ) | (140.7 | ) | (69.5 | ) | |||||
Fixed Charges | |||||||||||
Interest expense | 310.8 | 437.2 | 399.1 | ||||||||
Interest capitalized and allowance for borrowed funds used during construction | (33.0 | ) | (87.1 | ) | (50.0 | ) | |||||
Total fixed charges | 277.8 | 350.1 | 349.1 | ||||||||
(Loss) Income from Continuing Operations Before Income Taxes | (1,597.5 | ) | 7,490.2 | (1,396.7 | ) | ||||||
Income Tax (Benefit) Expense | (665.7 | ) | 2,986.8 | (78.3 | ) | ||||||
Net (Loss) Income | (931.8 | ) | 4,503.4 | (1,318.4 | ) | ||||||
Net Income (Loss) Attributable to Noncontrolling Interests and BGE Preference Stock Dividends | 50.8 | 60.0 | (4.0 | ) | |||||||
Net (Loss) Income Attributable to Common Stock | $ | (982.6 | ) | $ | 4,443.4 | $ | (1,314.4 | ) | |||
Average Shares of Common Stock Outstanding—Basic | 200.5 | 199.3 | 179.1 | ||||||||
Average Shares of Common Stock Outstanding—Diluted | 200.5 | 200.3 | 179.1 | ||||||||
(Loss) Earnings Per Common Share—Basic | $ | (4.90 | ) | $ | 22.29 | $ | (7.34 | ) | |||
(Loss) Earnings Per Common Share—Diluted | $ | (4.90 | ) | $ | 22.19 | $ | (7.34 | ) | |||
Dividends Declared Per Common Share | $ | 0.96 | $ | 0.96 | $ | 1.91 | |||||
Constellation Energy Group, Inc. and Subsidiaries
At December 31, | 2007 | 2006 | |||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Assets | |||||||||
Current Assets | |||||||||
Cash and cash equivalents | $ | 1,095.9 | $ | 2,289.1 | |||||
Accounts receivable (net of allowance for uncollectibles of$44.9 and $48.9, respectively) | 4,289.5 | 3,248.3 | |||||||
Fuel stocks | 591.3 | 599.5 | |||||||
Materials and supplies | 207.5 | 200.2 | |||||||
Derivative assets | 961.2 | 1,556.5 | |||||||
Unamortized energy contract assets | 32.0 | 35.2 | |||||||
Deferred income taxes | 300.7 | 674.3 | |||||||
Other | 410.9 | 497.0 | |||||||
Total current assets | 7,889.0 | 9,100.1 | |||||||
Investments and Other Noncurrent Assets | |||||||||
Nuclear decommissioning trust funds | 1,330.8 | 1,240.1 | |||||||
Other investments | 542.2 | 308.6 | |||||||
Regulatory assets (net) | 576.2 | 389.0 | |||||||
Goodwill | 261.3 | 157.6 | |||||||
Derivative assets | 1,030.2 | 949.1 | |||||||
Unamortized energy contract assets | 178.3 | 123.6 | |||||||
Other | 370.6 | 311.4 | |||||||
Total investments and other noncurrent assets | 4,289.6 | 3,479.4 | |||||||
Property, Plant and Equipment | |||||||||
Nonregulated property, plant and equipment | 8,087.0 | 7,587.6 | |||||||
Regulated property, plant and equipment | 6,051.2 | 5,752.9 | |||||||
Nuclear fuel (net of amortization) | 374.3 | 339.9 | |||||||
Accumulated depreciation | (4,745.4 | ) | (4,458.3 | ) | |||||
Net property, plant and equipment | 9,767.1 | 9,222.1 | |||||||
Total Assets | $ | 21,945.7 | $ | 21,801.6 | |||||
See Notes to Consolidated Financial Statements. | |||||||||
Certain prior-year amounts have been reclassified to conform with the current year's presentation. |
CONSOLIDATED BALANCE SHEETS
Constellation Energy Group, Inc. and Subsidiaries
At December 31, | 2007 | 2006 | ||||||
---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||
Liabilities and Equity | ||||||||
Current Liabilities | ||||||||
Short-term borrowings | $ | 14.0 | $ | — | ||||
Current portion of long-term debt | 380.6 | 878.8 | ||||||
Accounts payable and accrued liabilities | 2,630.1 | 2,137.2 | ||||||
Customer deposits and collateral | 347.2 | 347.2 | ||||||
Derivative liabilities | 1,137.1 | 2,411.7 | ||||||
Unamortized energy contract liabilities | 392.2 | 378.3 | ||||||
Accrued expenses | 528.5 | 619.8 | ||||||
Other | 427.5 | 349.7 | ||||||
Total current liabilities | 5,857.2 | 7,122.7 | ||||||
Deferred Credits and Other Noncurrent Liabilities | ||||||||
Deferred income taxes | 1,588.5 | 1,435.8 | ||||||
Asset retirement obligations | 917.6 | 974.8 | ||||||
Derivative liabilities | 1,118.9 | 1,099.7 | ||||||
Unamortized energy contract liabilities | 1,218.6 | 958.0 | ||||||
Defined benefit obligations | 828.6 | 928.3 | ||||||
Deferred investment tax credits | 50.5 | 57.2 | ||||||
Other | 155.9 | 109.0 | ||||||
Total deferred credits and other noncurrent liabilities | 5,878.6 | 5,562.8 | ||||||
Capitalization (See Consolidated Statements of Capitalization) | ||||||||
Long-term debt | 4,660.5 | 4,222.3 | ||||||
Minority interests | 19.2 | 94.5 | ||||||
BGE preference stock not subject to mandatory redemption | 190.0 | 190.0 | ||||||
Common shareholders' equity | 5,340.2 | 4,609.3 | ||||||
Total capitalization | 10,209.9 | 9,116.1 | ||||||
Commitments, Guarantees, and Contingencies (see Note 12) | ||||||||
Total Liabilities and Equity | $ | 21,945.7 | $ | 21,801.6 | ||||
See Notes to Consolidated Financial Statements. | ||||||||
Certain prior-year amounts have been reclassified to conform with the current year's presentation. |
CONSOLIDATED STATEMENTS OF CASH FLOWS
Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, | 2007 | 2006 | 2005 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||||
Cash Flows From Operating Activities | |||||||||||||
Net income | $ | 821.5 | $ | 936.4 | $ | 623.1 | |||||||
Adjustments to reconcile to net cash provided by operating activities | |||||||||||||
Gain on sales of gas-fired plants and discontinued operations | — | (191.4 | ) | (13.8 | ) | ||||||||
Cumulative effects of changes in accounting principles | — | — | 7.2 | ||||||||||
Depreciation, depletion, and amortization | 460.4 | 545.1 | 606.5 | ||||||||||
Accretion of asset retirement obligations | 68.3 | 67.6 | 62.1 | ||||||||||
Deferred income taxes | 226.2 | 128.0 | 136.9 | ||||||||||
Investment tax credit adjustments | (6.7 | ) | (6.9 | ) | (7.1 | ) | |||||||
Deferred fuel costs | (248.0 | ) | (348.5 | ) | (11.9 | ) | |||||||
Defined benefit obligation expense | 111.8 | 129.7 | 94.2 | ||||||||||
Defined benefit obligation payments | (165.4 | ) | (89.2 | ) | (90.8 | ) | |||||||
Impairment losses and other costs | 20.2 | — | — | ||||||||||
Gains on sale of CEP equity | (63.3 | ) | (28.7 | ) | — | ||||||||
Equity in earnings of affiliates less than dividends received | 45.3 | 27.6 | 38.7 | ||||||||||
Derivative power sales contracts classified as financing activities under SFAS No. 149 | 32.2 | 2.6 | (72.6 | ) | |||||||||
Changes in | |||||||||||||
Accounts receivable | (778.2 | ) | (653.7 | ) | (961.2 | ) | |||||||
Derivative assets and liabilities | (138.2 | ) | (286.1 | ) | (88.2 | ) | |||||||
Materials, supplies, and fuel stocks | (66.4 | ) | (267.2 | ) | (250.3 | ) | |||||||
Other current assets | 145.1 | 240.6 | (277.1 | ) | |||||||||
Accounts payable and accrued liabilities | 448.8 | 380.5 | 282.8 | ||||||||||
Other current liabilities | 15.7 | (91.8 | ) | 546.4 | |||||||||
Other | (1.5 | ) | 30.7 | 2.3 | |||||||||
Net cash provided by operating activities | 927.8 | 525.3 | 627.2 | ||||||||||
Cash Flows From Investing Activities | |||||||||||||
Investments in property, plant and equipment | (1,295.7 | ) | (962.9 | ) | (760.0 | ) | |||||||
Asset acquisitions and business combinations, net of cash acquired | (347.5 | ) | (137.6 | ) | (237.2 | ) | |||||||
Investments in nuclear decommissioning trust fund securities | (659.5 | ) | (492.5 | ) | (370.8 | ) | |||||||
Proceeds from nuclear decommissioning trust fund securities | 650.7 | 483.7 | 353.2 | ||||||||||
Net proceeds from sale of gas-fired plants and discontinued operations | — | 1,630.7 | 289.4 | ||||||||||
Issuances of loans receivable | (19.0 | ) | (65.4 | ) | (82.8 | ) | |||||||
Sale of investments and other assets | 13.9 | 43.9 | 14.4 | ||||||||||
Contract and portfolio acquisitions | (474.2 | ) | (2.3 | ) | (336.2 | ) | |||||||
(Increase) decrease in restricted funds | (109.9 | ) | 7.7 | (4.0 | ) | ||||||||
Other investments | (45.3 | ) | 54.8 | (40.0 | ) | ||||||||
Net cash (used in) provided by investing activities | (2,286.5 | ) | 560.1 | (1,174.0 | ) | ||||||||
Cash Flows From Financing Activities | |||||||||||||
Net issuance (maturity) of short-term borrowings | 14.0 | (0.7 | ) | 10.7 | |||||||||
Proceeds from issuance of | |||||||||||||
Common stock | 65.1 | 84.4 | 96.9 | ||||||||||
Long-term debt | 698.2 | 852.0 | 12.0 | ||||||||||
Proceeds from initial public offering of CEP | — | 101.3 | — | ||||||||||
Common stock dividends paid | (306.0 | ) | (264.0 | ) | (228.8 | ) | |||||||
Reacquisition of common stock | (409.5 | ) | — | — | |||||||||
Proceeds from contract and portfolio acquisitions | 847.8 | 221.3 | 1,026.9 | ||||||||||
Repayment of long-term debt | (745.3 | ) | (609.1 | ) | (362.3 | ) | |||||||
Derivative power sales contracts classified as financing activities under SFAS No. 149 | (32.2 | ) | (2.6 | ) | 72.6 | ||||||||
Other | 33.4 | 8.1 | 25.5 | ||||||||||
Net cash provided by financing activities | 165.5 | 390.7 | 653.5 | ||||||||||
Net (Decrease) Increase in Cash and Cash Equivalents | (1,193.2 | ) | 1,476.1 | 106.7 | |||||||||
Cash and Cash Equivalents at Beginning of Year | 2,289.1 | 813.0 | 706.3 | ||||||||||
Cash and Cash Equivalents at End of Year | $ | 1,095.9 | $ | 2,289.1 | $ | 813.0 | |||||||
Other Cash Flow Information: | |||||||||||||
Cash paid during the year for: | |||||||||||||
Interest (net of amounts capitalized) | $ | 291.8 | $ | 304.7 | $ | 301.3 | |||||||
Income taxes | $ | 282.4 | $ | 109.3 | $ | 115.3 |
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOMEBALANCE SHEETS
Constellation Energy Group, Inc. and Subsidiaries
| | | | Accumulated Other Comprehensive Loss | | ||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Common Stock | Retained Earnings | Total Amount | ||||||||||||||||
Year Ended December 31, 2007, 2006, and 2005 | Shares | Amount | |||||||||||||||||
| (Dollar amounts in millions, number of shares in thousands) | ||||||||||||||||||
Balance at December 31, 2004 | 176,333 | $ | 2,502.5 | $ | 2,425.9 | $ | (201.5 | ) | $ | 4,726.9 | |||||||||
Comprehensive Income | |||||||||||||||||||
Net income | 623.1 | 623.1 | |||||||||||||||||
Other comprehensive income | |||||||||||||||||||
Hedging instruments: | |||||||||||||||||||
Reclassification of net gains on hedging instruments from OCI to net income, net of taxes of $492.2 | (794.6 | ) | (794.6 | ) | |||||||||||||||
Net unrealized gain on hedging instruments, net of taxes of $335.9 | 534.7 | 534.7 | |||||||||||||||||
Available-for-sale securities: | |||||||||||||||||||
Reclassification of net gains on securities from OCI to net income, net of taxes of $1.2 | (1.8 | ) | (1.8 | ) | |||||||||||||||
Net unrealized gain on securities, net of taxes of $15.7 | 23.8 | 23.8 | |||||||||||||||||
Minimum pension liability, net of taxes of $50.4 | (77.1 | ) | (77.1 | ) | |||||||||||||||
Net unrealized gain on foreign currency translation | 1.0 | 1.0 | |||||||||||||||||
Total Comprehensive Income | 623.1 | (314.0 | ) | 309.1 | |||||||||||||||
Common stock dividend declared ($1.34 per share) | (238.4 | ) | (238.4 | ) | |||||||||||||||
Common stock issued and share-based awards | 1,968 | 118.3 | 118.3 | ||||||||||||||||
Other | (0.4 | ) | (0.4 | ) | |||||||||||||||
Balance at December 31, 2005 | 178,301 | 2,620.8 | 2,810.2 | (515.5 | ) | 4,915.5 | |||||||||||||
Comprehensive Income | |||||||||||||||||||
Net income | 936.4 | 936.4 | |||||||||||||||||
Other comprehensive income | |||||||||||||||||||
Hedging instruments: | |||||||||||||||||||
Reclassification of net losses on hedging instruments from OCI to net income, net of taxes of $375.6 | 620.8 | 620.8 | |||||||||||||||||
Net unrealized loss on hedging instruments, net of taxes of $1,025.8 | (1,683.4 | ) | (1,683.4 | ) | |||||||||||||||
Available-for-sale securities: | |||||||||||||||||||
Reclassification of net gains on securities from OCI to net income, net of taxes of $0.1 | (0.2 | ) | (0.2 | ) | |||||||||||||||
Net unrealized gain on securities, net of taxes of $45.5 | 69.7 | 69.7 | |||||||||||||||||
Minimum pension liability, net of taxes of $49.6 | 75.6 | 75.6 | |||||||||||||||||
Net unrealized loss on foreign currency translation | (1.1 | ) | (1.1 | ) | |||||||||||||||
Total Comprehensive Income | 936.4 | (918.6 | ) | 17.8 | |||||||||||||||
Effect of adoption of SFAS No. 158, net of taxes of $111.3 | (169.5 | ) | (169.5 | ) | |||||||||||||||
Common stock dividend declared ($1.51 per share) | (272.6 | ) | (272.6 | ) | |||||||||||||||
Common stock issued and share-based awards | 2,218 | 117.8 | 117.8 | ||||||||||||||||
Other | 0.3 | 0.3 | |||||||||||||||||
Balance at December 31, 2006 | 180,519 | 2,738.6 | 3,474.3 | (1,603.6 | ) | 4,609.3 | |||||||||||||
Comprehensive Income | |||||||||||||||||||
Net income | 821.5 | 821.5 | |||||||||||||||||
Other comprehensive income | |||||||||||||||||||
Hedging instruments: | |||||||||||||||||||
Reclassification of net losses on hedging instruments from OCI to net income, net of taxes of $682.3 | 1,124.8 | 1,124.8 | |||||||||||||||||
Net unrealized loss on hedging instruments, net of taxes of $408.2 | (671.1 | ) | (671.1 | ) | |||||||||||||||
Available-for-sale securities: | |||||||||||||||||||
Reclassification of net gains on securities from OCI to net income, net of taxes of $1.0 | (1.6 | ) | (1.6 | ) | |||||||||||||||
Net unrealized gain on securities, net of taxes of $25.5 | 26.5 | 26.5 | |||||||||||||||||
Defined benefit plans: | |||||||||||||||||||
Net gain arising during period, net of taxes of $7.8 | 11.6 | 11.6 | |||||||||||||||||
Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes of $15.9 | 24.6 | 24.6 | |||||||||||||||||
Net unrealized gain on foreign currency translation, net of taxes of $1.8 | 7.0 | 7.0 | |||||||||||||||||
Other | (10.8 | ) | (10.8 | ) | |||||||||||||||
Total Comprehensive Income | 821.5 | 511.0 | 1,332.5 | ||||||||||||||||
Effect of adoption of FIN 48 | (7.3 | ) | (7.3 | ) | |||||||||||||||
Common stock dividend declared ($1.74 per share) | (368.4 | ) | (368.4 | ) | |||||||||||||||
Common stock issued and share-based awards | 1,789 | 184.2 | 184.2 | ||||||||||||||||
Common stock purchased | (1,847 | ) | (159.5 | ) | (159.5 | ) | |||||||||||||
Common stock purchased and retired | (2,024 | ) | (250.0 | ) | (250.0 | ) | |||||||||||||
Other | (0.6 | ) | (0.6 | ) | |||||||||||||||
Balance at December 31, 2007 | 178,437 | $ | 2,513.3 | $ | 3,919.5 | $ | (1,092.6 | ) | $ | 5,340.2 | |||||||||
At December 31, | 2010 | 2009 | |||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Assets | |||||||||
Current Assets | |||||||||
Cash and cash equivalents | $ | 2,028.5 | $ | 3,440.0 | |||||
Accounts receivable (net of allowance for uncollectibles of$85.0 and $80.4, respectively) | 2,059.2 | 1,778.2 | |||||||
Accounts receivable—consolidated variable interest entities (net of allowance for uncollectibles of$87.9 and $80.2, respectively) | 308.9 | 359.4 | |||||||
Income taxes receivable | 152.7 | — | |||||||
Fuel stocks | 361.1 | 314.9 | |||||||
Materials and supplies | 104.3 | 93.3 | |||||||
Derivative assets | 534.4 | 639.1 | |||||||
Unamortized energy contract assets (includes$400.9 and $371.3, respectively, related to CENG) | 544.7 | 436.5 | |||||||
Restricted cash | 52.0 | 2.7 | |||||||
Restricted cash—consolidated variable interest entities | 52.3 | 24.3 | |||||||
Deferred income taxes | — | 127.9 | |||||||
Other | 254.5 | 244.4 | |||||||
Total current assets | 6,452.6 | 7,460.7 | |||||||
Investments and Other Noncurrent Assets | |||||||||
Investment in CENG | 2,991.1 | 5,222.9 | |||||||
Other investments | 189.9 | 424.3 | |||||||
Regulatory assets (net) | 374.1 | 414.4 | |||||||
Goodwill | 77.0 | 25.5 | |||||||
Derivative assets | 258.9 | 633.9 | |||||||
Unamortized energy contract assets (includes$— and $400.9, respectively, related to CENG) | 109.8 | 604.7 | |||||||
Other | 286.3 | 304.2 | |||||||
Total investments and other noncurrent assets | 4,287.1 | 7,629.9 | |||||||
Property, Plant and Equipment | |||||||||
Nonregulated property, plant and equipment | 6,387.2 | 5,784.6 | |||||||
Regulated property, plant and equipment | 7,201.7 | 6,749.9 | |||||||
Accumulated depreciation | (4,310.1 | ) | (4,080.7 | ) | |||||
Net property, plant and equipment | 9,278.8 | 8,453.8 | |||||||
Total Assets | $ | 20,018.5 | $ | 23,544.4 | |||||
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
CONSOLIDATED STATEMENTS OF CAPITALIZATIONBALANCE SHEETS
Constellation Energy Group, Inc. and Subsidiaries
At December 31, | 2007 | 2006 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Long-Term Debt | ||||||||||
Long-term debt of Constellation Energy | ||||||||||
6.35% Fixed-Rate Notes, due April 1, 2007 | $ | — | $ | 600.0 | ||||||
6.125% Fixed-Rate Notes, due September 1, 2009 | 500.0 | 500.0 | ||||||||
7.00% Fixed-Rate Notes, due April 1, 2012 | 700.0 | 700.0 | ||||||||
4.55% Fixed-Rate Notes, due June 15, 2015 | 550.0 | 550.0 | ||||||||
7.60% Fixed-Rate Notes, due April 1, 2032 | 700.0 | 700.0 | ||||||||
Fair Value of Interest Rate Swaps | 11.8 | (7.1 | ) | |||||||
Total long-term debt of Constellation Energy | 2,461.8 | 3,042.9 | ||||||||
Long-term debt of nonregulated businesses | ||||||||||
Tax-exempt debt transferred from BGE effective July 1, 2000 | ||||||||||
Pollution control loan, due July 1, 2011 | 36.0 | 36.0 | ||||||||
Port facilities loan, due June 1, 2013 | 48.0 | 48.0 | ||||||||
4.10% Pollution control loan, due July 1, 2014 | 20.0 | 20.0 | ||||||||
Economic development loan, due December 1, 2018 | 35.0 | 35.0 | ||||||||
Floating-rate pollution control loan, due June 1, 2027 | 8.8 | 8.8 | ||||||||
Tax-exempt variable rate notes, due April 1, 2024 | 75.0 | 75.0 | ||||||||
Tax-exempt variable rate notes, due December 1, 2025 | 47.0 | 47.0 | ||||||||
Tax-exempt variable rate notes, due December 1, 2037 | 65.0 | — | ||||||||
District Cooling facilities loan, due December 1, 2031 | 25.0 | 25.0 | ||||||||
CEP credit facility loan, due October 31, 2010 | — | 22.0 | ||||||||
5.00% Mortgage note, due June 15, 2010 | 3.6 | 7.5 | ||||||||
4.25% Mortgage note, due March 15, 2009 | 0.8 | 1.3 | ||||||||
7.3% Fixed Rate Note, due June 1, 2012 | 1.8 | 1.8 | ||||||||
South Carolina synthetic fuel facility loan, due January 15, 2008 (imputed interest rate of 3.47%) | 3.0 | 20.0 | ||||||||
Total long-term debt of nonregulated businesses | 369.0 | 347.4 | ||||||||
First Refunding Mortgage Bonds of BGE | ||||||||||
7.50% Series, due January 15, 2007 | — | 121.4 | ||||||||
6.625% Series, due March 15, 2008 | 119.7 | 123.1 | ||||||||
Total First Refunding Mortgage Bonds of BGE | 119.7 | 244.5 | ||||||||
Other long-term debt of BGE | ||||||||||
5.90% Notes, due October 1, 2016 | 300.0 | 300.0 | ||||||||
5.20% Notes, due June 15, 2033 | 200.0 | 200.0 | ||||||||
6.35% Notes, due October 1, 2036 | 400.0 | 400.0 | ||||||||
Medium-term notes, Series E | 174.5 | 174.5 | ||||||||
Medium-term notes, Series G | 140.0 | 140.0 | ||||||||
Total other long-term debt of BGE | 1,214.5 | 1,214.5 | ||||||||
6.20% deferrable interest subordinated debentures due October 15, 2043 to BGE wholly owned BGE Capital Trust II relating to trust preferred securities | 257.7 | 257.7 | ||||||||
5.683% Rate stabilization bonds due April 1, 2017 | 623.2 | — | ||||||||
Unamortized discount and premium | (4.8 | ) | (5.9 | ) | ||||||
Current portion of long-term debt | (380.6 | ) | (878.8 | ) | ||||||
Total long-term debt | $ | 4,660.5 | $ | 4,222.3 | ||||||
At December 31, | 2010 | 2009 | |||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Liabilities and Equity | |||||||||
Current Liabilities | |||||||||
Short-term borrowings | $ | 32.4 | $ | 46.0 | |||||
Current portion of long-term debt | 245.6 | 0.4 | |||||||
Current portion of long-term debt—consolidated variable interest entities | 59.7 | 56.5 | |||||||
Accounts payable | 1,072.6 | 916.3 | |||||||
Accounts payable—consolidated variable interest entities | 189.8 | 234.2 | |||||||
Customer deposits and collateral | 87.2 | 103.3 | |||||||
Derivative liabilities | 622.3 | 632.6 | |||||||
Unamortized energy contract liabilities | 130.5 | 390.1 | |||||||
Deferred income taxes | 56.5 | — | |||||||
Accrued taxes | 71.0 | 877.3 | |||||||
Accrued expenses | 358.1 | 409.8 | |||||||
Other | 351.5 | 374.2 | |||||||
Total current liabilities | 3,277.2 | 4,040.7 | |||||||
Deferred Credits and Other Noncurrent Liabilities | |||||||||
Deferred income taxes | 2,489.8 | 3,205.5 | |||||||
Asset retirement obligations | 32.3 | 29.3 | |||||||
Derivative liabilities | 353.0 | 674.1 | |||||||
Unamortized energy contract liabilities | 411.1 | 653.7 | |||||||
Defined benefit obligations | 574.7 | 743.9 | |||||||
Deferred investment tax credits | 27.6 | 32.0 | |||||||
Other | 296.0 | 388.8 | |||||||
Total deferred credits and other noncurrent liabilities | 4,184.5 | 5,727.3 | |||||||
Long-term Debt, Net of Current Portion | 4,054.2 | 4,359.6 | |||||||
Long-term Debt, Net of Current Portion—consolidated variable interest entities | 394.6 | 454.4 | |||||||
Equity | |||||||||
Common shareholders' equity | 7,829.2 | 8,697.1 | |||||||
BGE preference stock not subject to mandatory redemption | 190.0 | 190.0 | |||||||
Noncontrolling interests | 88.8 | 75.3 | |||||||
Total equity | 8,108.0 | 8,962.4 | |||||||
Commitments, Guarantees, and Contingencies (see Note 12) | |||||||||
Total Liabilities and Equity | $ | 20,018.5 | $ | 23,544.4 | |||||
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
77
CONSOLIDATED STATEMENTS OF CASH FLOWS
Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, | 2010 | 2009 | 2008 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||||
Cash Flows From Operating Activities | |||||||||||||
Net (loss) income | $ | (931.8 | ) | $ | 4,503.4 | $ | (1,318.4 | ) | |||||
Adjustments to reconcile to net cash provided by (used in) operating activities | |||||||||||||
Depreciation, depletion, and amortization | 517.6 | 589.1 | 583.2 | ||||||||||
Amortization of nuclear fuel | — | 117.9 | 123.9 | ||||||||||
Amortization of energy contracts and derivatives designated as hedges | 319.6 | (138.4 | ) | (256.3 | ) | ||||||||
All other amortization | 33.3 | 135.7 | 40.5 | ||||||||||
Accretion of asset retirement obligations | 1.9 | 62.3 | 68.4 | ||||||||||
Deferred income taxes | (716.4 | ) | 1,846.9 | (122.8 | ) | ||||||||
Investment tax credit adjustments | (4.5 | ) | (12.1 | ) | (6.4 | ) | |||||||
Deferred fuel costs | 67.4 | 68.9 | 52.0 | ||||||||||
Defined benefit obligation expense | 99.5 | 85.3 | 99.6 | ||||||||||
Defined benefit obligation payments | (324.0 | ) | (372.5 | ) | (120.4 | ) | |||||||
Merger termination and strategic alternatives costs | — | 128.2 | 541.8 | ||||||||||
Workforce reduction costs | — | 12.6 | 22.2 | ||||||||||
Impairment losses and other costs | 2,476.8 | 124.7 | 741.8 | ||||||||||
Impairment losses on nuclear decommissioning trust assets | — | 62.6 | 165.0 | ||||||||||
Gain on sale of 49.99% membership interest in CENG | — | (7,445.6 | ) | — | |||||||||
(Gain) loss on divestitures | (245.8 | ) | 468.8 | (38.1 | ) | ||||||||
Gains on termination of contracts | (76.8 | ) | — | (73.1 | ) | ||||||||
Accrual of BGE residential customer credit | — | 112.4 | — | ||||||||||
Equity in earnings of affiliates less than dividends received | 14.1 | 15.5 | 6.3 | ||||||||||
Derivative contracts classified as financing activities | 186.0 | 1,138.3 | (107.2 | ) | |||||||||
Changes in working capital | |||||||||||||
Accounts receivable, excluding margin | (236.5 | ) | 543.3 | 606.7 | |||||||||
Derivative assets and liabilities, excluding collateral | 449.9 | 425.3 | (757.9 | ) | |||||||||
Net collateral and margin | 44.2 | 1,522.8 | (960.3 | ) | |||||||||
Materials, supplies, and fuel stocks | 0.1 | 220.6 | (33.5 | ) | |||||||||
Other current assets | (150.0 | ) | 217.2 | (95.4 | ) | ||||||||
Accounts payable and accrued liabilities | 80.0 | (1,105.0 | ) | (225.8 | ) | ||||||||
Liability for unrecognized tax benefits | (66.6 | ) | 102.1 | 79.7 | |||||||||
Accrued taxes and other current liabilities | (1,028.4 | ) | 788.8 | (238.1 | ) | ||||||||
Other | 1.7 | 171.7 | (38.5 | ) | |||||||||
Net cash provided by (used in) operating activities | 511.3 | 4,390.8 | (1,261.1 | ) | |||||||||
Cash Flows From Investing Activities | |||||||||||||
Investments in property, plant and equipment | (995.6 | ) | (1,529.7 | ) | (1,934.1 | ) | |||||||
Asset acquisitions and business combinations, net of cash acquired | (445.8 | ) | (41.1 | ) | (315.3 | ) | |||||||
Investments in nuclear decommissioning trust fund securities | — | (385.2 | ) | (440.6 | ) | ||||||||
Proceeds from nuclear decommissioning trust fund securities | — | 366.5 | 421.9 | ||||||||||
Investments in joint ventures | — | (201.6 | ) | — | |||||||||
Proceeds from sale of 49.99% membership interest in CENG | — | 3,528.7 | — | ||||||||||
Proceeds from sales of investments and other assets | 244.0 | 88.3 | 446.3 | ||||||||||
Proceeds from investment tax credits and grants related to renewable energy investments | 56.5 | — | — | ||||||||||
Contract and portfolio acquisitions | (208.3 | ) | (2,153.7 | ) | — | ||||||||
(Increase) decrease in restricted funds | (60.3 | ) | 1,003.3 | (942.8 | ) | ||||||||
Other | (35.7 | ) | 0.1 | 21.7 | |||||||||
Net cash (used in) provided by investing activities | (1,445.2 | ) | 675.6 | (2,742.9 | ) | ||||||||
Cash Flows From Financing Activities | |||||||||||||
Net (maturity) issuance of short-term borrowings | (13.6 | ) | (809.7 | ) | 813.7 | ||||||||
Proceeds from issuance of common stock | 14.0 | 33.9 | 17.6 | ||||||||||
Proceeds from issuance of long-term debt | 550.0 | 136.1 | 3,211.4 | ||||||||||
Common stock dividends paid | (183.3 | ) | (228.0 | ) | (336.3 | ) | |||||||
Reacquisition of common stock | — | — | (16.2 | ) | |||||||||
BGE preference stock dividends paid | (13.2 | ) | (13.2 | ) | (13.2 | ) | |||||||
Proceeds from contract and portfolio acquisitions | 52.2 | 2,263.1 | — | ||||||||||
Repayment of long-term debt | (664.5 | ) | (1,986.8 | ) | (577.4 | ) | |||||||
Derivative contracts classified as financing activities | (186.0 | ) | (1,138.3 | ) | 107.2 | ||||||||
Debt and credit facility costs | (32.8 | ) | (98.4 | ) | (104.8 | ) | |||||||
Other | (0.4 | ) | 12.7 | 8.3 | |||||||||
Net cash (used in) provided by financing activities | (477.6 | ) | (1,828.6 | ) | 3,110.3 | ||||||||
Net (Decrease) Increase in Cash and Cash Equivalents | (1,411.5 | ) | 3,237.8 | (893.7 | ) | ||||||||
Cash and Cash Equivalents at Beginning of Year | 3,440.0 | 202.2 | 1,095.9 | ||||||||||
Cash and Cash Equivalents at End of Year | $ | 2,028.5 | $ | 3,440.0 | $ | 202.2 | |||||||
Other Cash Flow Information: | |||||||||||||
Cash paid during the year for: | |||||||||||||
Interest (net of amounts capitalized) | $ | 289.5 | $ | 369.5 | $ | 341.4 | |||||||
Income taxes | $ | 1,044.2 | $ | 57.1 | $ | 119.2 |
See Notes to Consolidated Financial Statements.
continued on next page
78
CONSOLIDATED STATEMENTS OF CAPITALIZATIONCOMMON SHAREHOLDERS' EQUITY AND COMPREHENISVE INCOME (LOSS)
Constellation Energy Group, Inc. and Subsidiaries
At December 31, | 2007 | 2006 | ||||||
---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||
Minority Interests | $ | 19.2 | $ | 94.5 | ||||
BGE Preference Stock | ||||||||
Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized 7.125%, 1993 Series, 400,000 shares outstanding, callable at $102.14 per share until June 30, 2008, and at lesser amounts thereafter | 40.0 | 40.0 | ||||||
6.97%, 1993 Series, 500,000 shares outstanding, callable at $102.09 per share until September 30, 2008, and at lesser amounts thereafter | 50.0 | 50.0 | ||||||
6.70%, 1993 Series, 400,000 shares outstanding, callable at $102.01 per share until December 31, 2008, and at lesser amounts thereafter | 40.0 | 40.0 | ||||||
6.99%, 1995 Series, 600,000 shares outstanding, callable at $102.80 per share until September 30, 2008, and at lesser amounts thereafter | 60.0 | 60.0 | ||||||
Total preference stock not subject to mandatory redemption | 190.0 | 190.0 | ||||||
Common Shareholders' Equity | ||||||||
Common stock without par value, 250,000,000 shares authorized; 178,437,208 and 180,519,180 shares issued and outstanding at December 31, 2007 and 2006, respectively. (At December 31, 2007, 9,244,969 shares were reserved for the long-term incentive plans, 7,208,691 shares were reserved for the Shareholder Investment Plan, 1,520,000 shares were reserved for the continuous offering programs, and 1,508,553 shares were reserved for the employee savings plan.) | 2,513.3 | 2,738.6 | ||||||
Retained earnings | 3,919.5 | 3,474.3 | ||||||
Accumulated other comprehensive loss | (1,092.6 | ) | (1,603.6 | ) | ||||
Total common shareholders' equity | 5,340.2 | 4,609.3 | ||||||
Total Capitalization | $ | 10,209.9 | $ | 9,116.1 | ||||
| | | | Accumulated Other Comprehensive Loss | | | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Years Ended December 31, 2010, 2009, and 2008 | Common Stock | Retained Earnings | Noncontrolling Interests | Total Amount | ||||||||||||||||||
Shares | Amount | |||||||||||||||||||||
| (Dollar amounts in millions, number of shares in thousands) | |||||||||||||||||||||
Balance at December 31, 2007 | 178,437 | $ | 2,513.3 | $ | 3,919.5 | $ | (1,092.6 | ) | $ | 209.2 | $ | 5,549.4 | ||||||||||
Increase in noncontrolling interests from consolidation of a VIE | 18.1 | 18.1 | ||||||||||||||||||||
Comprehensive Loss | ||||||||||||||||||||||
Net loss | (1,314.4 | ) | (4.0 | ) | (1,318.4 | ) | ||||||||||||||||
Other comprehensive loss | ||||||||||||||||||||||
Hedging instruments: | ||||||||||||||||||||||
Reclassification of net losses on hedging instruments from OCI to net income, net of taxes of $(120.2) | 200.6 | 200.6 | ||||||||||||||||||||
Net unrealized loss on hedging instruments, net of taxes of $561.6 | (875.3 | ) | (875.3 | ) | ||||||||||||||||||
Available-for-sale securities: | ||||||||||||||||||||||
Reclassification of net losses on securities from OCI to net income, net of taxes of $(79.1) | 81.7 | 81.7 | ||||||||||||||||||||
Net unrealized losses on securities, net of taxes of $189.8 | (197.5 | ) | (197.5 | ) | ||||||||||||||||||
Defined benefit plans: | ||||||||||||||||||||||
Prior service cost arising during period, net of taxes of $4.9 | (7.2 | ) | (7.2 | ) | ||||||||||||||||||
Net loss arising during period, net of taxes of $229.2 | (339.9 | ) | (339.9 | ) | ||||||||||||||||||
Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes of $(14.9) | 21.3 | 21.3 | ||||||||||||||||||||
Net unrealized loss on foreign currency translation, net of taxes of $0.1 | (3.1 | ) | (3.1 | ) | ||||||||||||||||||
Other | 0.2 | 0.2 | ||||||||||||||||||||
Total Comprehensive Loss | (1,314.4 | ) | (1,119.2 | ) | (4.0 | ) | (2,437.6 | ) | ||||||||||||||
Effect of adoption of fair value measurement accounting standard | 0.9 | 0.9 | ||||||||||||||||||||
BGE preference stock dividends | (13.2 | ) | (13.2 | ) | ||||||||||||||||||
Common stock dividend declared ($1.91 per share) | (341.3 | ) | (341.3 | ) | ||||||||||||||||||
Common stock issued and share-based awards * | 21,406 | 667.3 | (35.8 | ) | 631.5 | |||||||||||||||||
Common stock purchased | (200 | ) | (16.1 | ) | (16.1 | ) | ||||||||||||||||
Common stock purchased and retired | (514 | ) | — | — | ||||||||||||||||||
Other | (0.2 | ) | (0.2 | ) | ||||||||||||||||||
Balance at December 31, 2008 | 199,129 | 3,164.5 | 2,228.7 | (2,211.8 | ) | 210.1 | 3,391.5 | |||||||||||||||
Contribution from noncontrolling interest | 8.0 | 8.0 | ||||||||||||||||||||
Other noncontrolling interest activity | 0.4 | 0.4 | ||||||||||||||||||||
Comprehensive Income | ||||||||||||||||||||||
Net income | 4,443.4 | 60.0 | 4,503.4 | |||||||||||||||||||
Other comprehensive income | ||||||||||||||||||||||
Hedging instruments: | ||||||||||||||||||||||
Reclassification of net losses on hedging instruments from OCI to net income, net of taxes of $(898.5) | 1,499.4 | 1,499.4 | ||||||||||||||||||||
Net unrealized loss on hedging instruments, net of taxes of $251.2 | (474.7 | ) | (474.7 | ) | ||||||||||||||||||
Available-for-sale securities: | ||||||||||||||||||||||
Reclassification of net losses on securities from OCI to net income, net of taxes of $(24.6) | 25.4 | 25.4 | ||||||||||||||||||||
Net unrealized gains on securities, net of taxes of $(78.2) | 77.7 | 77.7 | ||||||||||||||||||||
Defined benefit plans: | ||||||||||||||||||||||
Prior service cost arising during period, net of taxes of $1.0 | (1.5 | ) | (1.5 | ) | ||||||||||||||||||
Net gains arising during period, net of taxes of $(23.9) | 26.9 | 26.9 | ||||||||||||||||||||
Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes of $(19.8) | 30.3 | 30.3 | ||||||||||||||||||||
Deconsolidation of CENG joint venture: | ||||||||||||||||||||||
Net unrealized gains on nuclear decommissioning trust funds, net of taxes of $125.3 | (125.3 | ) | (125.3 | ) | ||||||||||||||||||
Net unrealized losses on defined benefit plans, net of taxes of $(94.6) | 138.0 | 138.0 | ||||||||||||||||||||
Net unrealized gains on foreign currency translation, net of taxes of $(2.7) | 7.1 | 7.1 | ||||||||||||||||||||
Other comprehensive income—equity investment in CENG, net of taxes of $(11.7) | 12.9 | 12.9 | ||||||||||||||||||||
Other comprehensive income related to other equity method investees, net of taxes of $(1.3) | 2.1 | 2.1 | ||||||||||||||||||||
Total Comprehensive Income | 4,443.4 | 1,218.3 | 60.0 | 5,721.7 | ||||||||||||||||||
BGE preference stock dividends | (13.2 | ) | (13.2 | ) | ||||||||||||||||||
Common stock dividend declared ($0.96 per share) | (192.2 | ) | (192.2 | ) | ||||||||||||||||||
Common stock issued and share-based awards | 1,856 | 65.1 | (18.9 | ) | 46.2 | |||||||||||||||||
Balance at December 31, 2009 | 200,985 | 3,229.6 | 6,461.0 | (993.5 | ) | 265.3 | 8,962.4 | |||||||||||||||
CONSOLIDATED STATEMENTS OF INCOME
Baltimore Gas and Electric Company and Subsidiaries
Year Ended December 31, | 2007 | 2006 | 2005 | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||
Revenues | ||||||||||||
Electric revenues | $ | 2,455.7 | $ | 2,115.9 | $ | 2,036.5 | ||||||
Gas revenues | 962.8 | 899.5 | 972.8 | |||||||||
Total revenues | 3,418.5 | 3,015.4 | 3,009.3 | |||||||||
Expenses | ||||||||||||
Operating Expenses | ||||||||||||
Electricity purchased for resale | 1,500.4 | 1,167.8 | 1,068.9 | |||||||||
Gas purchased for resale | 639.8 | 581.5 | 687.5 | |||||||||
Operations and maintenance | 533.6 | 496.1 | 450.2 | |||||||||
Merger-related costs | — | 4.7 | 5.4 | |||||||||
Depreciation and amortization | 234.2 | 227.5 | 232.4 | |||||||||
Taxes other than income taxes | 176.2 | 168.7 | 168.4 | |||||||||
Total expenses | 3,084.2 | 2,646.3 | 2,612.8 | |||||||||
Income from Operations | 334.3 | 369.1 | 396.5 | |||||||||
Other Income | 26.8 | 6.0 | 5.9 | |||||||||
Fixed Charges | ||||||||||||
Interest expense | 127.9 | 104.6 | 95.6 | |||||||||
Allowance for borrowed funds used during construction | (2.6 | ) | (2.0 | ) | (2.1 | ) | ||||||
Total fixed charges | 125.3 | 102.6 | 93.5 | |||||||||
Income Before Income Taxes | 235.8 | 272.5 | 308.9 | |||||||||
Income Taxes | ||||||||||||
Current | (2.4 | ) | (22.8 | ) | 122.6 | |||||||
Deferred | 100.0 | 126.6 | (0.9 | ) | ||||||||
Investment tax credit adjustments | (1.6 | ) | (1.6 | ) | (1.8 | ) | ||||||
Total income taxes | 96.0 | 102.2 | 119.9 | |||||||||
Net Income | 139.8 | 170.3 | 189.0 | |||||||||
Preference Stock Dividends | 13.2 | 13.2 | 13.2 | |||||||||
Earnings Applicable to Common Stock | $ | 126.6 | $ | 157.1 | $ | 175.8 | ||||||
See Notes to Consolidated Financial Statements
Baltimore Gas and Electric Company and Subsidiaries
At December 31, | 2007 | 2006 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Assets | ||||||||||
Current Assets | ||||||||||
Cash and cash equivalents | $ | 17.6 | $ | 10.9 | ||||||
Accounts receivable (net of allowance for uncollectibles of$20.3 and $15.5, respectively) | 316.7 | 190.3 | ||||||||
Accounts receivable, unbilled (net of allowance for uncollectibles of$0.8 and $0.6, respectively) | 209.5 | 154.4 | ||||||||
Investment in cash pool, affiliated company | 78.4 | 60.6 | ||||||||
Accounts receivable, affiliated companies | 4.2 | 2.5 | ||||||||
Fuel stocks | 98.8 | 110.9 | ||||||||
Materials and supplies | 42.7 | 40.2 | ||||||||
Prepaid taxes other than income taxes | 49.9 | 48.0 | ||||||||
Regulatory assets (net) | 74.9 | 62.5 | ||||||||
Other | 46.6 | 35.2 | ||||||||
Total current assets | 939.3 | 715.5 | ||||||||
Investments and Other Assets | ||||||||||
Regulatory assets (net) | 576.2 | 389.0 | ||||||||
Receivable, affiliated company | 149.2 | 150.5 | ||||||||
Other | 148.1 | 127.5 | ||||||||
Total investments and other assets | 873.5 | 667.0 | ||||||||
Utility Plant | ||||||||||
Plant in service | ||||||||||
Electric | 4,244.4 | 4,060.2 | ||||||||
Gas | 1,181.7 | 1,148.3 | ||||||||
Common | 456.1 | 444.6 | ||||||||
Total plant in service | 5,882.2 | 5,653.1 | ||||||||
Accumulated depreciation | (2,080.8 | ) | (1,994.7 | ) | ||||||
Net plant in service | 3,801.4 | 3,658.4 | ||||||||
Construction work in progress | 166.4 | 97.1 | ||||||||
Plant held for future use | 2.4 | 2.7 | ||||||||
Net utility plant | 3,970.2 | 3,758.2 | ||||||||
Total Assets | $ | 5,783.0 | $ | 5,140.7 | ||||||
See Notes to Consolidated Financial Statements.
continued on next page
79
| | | | Accumulated Other Comprehensive Loss | | | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Years Ended December 31, 2010, 2009, and 2008 | Common Stock | Retained Earnings | Noncontrolling Interests | Total Amount | ||||||||||||||||||
Shares | Amount | |||||||||||||||||||||
| (Dollar amounts in millions, number of shares in thousands) | |||||||||||||||||||||
Balance at December 31, 2009 | 200,985 | $ | 3,229.6 | $ | 6,461.0 | $ | (993.5 | ) | $ | 265.3 | $ | 8,962.4 | ||||||||||
Sale of noncontrolling interest | (17.6 | ) | (17.6 | ) | ||||||||||||||||||
Distribution from noncontrolling interest | (6.3 | ) | (6.3 | ) | ||||||||||||||||||
Other noncontrolling interest activity | (0.2 | ) | (0.2 | ) | ||||||||||||||||||
Comprehensive Income (Loss) | ||||||||||||||||||||||
Net (loss) income | (982.6 | ) | 50.8 | (931.8 | ) | |||||||||||||||||
Other comprehensive income (loss) | ||||||||||||||||||||||
Hedging instruments: | ||||||||||||||||||||||
Reclassification of net losses on hedging instruments from OCI to net income, net of taxes of $(347.5) | 582.4 | 582.4 | ||||||||||||||||||||
Net unrealized loss on hedging instruments, net of taxes of $134.6 | (233.2 | ) | (233.2 | ) | ||||||||||||||||||
Available-for-sale securities: | ||||||||||||||||||||||
Reclassification of net gains on securities from OCI to net income, net of taxes of $0.1 | (0.1 | ) | (0.1 | ) | ||||||||||||||||||
Net unrealized gains on securities, net of taxes of $(0.1) | 0.1 | 0.1 | ||||||||||||||||||||
Defined benefit plans: | ||||||||||||||||||||||
Prior service cost arising during period, net of taxes of $(1.1) | 1.6 | 1.6 | ||||||||||||||||||||
Transition obligation arising during the period, net of taxes of $(0.2) | 0.4 | 0.4 | ||||||||||||||||||||
Net losses arising during period, net of taxes of $31.3 | (56.6 | ) | (56.6 | ) | ||||||||||||||||||
Amortization of net actuarial loss, prior service cost, and transition obligation included in net periodic benefit cost, net of taxes of $(15.5) | 22.7 | 22.7 | ||||||||||||||||||||
Net unrealized losses on foreign currency translation, net of taxes of $2.2 | (6.2 | ) | (6.2 | ) | ||||||||||||||||||
Other comprehensive income—equity investment in CENG, net of taxes of $(14.1) | 9.6 | 9.6 | ||||||||||||||||||||
Other comprehensive loss related to other equity method investees, net of taxes of $0.3 | (0.5 | ) | (0.5 | ) | ||||||||||||||||||
Total Comprehensive Income (Loss) | (982.6 | ) | 320.2 | 50.8 | (611.6 | ) | ||||||||||||||||
BGE preference stock dividends | (13.2 | ) | (13.2 | ) | ||||||||||||||||||
Common stock dividend declared ($0.96 per share) | (193.8 | ) | (193.8 | ) | ||||||||||||||||||
Common stock issued and share-based awards | 1,304 | 77.4 | (13.8 | ) | 63.6 | |||||||||||||||||
Common stock returned in connection with comprehensive agreement with EDF | (2,500 | ) | (75.3 | ) | (75.3 | ) | ||||||||||||||||
Balance at December 31, 2010 | 199,789 | $ | 3,231.7 | $ | 5,270.8 | $ | (673.3 | ) | $ | 278.8 | $ | 8,108.0 | ||||||||||
See Notes to Consolidated Financial Statements.
80
CONSOLIDATED STATEMENTS OF INCOME
Baltimore Gas and Electric Company and Subsidiaries
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||
Revenues | ||||||||||||
Electric revenues | $ | 2,752.3 | $ | 2,820.7 | $ | 2,679.7 | ||||||
Gas revenues | 709.4 | 758.3 | 1,024.0 | |||||||||
Total revenues | 3,461.7 | 3,579.0 | 3,703.7 | |||||||||
Expenses | ||||||||||||
Operating expenses | ||||||||||||
Electricity purchased for resale | 1,252.9 | 1,217.4 | 1,078.1 | |||||||||
Electricity purchased for resale from affiliate | 428.0 | 623.5 | 802.0 | |||||||||
Gas purchased for resale | 387.5 | 449.9 | 694.5 | |||||||||
Operations and maintenance | 484.5 | 433.7 | 428.2 | |||||||||
Operations and maintenance from affiliate | 121.6 | 126.2 | 109.6 | |||||||||
Impairment losses and other costs | — | 20.0 | — | |||||||||
Workforce reduction costs | — | — | 6.4 | |||||||||
Depreciation and amortization | 249.2 | 262.1 | 227.9 | |||||||||
Taxes other than income taxes | 183.8 | 177.8 | 174.5 | |||||||||
Total expenses | 3,107.5 | 3,310.6 | 3,521.2 | |||||||||
Income from Operations | 354.2 | 268.4 | 182.5 | |||||||||
Other Income | 20.8 | 25.4 | 29.6 | |||||||||
Fixed Charges | ||||||||||||
Interest expense | 135.8 | 143.6 | 144.2 | |||||||||
Allowance for borrowed funds used during construction | (5.5 | ) | (4.3 | ) | (4.3 | ) | ||||||
Total fixed charges | 130.3 | 139.3 | 139.9 | |||||||||
Income Before Income Taxes | 244.7 | 154.5 | 72.2 | |||||||||
Income Taxes | ||||||||||||
Current | (202.0 | ) | (119.8 | ) | (18.2 | ) | ||||||
Deferred | 300.2 | 184.7 | 40.2 | |||||||||
Investment tax credit adjustments | (1.1 | ) | (1.1 | ) | (1.3 | ) | ||||||
Total income taxes | 97.1 | 63.8 | 20.7 | |||||||||
Net Income | 147.6 | 90.7 | 51.5 | |||||||||
Preference Stock Dividends | 13.2 | 13.2 | 13.2 | |||||||||
Net Income Attributable to Common Stock before Noncontrolling Interests | 134.4 | 77.5 | 38.3 | |||||||||
Net Loss Attributable to Noncontrolling Interests | — | 7.3 | — | |||||||||
Net Income Attributable to Common Stock | $ | 134.4 | $ | 84.8 | $ | 38.3 | ||||||
See Notes to Consolidated Financial Statements.
81
Baltimore Gas and Electric Company and Subsidiaries
At December 31, | 2010 | 2009 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Assets | ||||||||||
Current Assets | ||||||||||
Cash and cash equivalents | $ | 50.0 | $ | 13.6 | ||||||
Accounts receivable (net of allowance for uncollectibles of$34.9 and $46.2, respectively) | 351.4 | 311.7 | ||||||||
Accounts receivable, unbilled (net of allowance for uncollectibles of$1.0 and $1.0, respectively) | 268.8 | 252.7 | ||||||||
Investment in cash pool, affiliated company | — | 314.7 | ||||||||
Accounts receivable, affiliated companies | 1.1 | 15.4 | ||||||||
Income taxes receivable, net | 55.9 | — | ||||||||
Fuel stocks | 66.5 | 73.8 | ||||||||
Materials and supplies | 31.2 | 31.9 | ||||||||
Prepaid taxes other than income taxes | 51.7 | 49.5 | ||||||||
Regulatory assets (net) | 78.7 | 72.5 | ||||||||
Restricted cash—consolidated variable interest entity | 29.5 | 24.3 | ||||||||
Deferred income taxes | — | 11.2 | ||||||||
Other | 9.5 | 11.3 | ||||||||
Total current assets | 994.3 | 1,182.6 | ||||||||
Investments and Other Assets | ||||||||||
Regulatory assets (net) | 374.1 | 414.4 | ||||||||
Receivable, affiliated company | 494.3 | 326.2 | ||||||||
Other | 52.2 | 98.2 | ||||||||
Total investments and other assets | 920.6 | 838.8 | ||||||||
Utility Plant | ||||||||||
Plant in service | ||||||||||
Electric | 5,127.9 | 4,772.4 | ||||||||
Gas | 1,323.0 | 1,260.6 | ||||||||
Common | 507.8 | 499.0 | ||||||||
Total plant in service | 6,958.7 | 6,532.0 | ||||||||
Accumulated depreciation | (2,449.3 | ) | (2,318.2 | ) | ||||||
Net plant in service | 4,509.4 | 4,213.8 | ||||||||
Construction work in progress | 232.9 | 215.5 | ||||||||
Plant held for future use | 10.1 | 2.4 | ||||||||
Net utility plant | 4,752.4 | 4,431.7 | ||||||||
Total Assets | $ | 6,667.3 | $ | 6,453.1 | ||||||
See Notes to Consolidated Financial Statements.
Certain prior-periodprior-year amounts have been reclassified to conform with the current period'syear's presentation.
Baltimore Gas and Electric Company and Subsidiaries
At December 31, | 2007 | 2006 | |||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Liabilities and Equity | |||||||||
Current Liabilities | |||||||||
Current portion of long-term debt | $ | 375.0 | $ | 258.3 | |||||
Accounts payable and accrued liabilities | 182.4 | 187.3 | |||||||
Accounts payable and accrued liabilities, affiliated companies | 164.5 | 163.4 | |||||||
Customer deposits | 70.5 | 71.4 | |||||||
Current portion of deferred income taxes | 44.1 | 47.4 | |||||||
Accrued taxes | 34.4 | 18.8 | |||||||
Accrued expenses and other | 96.3 | 79.5 | |||||||
Total current liabilities | 967.2 | 826.1 | |||||||
Deferred Credits and Other Liabilities | |||||||||
Deferred income taxes | 785.6 | 697.7 | |||||||
Payable, affiliated company | 243.7 | 250.7 | |||||||
Deferred investment tax credits | 11.9 | 13.5 | |||||||
Other | 33.6 | 14.0 | |||||||
Total deferred credits and other liabilities | 1,074.8 | 975.9 | |||||||
Long-term Debt | |||||||||
Rate stabilization bonds | 623.2 | — | |||||||
First refunding mortgage bonds of BGE | 119.7 | 244.5 | |||||||
Other long-term debt of BGE | 1,214.5 | 1,214.5 | |||||||
6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust II relating to trust preferred securities | 257.7 | 257.7 | |||||||
Long-term debt of nonregulated business | 25.0 | 25.0 | |||||||
Unamortized discount and premium | (2.6 | ) | (2.9 | ) | |||||
Current portion of long-term debt | (375.0 | ) | (258.3 | ) | |||||
Total long-term debt | 1,862.5 | 1,480.5 | |||||||
Minority Interest | 16.8 | 16.7 | |||||||
Preference Stock Not Subject to Mandatory Redemption | 190.0 | 190.0 | |||||||
Common Shareholder's Equity | |||||||||
Common stock | 912.2 | 912.2 | |||||||
Retained earnings | 758.8 | 738.6 | |||||||
Accumulated other comprehensive income | 0.7 | 0.7 | |||||||
Total common shareholder's equity | 1,671.7 | 1,651.5 | |||||||
Commitments, Guarantees, and Contingencies (see Note 12) | |||||||||
Total Liabilities and Equity | $ | 5,783.0 | $ | 5,140.7 | |||||
At December 31, | 2010 | 2009 | |||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Liabilities and Equity | |||||||||
Current Liabilities | |||||||||
Short-term borrowings | $ | — | $ | 46.0 | |||||
Current portion of long-term debt | 22.0 | — | |||||||
Current portion of long-term debt—consolidated variable interest entity | 59.7 | 56.5 | |||||||
Accounts payable | 252.9 | 166.0 | |||||||
Accounts payable, affiliated companies | 84.9 | 98.3 | |||||||
Customer deposits | 78.9 | 76.0 | |||||||
Deferred income taxes | 30.1 | — | |||||||
Accrued taxes | 19.0 | 80.2 | |||||||
Residential customer rate credit | — | 112.4 | |||||||
Liability for uncertain tax positions | 62.8 | — | |||||||
Accrued expenses and other | 99.7 | 96.1 | |||||||
Total current liabilities | 710.0 | 731.5 | |||||||
Deferred Credits and Other Liabilities | |||||||||
Deferred income taxes | 1,354.9 | 1,087.6 | |||||||
Payable, affiliated company | 250.8 | 243.4 | |||||||
Deferred investment tax credits | 8.4 | 9.5 | |||||||
Liability for uncertain tax positions | — | 73.3 | |||||||
Other | 20.1 | 20.0 | |||||||
Total deferred credits and other liabilities | 1,634.2 | 1,433.8 | |||||||
Long-term Debt | |||||||||
Rate stabilization bonds—consolidated variable interest entity | 454.4 | 510.9 | |||||||
Other long-term debt | 1,431.5 | 1,431.5 | |||||||
6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust II relating to trust preferred securities | 257.7 | 257.7 | |||||||
Unamortized discount and premium | (2.0 | ) | (2.2 | ) | |||||
Current portion of long-term debt | (22.0 | ) | — | ||||||
Current portion of long-term debt—consolidated variable interest entity | (59.7 | ) | (56.5 | ) | |||||
Total long-term debt | 2,059.9 | 2,141.4 | |||||||
Equity | |||||||||
Common shareholder's equity | 2,073.2 | 1,938.8 | |||||||
Preference stock not subject to mandatory redemption | 190.0 | 190.0 | |||||||
Noncontrolling interest | — | 17.6 | |||||||
Total equity | 2,263.2 | 2,146.4 | |||||||
Commitments, Guarantees, and Contingencies (see Note 12) | |||||||||
Total Liabilities and Equity | $ | 6,667.3 | $ | 6,453.1 | |||||
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Baltimore Gas and Electric Company and Subsidiaries
Year Ended December 31, | 2007 | 2006 | 2005 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||||
Cash Flows From Operating Activities | |||||||||||||
Net income | $ | 139.8 | $ | 170.3 | $ | 189.0 | |||||||
Adjustments to reconcile to net cash provided by operating activities | |||||||||||||
Depreciation and amortization | 246.7 | 241.1 | 250.5 | ||||||||||
Deferred income taxes | 99.9 | 126.6 | (0.9 | ) | |||||||||
Investment tax credit adjustments | (1.5 | ) | (1.7 | ) | (1.8 | ) | |||||||
Deferred fuel costs | (248.0 | ) | (348.5 | ) | (11.9 | ) | |||||||
Defined benefit plan expenses | 39.8 | 47.2 | 37.8 | ||||||||||
Allowance for equity funds used during construction | (4.9 | ) | (3.7 | ) | (3.9 | ) | |||||||
Changes in | |||||||||||||
Accounts receivable | (181.5 | ) | 135.8 | (98.7 | ) | ||||||||
Receivables, affiliated companies | (1.7 | ) | (0.7 | ) | (0.8 | ) | |||||||
Materials, supplies, and fuel stocks | 9.6 | (8.2 | ) | (21.7 | ) | ||||||||
Other current assets | 25.9 | (31.0 | ) | (0.5 | ) | ||||||||
Accounts payable and accrued liabilities | (4.9 | ) | 17.6 | 44.3 | |||||||||
Accounts payable and accrued liabilities, affiliated companies | 1.1 | 10.6 | 6.7 | ||||||||||
Other current liabilities | 29.6 | (0.9 | ) | 12.0 | |||||||||
Long-term receivables and payables, affiliated companies | (42.0 | ) | (70.1 | ) | (42.9 | ) | |||||||
Other | (44.7 | ) | (27.5 | ) | (37.4 | ) | |||||||
Net cash provided by operating activities | 63.2 | 256.9 | 319.8 | ||||||||||
Cash Flows From Investing Activities | |||||||||||||
Utility construction expenditures (excluding equity portion of allowance for funds used during construction) | (376.4 | ) | (320.6 | ) | (270.5 | ) | |||||||
Change in cash pool at parent | (17.8 | ) | (63.8 | ) | 131.1 | ||||||||
Sales of investments and other assets | 0.8 | (0.4 | ) | 11.0 | |||||||||
(Increase) decrease in restricted funds | (42.3 | ) | 10.3 | (10.4 | ) | ||||||||
Net cash used in investing activities | (435.7 | ) | (374.5 | ) | (138.8 | ) | |||||||
Cash Flows From Financing Activities | |||||||||||||
Proceeds from issuance of long-term debt | 623.2 | 700.0 | — | ||||||||||
Repayment of long-term debt | (124.8 | ) | (445.3 | ) | (41.6 | ) | |||||||
Preference stock dividends paid | (13.2 | ) | (13.2 | ) | (13.2 | ) | |||||||
Distribution to parent | (106.0 | ) | (128.1 | ) | (119.3 | ) | |||||||
Net cash provided by (used in) financing activities | 379.2 | 113.4 | (174.1 | ) | |||||||||
Net Increase (Decrease) in Cash and Cash Equivalents | 6.7 | (4.2 | ) | 6.9 | |||||||||
Cash and Cash Equivalents at Beginning of Year | 10.9 | 15.1 | 8.2 | ||||||||||
Cash and Cash Equivalents at End of Year | $ | 17.6 | $ | 10.9 | $ | 15.1 | |||||||
Other Cash Flow Information: | |||||||||||||
Cash paid (received) during the year for: | |||||||||||||
Interest (net of amounts capitalized) | $ | 126.3 | $ | 87.2 | $ | 88.6 | |||||||
Income taxes | $ | (37.6 | ) | $ | 18.7 | $ | 123.3 |
Year Ended December 31, | 2010 | 2009 | 2008 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||||
Cash Flows From Operating Activities | |||||||||||||
Net income | $ | 147.6 | $ | 90.7 | $ | 51.5 | |||||||
Adjustments to reconcile to net cash provided by operating activities | |||||||||||||
Depreciation and amortization | 249.2 | 262.1 | 227.9 | ||||||||||
Other amortization | 5.2 | 9.2 | 13.2 | ||||||||||
Deferred income taxes | 300.2 | 184.7 | 40.2 | ||||||||||
Investment tax credit adjustments | (1.1 | ) | (1.1 | ) | (1.3 | ) | |||||||
Deferred fuel costs | 67.4 | 68.9 | 52.0 | ||||||||||
Defined benefit plan expenses | 36.0 | 32.7 | 30.6 | ||||||||||
Allowance for equity funds used during construction | (10.5 | ) | (8.2 | ) | (8.0 | ) | |||||||
Accrual of residential customer rate credit | — | 112.4 | — | ||||||||||
Impairment losses and other costs | — | 20.0 | — | ||||||||||
Workforce reduction costs | — | — | 6.4 | ||||||||||
Changes in: | |||||||||||||
Accounts receivable | (57.6 | ) | (5.1 | ) | (33.1 | ) | |||||||
Accounts receivable, affiliated companies | 14.3 | (11.1 | ) | (0.1 | ) | ||||||||
Materials, supplies, and fuel stocks | 8.0 | 76.4 | (40.6 | ) | |||||||||
Income taxes receivable, net | (55.9 | ) | — | — | |||||||||
Other current assets | (6.6 | ) | (10.2 | ) | (4.5 | ) | |||||||
Accounts payable | 87.5 | (65.0 | ) | 48.6 | |||||||||
Accounts payable, affiliated companies | (13.4 | ) | 1.3 | (67.5 | ) | ||||||||
Other current liabilities | (121.5 | ) | 62.7 | (11.4 | ) | ||||||||
Long-term receivables and payables, affiliated companies | (200.8 | ) | (197.8 | ) | (45.7 | ) | |||||||
Regulatory assets, net | (64.3 | ) | (44.4 | ) | (18.7 | ) | |||||||
Other | (64.9 | ) | 67.6 | (10.4 | ) | ||||||||
Net cash provided by operating activities | 318.8 | 645.8 | 229.1 | ||||||||||
Cash Flows From Investing Activities | |||||||||||||
Utility construction expenditures (excluding equity portion of allowance for funds used during construction) | (496.8 | ) | (372.6 | ) | (426.4 | ) | |||||||
Change in cash pool at parent | 314.7 | (165.9 | ) | (70.4 | ) | ||||||||
Proceeds from sales of investments and other assets | 20.9 | — | 12.9 | ||||||||||
(Increase) decrease in restricted funds | (5.2 | ) | (0.6 | ) | 15.5 | ||||||||
Net cash used in investing activities | (166.4 | ) | (539.1 | ) | (468.4 | ) | |||||||
Cash Flows From Financing Activities | |||||||||||||
Net (repayment) issuance of short-term borrowings | (46.0 | ) | (324.0 | ) | 370.0 | ||||||||
Proceeds from issuance of long-term debt | — | — | 400.0 | ||||||||||
Repayment of long-term debt | (56.5 | ) | (90.0 | ) | (350.0 | ) | |||||||
Debt issuance costs | (0.3 | ) | (0.5 | ) | (2.7 | ) | |||||||
Contribution from noncontrolling interest | — | 8.0 | — | ||||||||||
Preference stock dividends paid | (13.2 | ) | (13.2 | ) | (13.2 | ) | |||||||
Contribution from (distribution to) parent | — | 315.9 | (171.7 | ) | |||||||||
Net cash (used in) provided by financing activities | (116.0 | ) | (103.8 | ) | 232.4 | ||||||||
Net Increase (Decrease) in Cash and Cash Equivalents | 36.4 | 2.9 | (6.9 | ) | |||||||||
Cash and Cash Equivalents at Beginning of Year | 13.6 | 10.7 | 17.6 | ||||||||||
Cash and Cash Equivalents at End of Year | $ | 50.0 | $ | 13.6 | $ | 10.7 | |||||||
Other Cash Flow Information: | |||||||||||||
Cash paid (received) during the year for: | |||||||||||||
Interest (net of amounts capitalized) | $ | 127.9 | $ | 136.9 | $ | 126.6 | |||||||
Income taxes | $ | (76.0 | ) | $ | (250.9 | ) | $ | (5.1 | ) |
See Notes to Consolidated Financial Statements.Statements
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
Notes to Consolidated Financial Statements
1Significant Accounting Policies
Nature of Our Business
Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various subsidiaries includingorganized around three business segments: a merchant energygeneration business (Generation), a customer supply business (NewEnergy), and Baltimore Gas and Electric Company (BGE). Our merchant energy business is aGeneration and NewEnergy businesses are competitive providerproviders of energy solutions for a variety of customers. BGE is a regulated electric transmission and distribution utility company and a regulated gas distribution utility company with a service territory that covers the City of Baltimore and all or part of ten counties in central Maryland. We describe our operating segments inNote 3.
This report is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries. References in this report to the "regulated business(es)" are to BGE.
Consolidation Policy
We use three different accounting methods to report our investments in our subsidiaries or other companies: consolidation, the equity method, and the cost method.
Consolidation
We use consolidation for two types of entities:
Consolidation means that we combine the accounts of these entities with our accounts. Therefore, our consolidated financial statements include our accounts, the accounts of our majority- ownedmajority-owned subsidiaries that are not VIEs, and the accounts of VIEs for which we are the primary beneficiary. We have not consolidated any entitiesthree VIEs for which we do not have a controlling voting interest.are the primary beneficiary. We eliminate all intercompany balances and transactions when we consolidate these accounts.
The Equity Method
We usually use the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies (including qualifying facilities and power projects) where we hold a significant influence, which generally approximates a 20% to 50% voting interest. Under the equity method, we report:
The only time we do not use this method is if we can exercise control over the operations and policies of the company. If we have control, accounting rules require us to use consolidation.
The Cost Method
We usually use the cost method if we hold less than a 20% voting interest in an investment. Under the cost method, we report our investment at cost in our Consolidated Balance Sheets. We recognize income only to the extent that we receive dividends or distributions. The only time we do not use this method is when we can exercise significant influence over the operations and policies of the company. If we have significant influence, accounting rules require us to use the equity method.
Sale of Subsidiary StockOwnership Interests
We may sell portions of our ownership interests through public offerings ofin a subsidiary's stock. We record anyThrough 2008, we recorded gains or losses on public offeringssuch sales in our Consolidated Statements of Income (Loss), as a component of non-operating income. Beginning in 2009, we treat sales of subsidiary stock as an equity transaction and do not recognize any gains or losses on the transaction as long as we retain a controlling financial interest.
When we sell ownership interests in our subsidiaries and do not retain a controlling financial interest, we deconsolidate that subsidiary. Upon deconsolidation, we recognize a gain or loss for the difference between the sum of the fair value of any consideration received and the fair value of our retained investment and the carrying amount of the former subsidiary's assets and liabilities.
On November 6, 2009, we completed the sale of a 49.99% membership interest in Constellation Energy Nuclear Group LLC and affiliates (CENG), our nuclear generation and operation business, to EDF Group and affiliates (EDF). As a result, we ceased to have a controlling financial interest in CENG and deconsolidated CENG at that time. We account for our retained interest in CENG using the equity method. SeeNote 2 for the gain recognized in 2009 on our sale of a 49.99% interest in CENG to EDF.
Regulation of Electric and Gas Business
The Maryland Public Service Commission (Maryland PSC) and the Federal Energy Regulatory Commission (FERC) provide the final determination of the rates we charge our customers for our regulated businesses. Generally, we usefollow the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC or the FERC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers.
When this happens, we and BGE must defer (include as an asset or liability in our, and BGE's,the Consolidated Balance Sheets and exclude from our, and BGE's, Consolidated Statements of Income)Income (Loss)) certain
85
regulated business expenses and income as regulatory assets and liabilities. We and BGE have recorded these regulatory assets and liabilities in our, and BGE's,the Consolidated Balance Sheets in accordance with Statement of Financial Accounting Standards (SFAS) No. 71,Accounting for the Effects of Certain Types of Regulation.Sheets.
We summarize and discuss our regulatory assets and liabilities further inNote 6.
Use of Accounting Estimates
Management makes estimates and assumptions when preparing financial statements under accounting principles generally accepted in the United States of America. These estimates and assumptions affect various matters, including:
These estimates involve judgments with respect to numerous factors that are difficult to predict and are beyond management's control. As a result, actual amounts could materially differ from these estimates.
Reclassifications
We have reclassified certain prior-year amountsIn accordance with the presentation requirements for comparative purposes for the following:
We discuss our adoption of the reporting requirements for consolidated variable interest entities later in this Note.
We have also reclassified certain prior-period amounts:
Revenues
Sources of Revenue
We earn revenues from the following primary business activities:
We report BGE's revenues from the sale and delivery of electricity and natural gas to its customers as "Regulated electric revenues" and "Regulated gas revenues" in our Consolidated Statements of Income (Loss). We report all other revenues as "Nonregulated revenues."
Revenues from nonregulated activities result from contracts or other sales that generally reflect market prices in effect at the time that we have separately presented "Accounts receivable, unbilled" that were previously reported within "Accounts receivable"executed the contract or the sale occurred. BGE's revenues from regulated activities reflect provisions of orders of the Maryland PSC and the FERC. In certain cases, these orders require BGE to defer the difference between certain portions of its actual costs and the amount presently billable to customers. BGE records these differences as regulatory assets or liabilities, which we discuss in more detail inNote 6. We describe the effects of these orders on BGE's Consolidated Balance Sheets.revenues below.
Regulated Electric
BGE provides market-based standard offer electric service to its residential, commercial, and industrial customers. BGE charges these customers standard offer service (SOS) rates that are designed to recover BGE's wholesale power supply costs and include an administrative fee consisting of a shareholder return component and an incremental cost component. Pursuant to Senate Bill 1, the energy legislation enacted in Maryland in June 2006, BGE suspended collection of the shareholder return component of the administrative fee for residential SOS service beginning January 1, 2007 for a 10-year period. However, under an order issued by the Maryland PSC in May 2007, as of June 1, 2007, BGE reinstated collection of the residential return component of the SOS administration charge and began providing all residential electric customers a credit for the return component of the administrative charge. As part of the 2008 Maryland settlement agreement, which is discussed in more detail inNote 2, BGE resumed collection of the shareholder return portion of the residential standard offer service administrative charge from June 1, 2008 through May 31, 2010 without having to rebate it to all residential electric customers. Starting June 1, 2010, BGE is providing all residential electric customers a credit for the residential return component of the administrative charge, which will continue through December 2016.
As part of the October 30, 2009 order from the Maryland PSC approving our transaction with EDF, BGE was permitted to file an electric distribution rate case at any time beginning in January 2010 and could not file a subsequent electric
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distribution rate case until January 2011. Any rate increase in the first electric distribution rate case was capped at 5%.
In May 2010, BGE filed an electric and gas distribution rate case with the Maryland PSC and the Maryland PSC issued an abbreviated order in December 2010. The order authorizes BGE to increase electric distribution rates by $31.0 million and was based on an 8.06% rate of return with a 9.86% return on equity and a 52% equity ratio.
BGE defers the difference between certain of its actual costs related to the electric commodity and what it collects from customers under the commodity charge portion of SOS rates in a given period. BGE either bills or refunds its customers the difference in the future.
Regulated Gas
BGE charges its gas customers for the natural gas they purchase from BGE using "gas cost adjustment clauses." Under these clauses, BGE defers the difference between certain of its actual costs related to the gas commodity and what it collects from customers under the commodity charge in a given period for evaluation under a market-based rates incentive mechanism. For each period subject to that mechanism, BGE compares its actual cost of gas to a market index (a measure of the market price of gas for that period) and shares the difference equally between shareholders and customers through an adjustment to the price of gas service in future periods. This sharing mechanism excludes fixed-price contracts which the Maryland PSC requires BGE to procure for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period. As a condition to the October 30, 2009 order from the Maryland PSC approving our transaction with EDF, BGE was permitted to file a gas distribution case at any time beginning in January 2010 and could not file a subsequent gas distribution rate case until January 2011.
In May 2010, BGE filed an electric and gas distribution rate case with the Maryland PSC and the Maryland PSC issued an abbreviated order in December 2010. The order authorizes BGE to increase gas distribution rates by $9.8 million and was based on a 7.90% rate of return with a 9.56% return on equity and a 52% equity ratio.
Selection of Accounting Treatment
We determine the appropriate accounting treatment for recognizing revenues based on the nature of the transaction, governing accounting standards and, where required, by applying judgment as to the most transparent presentation of the economics of the underlying transactions. We utilize two primary accounting treatments to recognize and report revenues in our results of operations:
Revenues We describe each of these accounting treatments below.
Accrual Accounting
WeUnder accrual accounting, we record revenues from the sale of energy, energy-related products, and energy services under the accrual method of accounting in the period when we deliver energy commodities or products, render services, or settle contracts. We generally use accrual accounting to recognize revenues for our merchant energy and other nonregulated business transactions, including the generation or purchase and salesales of electricity, gas, coal, and coalother commodities as part of our physical delivery activities and for power, gas, and coalactivities. We enter into these sales contracts that are not subject to mark-to-market accounting. Sales contracts that are eligible for accrual accounting includetransactions using a variety of instruments, including non-derivative transactions andagreements, derivatives that qualify for and are designated as normal purchases and normal sales (NPNS) of commodities that will be physically delivered. We record accrual revenues,delivered, sales to BGE's customers under regulated service tariffs, and spot-market sales, including settlements with independent system operators,operators. We discuss the NPNS election later in this Note underDerivatives and Hedging Activities.
However, we also use mark-to-market accounting rather than accrual accounting for recognizing revenue on our competitive retail gas customer supply activities, our fixed quantity competitive retail power customer supply activities for new transactions closed after June 30, 2010, which are managed using economic hedges that we have not designated as cash-flow hedges so as to match the timing of recognition of the earnings impacts of those activities to the greatest extent permissible, and other physical commodity derivatives if we have not designated those contracts as NPNS.
We record accrual revenues from sales of products or services on a gross basis at the contract, tariff, or spot price because we are a principal to the transactiontransaction. Accrual revenues also include certain other gains and otherwise meetlosses that relate to these activities or for which accrual accounting is required.
We include in accrual revenues the requirementseffects of Emerging Issues Task Force (EITF) 03-11,hedge accounting for derivative contracts that qualify as hedges of our sales of products or services. Substantially all of the derivatives that we designate as hedges are cash flow hedges. We recognize the effective portion of hedge gains or losses in revenues during the same period in which we record the revenues from the hedged transaction. We record any hedge ineffectiveness in revenues when it occurs. We discuss our hedge accounting policy in theReporting Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative InstrumentsDerivatives and Hedging Activities and Not Held for Trading Purposes, and EITF 99-19,Reporting Revenue Gross as a Principal versus Net as an Agent.
While we generally elect accrual accounting whenever permitted, we sometimes use mark-to-market accounting for physical delivery activities that are managed using economic hedges that do not qualify for accrual accounting. We discuss mark-to-market accountingsection later in further detail below.this Note.
We may make or receive cash payments at the time we assume apreviously existing power sale agreementagreements for which the contract price differs from current market prices. We also may designate a derivative as NPNS after its inception. We recognize the value of these derivatives in our Consolidated Balance Sheets as an "Unamortized energy contract" asset or liability. We amortize these assets and liabilities into revenues based on the present value of the underlying cash flows provided by the contracts.
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The following table summarizes the primary components of accrual revenues:
Activity | ||||||
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Component of Accrual Revenues | Nonregulated Physical Energy Delivery | Regulated Electricity and Gas Sales | Other Nonregulated Products and Services | |||
Gross amounts receivable for sales of products or services based on contract, tariff, or spot price | X | X | X | |||
Reclassification of net gains/losses on cash flow hedges from AOCI | X | |||||
Ineffective portion of net gains/losses on cash flow hedges | X | |||||
Amortization of acquired energy contract assets or liabilities | X | |||||
Recovery or refund of deferred SOS and gas cost adjustment clause regulatory assets/liabilities | X | |||||
Mark-to-Market Accounting
We record revenues using the mark-to-market method of accounting for transactions under derivative contracts for which we are not permitted, or do not elect, to use accrual accounting or hedge accounting. These mark-to-market transactions primarily relate to our risk management and trading activities, our competitive retail gas customer supply activities, and economic hedges of other accrual activities. Mark-to-market revenues include:
Under the mark-to-market method of accounting, we record any inception fair value of these contracts as derivative assets and liabilities at the time of contract execution. We record subsequent changes in the fair value of these derivative assets and liabilities on a net basis in "Nonregulated revenues" in our Consolidated Statements of Income (Loss). We discuss our mark-to-market accounting policy in theDerivatives and Hedging Activities section later in this Note.
Fuel and Purchased Energy Expenses
Sources of Fuel and Purchased Energy Expenses
We incur fuel and purchased energy costs for:
We report these costs in "Fuel and purchased energy expenses" in our Consolidated Statements of Income (Loss). We also include certain fuel-related direct costs, such as ancillary services purchased from independent system operators, transmission costs, brokerage fees, and freight costs in the same category in our Consolidated Statements of Income (Loss).
Fuel and purchased energy costs from nonregulated activities result from contracts or other purchases that generally reflect market prices in effect at the time that we executed the contract or the purchase occurred. BGE's costs of electricity and gas for resale under regulated activities reflect actual costs of purchases, adjusted to reflect provisions of orders of the Maryland PSC and the FERC. In certain cases, these orders require BGE to defer the difference between certain portions of its actual costs and the amount presently billable to customers. BGE records these differences as regulatory assets or liabilities, which we discuss in more detail inNote 6. We describe the effects of these orders on BGE's fuel and purchased energy expense below.
Regulated Electric
BGE provides market-based standard offer electric service to its residential, commercial, and industrial customers. BGE charges these customers SOS rates that are designed to recover BGE's wholesale power supply costs and include an administrative fee consisting of a shareholder return component and an incremental cost component. Starting June 1, 2010, BGE is providing all residential electric customers a credit for the residential return component of the administrative charge, which will continue through December 2016.
BGE defers the difference between certain of its actual costs related to the electric commodity and what it collects from customers under the commodity charge portion of SOS rates in a given period. BGE either bills or refunds its customers the difference in the future and includes amortization of the deferred amounts in fuel and purchased energy expense. Therefore, BGE does not earn a profit on the cost of fuel and purchased energy because its expense approximates the amount of the related commodity charge included in revenues for the period, reflecting actual costs adjusted for the effects of the regulatory deferral mechanism.
Regulated Gas
BGE charges its gas customers for the natural gas they purchase from BGE using "gas cost adjustment clauses." These clauses include a market-based rates incentive mechanism that requires BGE to compare its actual cost of gas to a market index (a measure of the market price of gas for that period) and share the difference equally between shareholders and customers. This
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sharing mechanism excludes fixed-price contracts which the Maryland PSC requires BGE to procure for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period.
BGE defers the difference between the portion of its actual gas commodity costs subject to the market-based rates incentive mechanism and what it collects from customers under the commodity charge in a given period. BGE either bills or refunds its customers the portion of this difference to which they are entitled through an adjustment to the price of gas service in future periods and includes amortization of the deferred amounts in fuel and purchased energy expense.
Selection of Accounting Treatment
We determine the appropriate accounting treatment for fuel and purchased energy costs based on the nature of the transaction, governing accounting standards and, where required, by applying judgment as to the most transparent presentation of the economics of the underlying transactions. We utilize two primary accounting treatments to recognize and report these costs in our Consolidated Statements of Income (Loss):
We describe each of these accounting treatments below.
Accrual Accounting
Under accrual accounting, we record fuel and purchased energy expenses in the period when we consume the fuel or purchase the electricity or other commodity for resale. We use accrual accounting to recognize substantially all of our fuel and purchased energy expenses as part of our physical delivery activities. We make these purchases using a variety of instruments, including non-derivative transactions, derivatives that qualify for and are designated as NPNS, and spot-market purchases, including settlements with independent system operators. These transactions also include power purchase agreements that qualify as operating leases, for which fuel and purchased energy consists of both fixed capacity payments and variable payments based on the actual output of the plants. We discuss the NPNS election later in this Note underDerivatives and Hedging Activities.
In certain cases, we use mark-to-market accounting rather than accrual accounting for recognizing fuel and purchased energy expenses on physical commodity derivatives if we have not designated those contracts as NPNS.
We include in accrual fuel and purchased energy expenses the effects of hedge accounting for derivative contracts that qualify as hedges of our fuel and purchased energy costs. Substantially all of the derivatives that we designate as hedges are cash flow hedges. We recognize the effective portion of hedge gains or losses in fuel and purchased energy expenses during the same period in which we record the costs from the hedged transaction. We record any hedge ineffectiveness in expense when it occurs. We discuss our use of hedge accounting in theDerivatives and Hedging Activities section later in this Note.
We may make or receive cash payments at the time we assume previously existing power purchase agreements or other contracts for which the contract price differs from current market prices. We recognize the cash payment at inception in our Consolidated Balance Sheets as an "Unamortized energy contract" asset or liability. We amortize these assets and liabilities into revenuesfuel and purchased energy expenses based on the expectedpresent value of the underlying cash flows provided by the contracts.
During 2007, 2006,The following table summarizes the primary components of accrual purchased fuel and 2005, we terminated or restructured in-the-money contracts in exchange for upfront cash payments and a reduction or cancellation of future performance obligations. The termination or restructuring of contracts allowed us to lower our exposure to performance risk under these contracts, and resulted in the realization of $17.8 million of pre-tax earnings in 2007, $56.7 million of pre-tax earnings in 2006, and $77.0 million of pre-tax earnings in 2005 that would have been recognized over the life of these contracts.energy expense:
Activity | ||||||
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Component of Accrual Fuel and Purchased Energy Expense | Nonregulated Physical Energy Delivery | Regulated Electricity and Gas Sales | Other Nonregulated Products and Services | |||
Actual costs of fuel and purchased energy | X | X | X | |||
Reclassification of net gains/losses on cash flow hedges from AOCI | X | |||||
Ineffective portion of net gains/losses on cash flow hedges | X | |||||
Amortization of acquired energy contract assets or liabilities | X | |||||
Deferral or amortization of deferred SOS and gas cost adjustment clause regulatory assets/liabilities | X | |||||
Mark-to-Market Accounting
We record revenuesfuel and purchased energy expenses using the mark-to-market method of accounting for transactions under derivative contracts for which we are not permitted, or do not elect, to use accrual accounting or hedge accounting. We discuss our use of hedge accounting in order to match theDerivatives and Hedging Activities section later in this Note. earnings impacts of those activities to the greatest extent permissible. These mark-to-market activities include derivativetransactions relate to our physical international coal purchase contracts for energyin 2009 and other energy-related commodities. Under the mark-to-market method of accounting, we record the fair value of these derivatives as derivative assets and liabilities at the time of contract execution. We record changes in derivative assets and liabilities subject to mark-to-market accounting on a net basis in "Nonregulated revenues" in our Consolidated Statements of Income.
Derivative assets and liabilities include contracts subject to mark-to-market accounting. While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using modeling techniques to determine expected future market prices, contract quantities, or both. The market prices and quantities used to determine fair value reflect management's best estimate considering various factors, including closing exchange and over-the-counter quotations, time value, and volatility factors. However, future market prices and actual quantities will vary from those used in recording derivative assets and liabilities subject to mark-to-market accounting, and it is possible that such variations could be material.
2008. Mark-to-market revenuescosts include:
Origination gains, which Under the mark-to-market method of accounting, we record any inception fair value of these contracts as derivative assets and liabilities at the time of contract execution. We record subsequent changes in the fair value of these derivative assets and liabilities on a net basis in "Fuel and purchased energy expense" in our Consolidated Statements of Income (Loss). We discuss our mark-to-market accounting policy in theDerivatives and Hedging Activities section later in this Note.
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Derivatives and Hedging Activities
We engage in electricity, natural gas, coal, emission allowances, and other commodity marketing and risk management activities as part of our NewEnergy business. In order to manage our exposure to commodity price fluctuations, we enter into energy and energy-related derivative contracts traded in the over-the-counter markets or on exchanges. These contracts include:
We use interest rate swaps to manage our interest rate exposures associated with new debt issuances, to manage our exposure to fluctuations in interest rates on variable rate debt, and to optimize the mix of fixed and floating-rate debt. We use foreign currency swaps to manage our exposure to foreign currency exchange rate fluctuations.
Selection of Accounting Treatment
We account for derivative instruments and hedging activities in accordance with several possible accounting treatments that meet all of the requirements of the accounting standard. Mark-to-market is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the other elective accounting treatments must meet specific, restrictive criteria, both at the time of designation and on an ongoing basis.
The following are includedpermissible accounting treatments for derivatives:
Each of the accounting treatments for derivatives affects our financial statements in substantially different ways as summarized below:
Recognition and Measurement | ||||
---|---|---|---|---|
Accounting Treatment | ||||
Balance Sheet | Income Statement | |||
Mark-to-market | • Derivative asset or liability recorded at fair value | • Changes in fair value recognized in earnings | ||
Cash flow hedge | • Derivative asset or liability recorded at fair value • Effective changes in fair value recognized in accumulated other comprehensive income | • Ineffective changes in fair value recognized in earnings • Amounts in accumulated other comprehensive income reclassified to earnings when the hedged forecasted transaction affects earnings or becomes probable of not occurring | ||
Fair value hedge | • Derivative asset or liability recorded at fair value | • Changes in fair value recognized in earnings | ||
• Book value of hedged asset or liability adjusted for changes in its fair value | • Changes in fair value of hedged asset or liability recognized in earnings | |||
NPNS (accrual) | • Fair value not recorded • Accounts receivable or accounts payable recorded when derivative settles | • Changes in fair value not recognized in earnings • Revenue or expense recognized in earnings when underlying physical commodity is sold or consumed | ||
Mark-to-Market
We generally apply mark-to-market revenues, arise primarily from contracts that our wholesale marketing,accounting for risk management and trading activities because changes in fair value more closely reflect the economic performance of the activity. However, we also use mark-to-market accounting for derivatives related to the following physical energy delivery activities:
We may record origination gains associated with derivatives subject to mark-to-market accounting. Origination gains represent the initial fair value of certain structured transactions that our portfolio management and trading operation structuresexecutes to meet the risk management needs of our customers. TransactionsHistorically, transactions that result in origination gains may behave been unique and provide the potential forresulted in individually significant gains from a single transaction.
Origination gains represent the initial fair value recognized on these structured transactions. The recognition of We generally recognize origination gains is dependent on the existence ofwhen we are able to obtain observable market data to validate that validates the initial fair value of the contract. Origination gains were:contract differs from the contract price.
Origination gains arose primarily from:
Valuation AdjustmentsCash Flow Hedge
We generally elect cash flow hedge accounting for most of the derivatives that we use to hedge market price risk for our physical energy delivery (Generation and NewEnergy businesses) activities because cash flow hedge accounting more closely aligns the timing of earnings recognition, cash flows, and the underlying business activities. We only use fair value hedge accounting on a limited basis.
We use regression analysis to determine whether we expect a derivative to be highly effective as a cash flow hedge prior to electing hedge accounting and also to determine whether all derivatives designated as cash flow hedges have been effective. We perform these effectiveness tests prior to designation for all new hedges and on a daily basis for all existing hedges. We calculate the actual amount of ineffectiveness on our cash flow hedges using the "dollar offset" method, which compares changes in the expected cash flows of the hedged transaction to changes in the value of expected cash flows from the hedge.
We discontinue hedge accounting when our effectiveness tests indicate that a derivative is no longer highly effective as a hedge; when the derivative expires or is sold, terminated or exercised; when the hedged item matures, is sold or repaid; or when we determine that the occurrence of the hedged forecasted
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transaction is not probable. When we discontinue hedge accounting but continue to hold the derivative, we begin to apply mark-to-market accounting at that time.
NPNS
We elect NPNS accounting for derivative contracts that provide for the purchase or sale of a physical commodity that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Once we elect NPNS classification for a given contract, we do not subsequently change the election and treat the contract as a derivative using mark-to-market or hedge accounting. However, if we were to determine that a transaction designated as NPNS no longer qualified for the NPNS election, we would have to record the fair value of that contract on the balance sheet at that time and immediately recognize that amount in earnings.
Fair Value
We record mark-to-market and hedge derivatives at fair value, which represents an exit price for the asset or liability from the perspective of a market participant. An exit price is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. While some of our derivatives relate to commodities or instruments for which quoted market prices are available from external sources, many other commodities and related contracts are not actively traded. Additionally, some contracts include quantities and other factors that vary over time. As a result, often we must use modeling techniques to estimate expected future market prices, contract quantities, or both in order to determine fair value.
The prices, quantities, and other factors we use to determine fair value reflect management's best estimates of inputs a market participant would consider. We record valuation adjustments to reflect uncertainties associated with certain estimates inherent in the determination of the fair value of derivative assets and liabilities subjectthat are not incorporated in market price information or other market-based estimates we use to mark-to-market accounting.determine fair value. To the extent possible, we utilize market-based data together with quantitative methods for both measuring the uncertainties for which we record valuation adjustments and determining the level of such adjustments and changes in those levels.
We describe below the main types of The valuation adjustments we record andinclude the process for establishing each. Generally, increases in valuation adjustments reduce our earnings, and decreases in valuation adjustments increase our earnings. However, all or a portion of the effect on earnings of changes in valuation adjustments may be offset by changes in the value of the underlying positions. As discussed below and later in this Note, our valuation adjustments will be affected by the adoption of SFAS No. 157,Fair Value Measurements, in 2008.following:
We discuss derivatives and associated default probability percentages. We compute this adjustment by applying the appropriate default probability percentage to our outstanding credit exposure, net of collateral, for each counterparty. The level of this adjustment increaseshedging activities as our credit exposure to counterparties increases, the maturity terms of our transactions increase, or the credit ratings of our counterparties deteriorate, and it decreases when our credit exposure to counterparties decreases, the maturity terms of our transactions decrease, or the credit ratings of our counterparties improve. Upon adoption of SFAS No. 157,well as how we will also use a credit-spread adjustment in order to reflect our own credit risk in determining thedetermine fair value of our derivative liabilities.
Financial Statement PresentationBalance Sheet Netting
Certain transactions entered intoWe often transact with counterparties under master agreements and other arrangements that provide our wholesale competitive supply operationus with a right of setoff of amounts due to us and from us in the event of bankruptcy or default by the counterparty. We report suchthese transactions on a net basis in our Consolidated Balance Sheets in accordance with FASB Interpretation No. 39,Offsetting of Amounts Related to Certain Contracts. During 2007, the FASB issued Staff Position FIN 39-1,Amendment of FASB Interpretation No. 39, which was effective January 1, 2008. We discuss Staff Position FIN 39-1 in more detail later inNote 1.
Equity in Earnings
We include equity in earnings from our investments in qualifying facilities and power projects, joint ventures, and investment in Constellation Energy Partners LLC (CEP) in "Nonregulated revenues" in our Consolidated Statements of Income in the period they are earned.
Fuel and Purchased Energy Expenses
We incur costs for:
These costs are included in "Fuel and purchased energy expenses" in our Consolidated Statements of Income. We discuss certain of these separately below. We also include certain non-fuel direct costs, such as ancillary services, transmission costs, brokerage fees, and freight costs in "Fuel and purchased energy expenses" in our Consolidated Statements of Income.
Fuel Used to Generate Electricity and Purchases of Electricity and Gas
Nonregulated Businesses
We assemble a variety of power supply resources, including baseload, intermediate, and peaking plants that we own, as well as a variety of power supply contracts that may have similar characteristics, in order to enable us to meet our customers' energy requirements, which vary on an hourly basis. The amount of power purchased depends on a number of factors, including the capacity and availability of our power plants, the level of customer demand, and the relative economics of generating power versus purchasing power from the spot market.Sheets.
We also have acquired contractsapply balance sheet netting separately for current and certain power purchase agreements that qualify as operating leases. Under these operating leases, we record fuel and purchased energy expense as we make fixed capacity payments, as well as variable payments based onnoncurrent derivatives. Current derivatives represent the actual outputportion of the plants.
We may make or receive cash payments at the time we acquire aderivative contract or assume a power purchase agreement when the contract price differs from market prices at closing. We recognize the cash payment or receipt at inception in our Consolidated Balance Sheets as an "Unamortized energy contract" asset (payment) or liability (receipt). We amortize these assets and liabilities into fuel and purchased energy expenses based on the expected cash flows provided byexpected to occur within 12 months, and noncurrent derivatives represent the contracts.
Regulated Electric
BGE is obligatedportion of those cash flows expected to provide market-based standard offer serviceoccur beyond 12 months. Within each of these categories, we net all amounts due to residential and small commercial customers for the indefinite future, and for large commercial and industrial customers for varying periods beyond June 30, 2004, depending on customer load. The Provider of Last Resort (POLR) rates charged during these time periods will recover BGE's wholesale power supply costs andfrom each counterparty under master agreements into a single net asset or liability. We include an administrative fee. The administrative fee includes a shareholder return component and an incremental cost component. Pursuant to Senate Bill 1, the energy legislation enacted in Maryland in June 2006, collection of the shareholder return component of the administrative fee for residential POLR service was suspended beginning January 1, 2007 for a 10-year period. However, under an order issued by the Maryland PSC in May 2007, as of June 1, 2007, we were required to reinstate collection of the residential return component of the POLR administration charge and provide all residential electric customers a credit for the return component of the administrative charge.
In accordance with the POLR settlement agreement approved by the Maryland PSC, BGE defers the difference between certain of its actual costs related to the electric commodity and what it collects from customers under the commodity charge in a given period. BGE either bills or refunds its customers the difference in the future. In addition, Senate Bill 1 imposed a 15% rate cap for BGE residential electric customers from July 1, 2006 until May 31, 2007. We discuss this in more detail inNote 6.
BGE's obligation to provide market-based standard offer service to its largest commercial and industrial customers expired May 31, 2005. BGE continues to provide an hourly priced market-based standard offer service to those customers.
Regulated Gas
BGE charges its gas customers for the natural gas they purchase from BGE using "gas cost adjustment clauses" set by the Maryland PSC. Under these clauses, BGE defers the difference between certain of its actual costs related to the gas commodity and what it collects from customers under the commodity charge in a given period. BGE either bills or refunds its customers the difference in the future. The Maryland PSC approved a modification of the gas cost adjustment clauses to provide a market-based rates incentive mechanism. Under the market-based rates incentive mechanism, BGE's actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE's actual cost and the market index is shared equally between shareholders and customers. The Maryland PSC also has approved a settlement that modifies certain provisions of the market-based rates incentive mechanism. These provisions require that BGE secure fixed-price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for the November through March period. These fixed-price contracts are not subject to sharing under the market-based rates incentive mechanism.
Derivatives and Hedging Activities
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 as discussed further inNote 13. In order to manage these risks, we use both derivative and non-derivative contracts that may provide for settlement in cash or by delivery of a commodity, including:
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, requires that we recognize at fair value all derivatives not qualifying for accrual accounting under the normal purchasecash collateral amounts received and normal sale exception. We record all derivativesposted in "Derivative assest or liabilities" in our Consolidated Balance Sheets, including derivatives subject to mark-to-market accountingdetermining this net asset and derivatives that are designated as hedges.liability amount.
We record changes in the value of derivatives that are not designated as cash-flow hedges in earnings during the period of change. We record changes in the fair value of derivatives designated as cash-flow hedges that are effective in offsetting the variability in cash flows of forecasted transactions in other comprehensive income until the forecasted transactions occur. At the time the forecasted transactions occur, we reclassify the amounts recorded in other comprehensive income into earnings. We record the ineffective portion of changes in the fair value of derivatives used as cash-flow hedges immediately in earnings.
We summarize our cash-flow hedging activities under SFAS No. 133 and the income statement classification of amounts reclassified from "Accumulated other comprehensive income (loss)" as follows:
We designate certain derivatives as fair value hedges. We record changes in the fair value of these derivatives and changes in the fair value of the hedged assets or liabilities in earnings as the changes occur. We summarize our fair value hedging activities and the income statement classification of changes in the fair value of these hedges and the related hedged items as follows:
We record changes in the fair value of interest rate swaps and the debt being hedged in "Derivative assets and liabilities" and "Long-term debt" and changes in the fair value of the gas being hedged and related derivatives in "Fuel stocks" and "Derivative assets and liabilities" 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.
Unamortized Energy Assets and Liabilities
Unamortized energy contract assets and liabilities represent the remaining unamortized balance of non-derivative energy contracts that we acquired, certain contracts which no longer qualify as derivatives due to the absence of a liquid market, or derivatives designated as normal purchases and normal salesNPNS that we had previously recorded as "Derivative assets or liabilities." The initial amount recorded represents the fair value of the contract at the time of acquisition or designation, and the balance is amortized over the life of the contract in relation to the present value of the underlying cash flows. The amortization of these values is discussed in theRevenues andFuel and Purchased Energy Expenses sections of this Note.
Credit Risk
Credit risk is the loss that may result from counterparty non-performance. We are exposed to credit risk, primarily through our merchant energyNewEnergy business. We use credit policies to manage our credit risk, including utilizing an established credit approval process, daily monitoring of counterparty limits, employing credit mitigation measures such as margin, collateral (cash or letters of credit) or prepayment arrangements, and using master netting agreements. We measure credit risk as the replacement cost for open energy commodity and derivative positions (both mark-to-market and accrual) plus amounts owed from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, less any unrealized losses where we have a legally enforceable right of setoff.
Electric and gas utilities, municipalities, cooperatives, generation owners, coal producers, and energy marketers comprise the majority of counterparties underlying our assets from our wholesale marketing and risk management activities. We held cash collateral from these counterparties totaling $269.9$28.8 million as of December 31, 20072010 and $252.6$95.2 million as of December 31, 2006.2009. These amounts are included in "Customer deposits and collateral" in our Consolidated Balance Sheets.
We consider a significant concentration of credit risk to be any single obligor or counterparty whose concentration exceeds 10% of total credit exposure. As of December 31, 2010, two
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counterparties, CENG and a large power cooperative, comprise total exposure concentrations of 25%. No counterparties based in a single country other than the United States in aggregate comprise more than 10% of the total exposure of the portfolio.
Equity Investment (Losses) Earnings
We include equity in earnings from our investments in qualifying facilities and power projects, joint ventures, and Constellation Energy Partners LLC (CEP) in "Equity Investment (Losses) Earnings" in our Consolidated Statements of Income (Loss) in the period they are earned. "Equity Investment (Losses) Earnings" also includes any adjustments to amortize the difference, if any, except for goodwill and land, between our cost in an equity method investment and our underlying equity in net assets of the investee at the date of investment.
We consider our investments in generation-related qualifying facilities, power projects, and joint ventures to be integral to our operations.
Taxes
We summarize our income taxes inNote 10. BGE and our other subsidiaries record their allocated share of our consolidated federal income tax liability using the percentage complementary method specified in U.S. income tax regulations. As you read this section, it may be helpful to refer toNote 10.
Income Tax Expense
We have two categories of income tax expense—current and deferred. We describe each of these below:
Tax Credits
We have deferreddefer the investment tax credits associated with our regulated business, and assets previously held by our regulated business, and any investment tax credits that are convertible to cash grants in our Consolidated Balance Sheets. The investment tax credits that are convertible to cash grants are recorded as a reduction to the carrying value of the underlying property and subsequently amortized evenly to incomeearnings over the life of each underlying property. We reduce current income tax expense in our Consolidated Statements of Income (Loss) for theany investment tax credits that are not convertible to cash grants and other tax credits associated with our nonregulated businesses.
We have certain investments in facilities that manufactured solid synthetic fuel produced from coal as defined under the Internal Revenue Code for which we claim tax credits on our Federal income tax return. Because the federal tax credit for synthetic fuel produced from coal expired on December 31, 2007, these facilities ceased fuel production on that date. 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.
Deferred Income Tax Assets and Liabilities
We must report some of our revenues and expenses differently for our financial statements than for income tax return purposes. The tax effects of the temporary differences in these items are reported as deferred income tax assets or liabilities in our Consolidated Balance Sheets. We measure the deferred income tax assets and liabilities using income tax rates that are currently in effect. During 2007, the State of Maryland increased its corporate income tax rate from 7% to 8.25%. We discuss the impact on our existing deferred income tax assets and liabilities in more detail inNote 10.
A portion of our total deferred income tax liability relates to our regulated business, but has not been reflected in the rates we charge our customers. We refer to this portion of the liability as "Income taxes recoverable through future rates (net)." We have recorded that portion of the net liability as a regulatory asset in our Consolidated Balance Sheets. We discuss this further inNote 6.
StateInterest and Local TaxesPenalties
StateWe recognize interest and local income taxes are includedpenalties related to tax underpayments, assessments, and unrecognized tax benefits in "Income taxes"tax expense (benefit)" in our Consolidated Statements of Income.
Taxes Other Than Income Taxes(Loss).
BGE collects from certain customers franchise and other taxes that are levied by state or local governments on the sale or distribution of gas and electricity. We include these types of taxes in "Taxes other than income taxes" in our Consolidated Statements of Income. Some of these taxes are imposed on the customer and others are imposed on BGE. The taxes imposed on the customer are accounted for on a net basis, which means we do not recognize revenue and an offsetting tax expense for the taxes collected from customers. The taxes imposed on BGE are accounted for on a gross basis, which means we recognize revenue for the taxes collected from customers. Accordingly, the taxes accounted for on a gross basis are recorded as revenues in the accompanying Consolidated Statements of Income for BGE as follows:
Year Ended December 31, | 2007 | 2006 | 2005 | ||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Taxes other than income taxes included in revenues—BGE | $ | 77.0 | $ | 74.0 | $ | 77.0 | |||
Unrecognized Tax Benefits
We adopted FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes, on January 1, 2007 (FIN 48). FIN 48 requires us to recognize in our financial statements the effects of uncertain tax positions if we believe that these positions meet aare "more-likely-than-not" threshold. For those uncertain tax positions that we have recognized in our financial statements, weto be realized. We establish liabilities to reflect the portion of those positions we cannot conclude are "more-likely-than-not" to be realized upon ultimate settlement. These are referred to as liabilities for unrecognized tax benefits under FIN 48. We recognize interest and penalties related to unrecognized tax benefits in "Income tax expense" in our Consolidated Statements of Income.benefits.
We discuss our unrecognized tax benefits in more detail inNote 10.
State and Local Taxes
State and local income taxes are included in "Income tax expense (benefit)" in our Consolidated Statements of Income (Loss).
Taxes Other Than Income Taxes
Taxes other than income taxes primarily include property and gross receipts taxes along with franchise taxes and other non-income taxes, surcharges, and fees.
BGE and our NewEnergy business collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees that are levied by state or local governments on the sale or distribution of gas and electricity. Some of these taxes are imposed on the customer and others are imposed on BGE and our NewEnergy business. Where these taxes, such as sales taxes, are imposed on the customer, we account for these taxes on a net basis with no impact to our Consolidated Statements of Income (Loss). However, where these taxes, such as gross receipts taxes or other surcharges or fees, are imposed on BGE or our NewEnergy business, we account for these taxes on a gross basis. Accordingly, we recognize revenues for these taxes collected from customers along with an offsetting tax expense, which are both included in our Consolidated
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Statements of Income (Loss). The taxes, surcharges, or fees that are included in revenues were as follows:
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Constellation Energy (including BGE) | $ | 122.2 | $ | 106.8 | $ | 111.7 | ||||
BGE | 81.9 | 76.8 | 73.2 | |||||||
Earnings Per Share
Basic earnings per common share (EPS) is computed by dividing earnings applicablenet income (loss) attributable to common stock by the weighted-average number of common shares outstanding for the year. 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 primarily consist of stock options and other stock-based compensation awards. The following table presents stock options that were not dilutive and were excluded from the computation of diluted EPS in each period, as well as the dilutive common stock equivalent shares as follows:
Year Ended December 31, | 2007 | 2006 | 2005 | |||
---|---|---|---|---|---|---|
| (In millions) | |||||
Non-dilutive stock options | — | — | 0.1 | |||
Dilutive common stock equivalent shares | 2.3 | 2.0 | 2.2 |
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Non-dilutive stock options | 5.6 | 5.1 | 2.6 | |||||||
Dilutive common stock equivalent shares | 1.6 | 1.0 | 5.5 |
As a result of the Company incurring a loss for the years ended December 31, 2010 and December 31, 2008, diluted common stock equivalent shares were not included in calculating diluted EPS for those reporting periods.
We issued to MidAmerican Energy Holdings Company (MidAmerican) 19,897,322 shares of Constellation Energy's common stock upon the conversion of the Series A Preferred Stock, which occurred upon the termination of the merger agreement with MidAmerican on December 17, 2008. These additional shares impacted our earnings per share for 2009.
Stock-Based Compensation
Under our long-term incentive plans, we have granted stock options, performance-based units, service-based units, performance and service-based restricted stock, and equity to officers, key employees, and members of the Board of Directors. We discuss these awards in more detail inNote 14.
We elected to early adopt SFAS No. 123 Revised (SFAS No. 123R),Share-Based Payment, on October 1, 2005, which was prior to the required effective date of January 1, 2006. SFAS No. 123R requires companies to recognize compensation expense for all equity-based compensation awards issued to employees that are expected to vest. Equity-based compensation awards include stock options, restricted stock, and any other share-based payments. We recognized a small, favorable cumulative effect of change in accounting principle of $0.2 million after-tax due to the requirement to reduce compensation expense for estimated forfeitures relating to outstanding unvested service-based restricted stock awards and performance-based unit awards at October 1, 2005.
Under SFAS No. 123R, we recognize compensation cost ratably or in tranches (depending if the award has cliff or graded vesting) over the period during which an employee is required to provide service in exchange for the award, which is typically a one to five-year period. We use a forfeiture assumption based on historical experience to estimate the number of awards that are expected to vest during the service period, and ultimately true-up the estimated expense to the actual expense associated with vested awards. We estimate the fair value of stock option awards on the date of grant using the Black-Scholes option-pricing model and we remeasure the fair value of liability awards each reporting period. The following table presents the pro-forma effect on net income and earnings per share for all outstanding stock options and stock awards in each period that the fair value provisions of SFAS No. 123R were not in effect. We do not capitalize any portion of our stock-based compensation.
Year Ended December 31, | 2005 | ||||
---|---|---|---|---|---|
(in millions, except per share amounts) | |||||
Net income, as reported | $ | 623.1 | |||
Add: Actual stock-based compensation expense determined under intrinsic value method and included in reported net income, net of related tax effects | 17.8 | * | |||
Deduct: Pro-forma stock-based compensation expense determined under fair value based method for all awards, net of related tax effects | (24.5) | * | |||
Pro-forma net income | $ | 616.4 | |||
Earnings per share: | |||||
Basic—as reported | $ | 3.51 | |||
Basic—pro-forma | $ | 3.47 | |||
Diluted—as reported | $ | 3.47 | |||
Diluted—pro-forma | $ | 3.43 |
* Represents expense for the nine months ended September 30, 2005, which was prior to adoption of SFAS No. 123R
Cash and Cash Equivalents
All highly liquid investments with original maturities of three months or less are considered cash equivalents.
Accounts Receivable and Allowance for Uncollectibles
Accounts receivable, which includes cash collateral posted in our margin account with a third-party broker,third party brokers, are stated at the historical carrying amount net of write-offs and allowance for uncollectibles. We establish an allowance for uncollectibles based on our expected exposure to the credit risk of customers based on a variety of factors.
Materials, Supplies, and Fuel Stocks
We record our fuel stocks, emissions credits, renewable energy credits, coal held for resale, and materials and supplies at the lower of cost or market. We determine cost using the average cost method for allour entire inventory.
Restricted Cash
At December 31, 2010, our restricted cash primarily included cash at one of our inventory.consolidated variable interest entities, cash held in escrow for the acquisition of the Boston Generating fleet of generating plants, and BGE's funds restricted for the repayment of the rate stabilization bonds. At December 31, 2009, restricted cash also included proceeds from financing for the acquisition, construction, installation and equipping of certain sewage and solid waste disposal facilities at our Brandon Shores coal-fired generating plant in Maryland.
As of December 31, 2010 and 2009, BGE's restricted cash primarily represented funds restricted at its consolidated variable interest entity for the repayment of the rate stabilization bonds. We discuss the rate stabilization bonds in more detail inNote 9.
Financial Investments
InNote 4, we summarize the financial investments that are in our Consolidated Balance Sheets.
SFAS No. 115,Accounting for Certain Investments in Debt and Equity Securities, applies particular requirements to some of We report our investments in debt and equity securities. We report those investmentssecurities at fair value, and we use either specific identification or average cost to determine their cost for computing realized gains or losses.
Available-for-Sale Securities
We classify our investments in the nuclear decommissioning trust funds as available-for-sale securities. We describe the nuclear decommissioning trusts and the related asset retirement obligations later in this Note. In addition, we have investments in marketable equity securities and trust assets securing certain executive benefits that are classified as available-for-sale securities.
We include any unrealized gains (losses) on our available-for-sale securities in "Accumulated other comprehensive loss" in our
Consolidated Statements of Common Shareholders' Equity and Comprehensive Income and Consolidated Statements(Loss).
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Table of Capitalization.Contents
Evaluation of Assets for Impairment and Other Than Temporary Decline in Value
Long-Lived Assets
We are required to evaluate certain assets that have long lives (for example, generating property and equipment and real estate) to determine if they are impaired when certain conditions exist. SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, provides the accounting requirements for impairments of long-lived assets and proved gas properties. We are required to test our long-lived assets and proved gas properties for recoverability whenever events or changes in circumstances indicate that their carrying amount may not be recoverable.
We determine if long-lived assets and proved gas properties are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting records. We would record an impairment loss if the undiscounted expected future cash flows were less than the carrying amount of the asset. Cash flows for long-lived assets, or a group of long-lived assets are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Proven gas properties' cash flows are determined at the field level. Undiscounted expected future cash flows for proved gas properties include risk-adjusted probable and possible reserves.
We are also required to evaluate our equity-method and cost-method investments (for example, in partnerships that own power projects) for impairment. Accounting Principles Board (APB) No. 18,The Equity Method of Accounting for Investments in Common Stock (APB No. 18), provides the accounting requirements for these investments. The standard for determining whetherrecord an impairment must be recorded under APB No. 18 is whetherloss if the investment has experienced aundiscounted expected future cash flows are less than the carrying amount of the asset. The amount of the impairment loss we record equals the difference between the estimated fair value of the asset and its carrying amount in value that is considered an "other than a temporary" decline in value.our accounting records.
We are also required to evaluate unproved gas producing properties at least annually to determine if it is impaired under SFAS No. 19,Financial Accounting and Reporting by Oil and Gas Producing Properties.they are impaired. Impairment for unproved property occurs if there are no firm plans to continue drilling, lease expiration is at risk, or historical experience necessitates a valuation allowance.
We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, legislative initiatives, and operating costs. However, actual future market prices and project costs could vary from those used in our impairment evaluations, and the impact of such variations could be material.
Investments
We evaluate our equity method and cost method investments (for example, CENG, CEP and partnerships that own power projects) to determine whether or not they are impaired. The standard for determining whether an impairment must be recorded is whether the investment has experienced an "other than a temporary" decline in value.
Additionally, if the projects in which we hold these investments recognize an impairment, we would record our proportionate share of that impairment loss and would evaluate our investment for an other than temporary decline in value.
We continuously monitor issues that potentially could impact future profitability of our equity method investments that own coal, hydroelectric, fuel processing projects, as well as our equity investments in our nuclear joint venture and CEP. These issues include environmental and legislative initiatives.
Debt and Equity Securities
Our investments in debt and equity securities, which primarily consist of our nuclear decommissioning trust fund investments, are subject to impairment evaluations under FASB Staff Position (FSP) FAS 115-1,The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments. FSP FAS 115-1 requires us toWe determine whether a decline in fair value of ana debt or equity investment below book value is other than temporary. If we determine that the decline in fair value is judged to be other than temporary, we write-down the cost basis of the investment must be written down to fair value as a new cost basis. For securities held in our nuclear decommissioning trust fund for which the market value is below book value, the decline in fair value for these securities is considered other than temporary and must be written down to fair value.
Goodwill and Intangible Assets
Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We account for goodwill and other intangibles under the provisions of SFAS No. 142,Goodwill and Other Intangible Assets. We do not amortize goodwill. SFAS No. 142 requires us toWe evaluate goodwill for impairment at least annually or more frequently if events and circumstances indicate the business might be impaired. Goodwill is impaired if the carrying value of the business exceeds fair value. Annually, we estimate the fair value of theour businesses we have acquired using techniques similar to those used to estimate future cash flows for long-lived assets as previously discussed. If the estimated fair value of the business is less than its carrying value, an impairment loss is required to be recognized to the extent that the carrying value of goodwill is greater than its fair value. SFAS No. 142 also requires the amortization ofWe amortize intangible assets with finite lives. We discuss the changes in our goodwill and intangible assets in more detail inNote 5.
Property, Plant and Equipment, Depreciation, Depletion, Amortization, and Accretion of Asset Retirement Obligations
We report our property, plant and equipment at its original cost, unless impaired under the provisions of SFAS No. 144.impaired.
Our original costs include:Original cost includes:
We own an undivided interest in the Keystone and Conemaugh electric generating plants in Western Pennsylvania, as well as in the Conemaugh substation and transmission line that transports the plants' output to the joint owners' service territories. Our ownership interests in these plants are 20.99% in Keystone and 10.56% in Conemaugh. These ownership interests represented a net investment of $210.3$338.0 million at December 31, 20072010 and $183.1$339.6 million at December 31, 2006.2009. Each owner is responsible for financing its proportionate share of the plants' working funds. Working funds are used for operating expenses and capital expenditures. Operating expenses related to these plants are included in "Operating expenses" in our Consolidated Statements of Income.Income (Loss). Capital costs related to these plants are included in "Nonregulated property, plant and equipment" in our Consolidated Balance Sheets.
The "Nonregulated property, plant and equipment" in our Consolidated Balance Sheets includes nonregulated generation construction work in progress of $329.6$70.9 million at December 31, 20072010 and $229.5$685.1 million at December 31, 2006.2009.
When we retire or dispose of property, plant and equipment, we remove the asset's cost from our Consolidated Balance Sheets. We charge this cost to accumulated depreciation for assets that were depreciated under the group, straight-line method. This includes regulated property, plant and equipment and nonregulated generating assets transferred from BGE to our merchant energy business.assets. For all other assets, we remove the accumulated depreciation and amortization amounts from our Consolidated Balance Sheets and record any gain or loss in our Consolidated Statements of Income.Income (Loss).
The costs of maintenance and certain replacements are charged to "Operating expenses" in our Consolidated Statements of Income (Loss) as incurred.
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Our oil and gas exploration and production activities consist of working interests in gas producing fields. We account for these activities under the successful efforts method of accounting. Acquisition, development, and exploration costs are capitalized as permitted by SFAS No. 19.capitalized. Costs of drilling exploratory wells are initially capitalized and later charged to expense if reserves are not discovered or deemed not to be commercially viable. Other exploratory costs are charged to expense when incurred.
Capitalized exploratory well costs were $16.8 million at December 31, 2007 and $7.0 million at December 31, 2006, and do not include amounts that were capitalized and subsequently expensed within the same period. There were no material well costs capitalized at December 31, 2006 and 2005 that were reclassified in 2007 and 2006, respectively, to wells, facilities and equipment based on the determination of proved reserves.
There were no material capitalized exploratory well costs charged to expense in 2007, 2006 and 2005. However, there was $12.9 million, $4.1 million, and $1.7 million capitalized as exploratory well costs pending the determination of proved reserves during the years 2007, 2006, and 2005, respectively.
As of December 31, 2007, we have $3.9 million of exploratory well costs, related to one project, that have been capitalized for a period greater than one year since the completion of drilling. These capitalized exploratory well costs are related to wells that are being stimulated and will be evaluated upon completion of this program.
Depreciation and Depletion Expense
We compute depreciation for our generating, electric transmission and distribution, and gas distribution facilities. We compute depletion for our oil and gas exploitation and production activities. Depreciation and depletion are determined using the following methods:
Other assets are depreciated primarily using the straight-line method and the following estimated useful lives:
Asset | Estimated Useful Lives | |
---|---|---|
Building and improvements | 5 | |
Office equipment and furniture | 3 | |
Transportation equipment | 5 | |
Computer software | 3 |
Amortization Expense
Amortization is an accounting process of reducing an asset amount in our Consolidated Balance Sheets over a period of time that approximates the asset's useful life of the related item.life. When we reduce amounts in our Consolidated Balance Sheets, we increaserecord amortization expense in our Consolidated Statements of Income.Income (Loss). We discuss the types of assets that we amortize and the periods over which we amortize them in more detail inNote 5.
Accretion Expense
SFAS No. 143,Accounting for Asset Retirement Obligations, provides the accounting requirements for recognizingWe recognize an estimated liability for legal obligations and legal obligations conditional upon a future event associated with the retirement of tangible long-lived assets. In the fourth quarter of 2005, we adopted 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. Our conditional asset retirement obligations relate primarily to asbestos removal at certain of our generating facilities. In 2005, we recorded an asset retirement obligation of $13.9 million for these facilities and recorded a $7.4 million after-tax charge
Prior to earnings as a cumulative effect of change in accounting principle.
At December 31, 2007, $897.3 millionNovember 6, 2009, substantially all of our total asset retirement obligation of $917.6 million was associated with the decommissioning of our nuclear power plants—Calvert Cliffs Nuclear Power Plant (Calvert Cliffs), Nine Mile Point Nuclear Station (Nine Mile Point) and R. E. Ginna Nuclear Power Plant (Ginna). The remainderUpon the close of ourthe transaction with EDF on November 6, 2009, we deconsolidated CENG and removed the asset retirement obligations isassociated with these nuclear power plants from our Consolidated Balance Sheets. Our remaining asset retirement obligations are associated with our other generating facilities and certain other long-lived assets.
From time to time, we will perform studies to update our asset retirement obligations. We record a liability when we are able to reasonably estimate the fair value of any future legal obligations associated with retirement that have been 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 lives 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 (Loss) until the settlement of the liability. We record a gain or loss when the liability is settled after retirement for any difference between the accrued liability and actual costs. The change in our "Asset retirement obligations" liability during 2007 was as follows:
| (In millions) | |||
---|---|---|---|---|
Liability at January 1, 2007 | $ | 974.8 | ||
Liabilities incurred | 3.9 | |||
Liabilities settled | (1.4 | ) | ||
Accretion expense | 68.3 | |||
Revisions to cash flows | (125.1 | ) | ||
Other | (2.9 | ) | ||
Liability at December 31, 2007 | $ | 917.6 | ||
Substantially all of the $125.1 million "Revisions to expected future cash flows" represents the decrease to our nuclear decommissioning asset retirement obligations in conjunction with site-specific studies that we completed in 2007 for all three of our nuclear sites. These studies reassessed the key assumptions involved in estimating the expected future cost of nuclear decommissioning activities. The resulting decrease in the expected future cost of nuclear decommissioning and the related asset retirement obligation is primarily due to a fleet-based approach incorporating recent industry experiences, technological advances, improved economies of scale, and the impact of Nine Mile Point's license renewal, which was approved in late 2006.
"Other" primarily represents CEP's asset retirement obligation that is no longer included in our Consolidated Balance Sheets. We discuss the deconsolidation of CEP inNote 2.
Nuclear Fuel
We amortize the cost of nuclear fuel, including the quarterly fees we pay to the Department of Energy for the future disposal of spent nuclear fuel, based on the energy produced over the life of the fuel. These fees are based on the kilowatt-hours of electricity sold. We report the amortization expense for nuclear fuel in "Fuel and purchased energy expenses" in our Consolidated Statements of Income.
Nuclear Decommissioning
Effective January 1, 2003, we began to record decommissioning expense for Calvert Cliffs in accordance with SFAS No. 143. The "Asset retirement obligations" liability associated with the decommissioning of Calvert Cliffs was $309.5 million at December 31, 2007 and $336.7 million at December 31, 2006. Our contributions to the nuclear decommissioning trust funds for Calvert Cliffs were $8.8 million for 2007, $8.8 million for 2006, and $17.6 million for 2005. Under the Maryland PSC's order deregulating electric generation, BGE's customers must pay a total of $520 million in 1993 dollars, adjusted for inflation, to decommission Calvert Cliffs. BGE is collecting this amount on behalf of and passing it to Calvert Cliffs. Calvert Cliffs is responsible for any difference between this amount and the actual costs to decommission the plant.
In 2006, BGE received approval from the Maryland PSC to continue annual customer collections of $18.7 million per year through December 31, 2016. BGE will be required to submit a filing to determine the level of customer contributions after December 31, 2016. In addition, Senate Bill 1 required BGE to provide credits to residential electric customers equal to the amount collected for decommissioning annually for ten years beginning in 2007. Under the provisions of Senate Bill 1, we are required to apply the collection of the nuclear decommissioning trust funds over the ten year period beginning in 2007 toward fulfillment of the decommissioning obligations of BGE customers.
We began to record decommissioning expense for Nine Mile Point in accordance with SFAS No. 143 on January 1, 2003. The "Asset retirement obligations" liability associated with the decommissioning was $341.9 million at December 31, 2007 and $408.1 million at December 31, 2006. We determined that the decommissioning trust funds established for Nine Mile Point are adequately funded to cover the future costs to decommission the plant and as such, no contributions were made to the trust funds during the years ended December 31, 2007, 2006, and 2005.
Upon the closing of the Ginna acquisition in 2004, the seller transferred $200.8 million in decommissioning funds. In return, we assumed all liability for the costs to decommission the unit. We believe that this transfer will be sufficient to cover the future costs to decommission the plant and as such, no contributions were made to the trust funds during the years ended December 31, 2007, 2006, and 2005. Effective June 2004, we began to record decommissioning expense for Ginna in accordance with SFAS No. 143. The "Asset retirement obligations" liability associated with the decommissioning was $245.9 million at December 31, 2007 and $209.9 million at December 31, 2006.
In accordance with Nuclear Regulatory Commission (NRC) regulations, we maintain external decommissioning trusts to fund the costs expected to be incurred to decommission Calvert Cliffs, Nine Mile Point, and Ginna. The NRC requires owners to provide financial assurance that they will accumulate sufficient funds to pay for the cost of nuclear decommissioning. The assets in the trusts are reported in "Nuclear decommissioning trust funds" in our Consolidated Balance Sheets. These amounts are legally restricted for funding the costs of decommissioning. We classify the investments in the nuclear decommissioning trust funds as available-for-sale securities, and we report these investments at fair value in our Consolidated Balance Sheets as previously discussed in this Note. Investments by nuclear decommissioning trust funds are guided by the "prudent man" investment principle. The funds
are prohibited from investing directly in Constellation Energy or its affiliates and any other entity owning a nuclear power plant.
As the owner of Calvert Cliffs we, along with other domestic utilities, were required by the Energy Policy Act of 1992 to make contributions to a fund for decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. The contributions were paid by BGE over a 15 year period that ended in 2006. BGE amortizes the deferred costs of decommissioning and decontaminating the Department of Energy's uranium enrichment facilities.
Capitalized Interest and Allowance for Funds Used During Construction
Capitalized Interest
Our nonregulated businesses capitalize interest costs under SFAS No. 34,Capitalizing Interest Costs, for costs incurred to finance our power plant construction projects, real estate developed for internal use, and other capital projects.
Allowance for Funds Used During Construction (AFC)
BGE finances its construction projects with borrowed funds and equity funds. BGE is allowed by the Maryland PSC and the FERC to record the costs of these funds as part of the cost of construction projects in its Consolidated Balance Sheets. BGE does this through the AFC, which it calculates using rates authorized by the Maryland PSC.PSC and the FERC. BGE bills its customers for the AFC plus a return after the utility property is placed in service.
The AFC rates are 9.4%for the period January 1, 2010 through December 3, 2010 were 9.40% for electric distribution plant, 8.5%8.47% for electric transmission plant, 8.49% for gas plant, and 9.2%9.08% for common plant. The AFC rates for the period December 4, 2010 through December 31, 2010 were 8.06% for electric distribution plant, 8.47% for electric transmission plant, 7.90% for gas plant, and 8.07% for common plant. BGE compounds AFC annually.
Long-Term Debt and Credit Facilities
We defer all costs related to the issuance of long-term debt.debt and credit facilities. These costs include underwriters' commissions, discounts or premiums, other costs such as external legal, accounting, and regulatory fees, and printing costs. We amortize these costs related to long-term debt into interest expense over the life
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of the debt. We amortize costs related to credit facilities to other (expenses) income over the terms of the facilities.
In addition to the fees that are paid upfront for credit facilities, we also incur ongoing fees related to these facilities. We record the ongoing fees in other (expense) income, and we record interest incurred on cash draws in interest expense.
When BGE incurs gains or losses on debt that it retires prior to maturity, it amortizes those gains or losses over the remaining original life of the debt.debt in accordance with regulatory requirements.
Accounting Standards IssuedAdopted
SFAS No. 157Accounting for Variable Interest Entities
In September 2006,June 2009, the FASB issued SFAS No. 157. SFAS No. 157 defines fair value, establishes a framework for measuring fair value,amended the accounting, presentation, and requires new disclosures for fair value measurements. SFAS No. 157 became effective for most fair value measurements, other than leases and certain nonfinancial assets and liabilities, beginning January 1, 2008. These exclusions from SFAS No. 157 did not have a material effect on our implementation of this statement.disclosure guidance related to variable interest entities.
The most significant impact of SFAS No. 157 relates to the accounting for derivatives, which is one of our critical accounting policies, inamended standard includes the following ways:significant provisions:
(the primary beneficiary) to mark-to-market accounting includedpresent separately on the initial margin on contractsface of its balance sheet (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which we were unable to obtain observable market information. As a result, we did not recognize gains or losses in earnings at the inception of such contracts; instead, we recognize gains or losses in earnings as we realize cash flows under the contract or when observable market data becomes available. Upon adoption of SFAS No. 157, we continue to reflect a substantial portion of this reserve as an unobservable input valuation adjustment because it relates to contracts executed in our principal market for which SFAS No. 157 requires us to recalibrate our estimate of fair value to reflect transaction price. Therefore, wecreditors do not expecthave recourse to record a material adjustment in retained earnings atthe general credit of the primary beneficiary.
We adopted this guidance on January 1, 2008 to reflect the required adoption of this aspect of SFAS No. 157 using a modified retrospective approach.
SFAS No. 157 also establishes a three-level fair value hierarchy, reflecting the extent to which inputs to the determination of fair value can be observed, and requires fair value disclosures based upon this hierarchy. We will include these disclosuresdiscuss our investments in thevariable interest entities in more detail inNotes to our Consolidated Financial StatementsNote 4 subsequent to the adoption of SFAS No. 157..
SFAS No. 159
In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FASB Statement No. 115. SFAS No. 159 provides the option to report at fair value certain financial instruments that are not currently required or permitted to be measured at fair value. This option would be applied on an instrument by instrument basis. If elected, unrealized gains and losses on the affected financial instruments would be recognized in earnings at each subsequent reporting date. SFAS No. 159 is effective beginning January 1, 2008. We have assessed the provisions of SFAS No. 159 and we have
elected not to apply fair value accounting to our eligible financial instruments. As a result, there will be no impact on our, or BGE's, financial results.
FSP FIN 39-1
In April 2007, the FASB issued Staff Position (FSP) FIN 39-1,Amendment of FASB Interpretation No. 39. FSP FIN 39-1 permits an entity to report all derivatives recorded at fair value with any associated fair value cash collateral, which are with the same counterparty under a master netting arrangement, together in the balance sheet. Our competitive supply operation reports derivative amounts under master netting arrangements net in accordance with FIN 39,Offsetting of Amounts Related to Certain Contracts; however, we report fair value cash collateral separately from our derivative amounts. Under the provisions of this FSP, we expect to report all derivatives recorded at fair value net with the associated fair value cash collateral. The effects of FSP FIN 39-1 will be applied by adjusting all financial statements presented beginning January 1, 2008. We do not expect this standard to have a material impact on our balance sheet presentation.
SFAS No. 141 Revised
In December 2007, the FASB issued SFAS No. 141 Revised (SFAS No. 141R),Business Combinations. SFAS No. 141R revises SFAS 141, Business Combinations. SFAS No. 141R requires an acquirer to determine the fair value of the consideration exchanged as of the acquisition date (i.e., the date the acquirer obtains control). Presently, an acquisition is valued as of the date the parties agree upon the terms of the transaction. SFAS No. 141R also modifies, among other things, the accounting for direct costs associated with an acquisition, contingencies acquired, and contingent consideration. We plan to adopt SFAS No. 141R for business combinations for which the acquisition date occurs after January 1, 2009.
SFAS No. 160
In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements an amendment
Effective January 1, 2009, we adopted guidance relating to the accounting and reporting of ARB No. 51. SFAS No. 160 clarifies that a noncontrolling interestinterests in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 requires that changes in a parent's ownership interest in a subsidiary be reported as an equity transaction in the consolidated financial statements when it does not result in a change in control of the subsidiary. When a change in a parent's ownership interest results in deconsolidation, a gain or loss should be recognized in the consolidated financial statements. SFAS No. 160 must be applied prospectively as of January 1, 2009, except for the presentationWe presented and disclosure requirements, which are required to be applied retrospectively for all periods presented. We are currently evaluating the impact of SFAS No. 160 but do not expect the adoption of this standard to have a material impact ondisclosed our or BGE's, financial results.
Accounting Standards Adopted
FIN 48
In July 2006, the FASB issued FIN 48. FIN 48 provides guidance for the recognition and measurement of an entity's uncertain tax positions. These are defined as positions taken in a previously filed tax return or positions expected to be taken in future tax returns and which result in, among other things, a permanent reduction of income taxes payable, a deferral of income taxes otherwise currently payable to future years, or a change in the expected ability to realize deferred tax assets. Under FIN 48, we are required to recognize the financial statement effects of tax positions if they meet a "more-likely-than-not" threshold. In evaluating items relative to this threshold, we must assess whether each tax position will be sustained based solely on its technical merits assuming examination by a taxing authority.
The adoption of FIN 48 on January 1, 2007, resulted in the recording of a $7.3 million incremental liability for unrecognized tax benefits and a corresponding reduction in "Retained earnings"noncontrolling interests in our Consolidated Balance Sheets asFinancial Statements, and we accounted for the 2009 sale of a cumulative effect of change49.99% membership interest in accounting principle. We also reclassified $49.4 million from existing tax liabilities (primarily deferred income taxes)CENG to the new FIN 48 liability for unrecognized tax benefits. Our resulting total $56.7 million FIN 48 liability for unrecognized tax benefits included $12.1 million of accruedEDF by deconsolidating CENG, measuring our retained interest at fair value, and penalties.
recognizing a gain at closing. We discuss the adoption of FIN 48this transaction in more detail inNote 102.
2Other Events
20072010 Events
| Pre-Tax | After-Tax | ||||||
---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||
Impairment losses and other costs | $ | (20.2 | ) | $ | (12.2 | ) | ||
Workforce reduction costs | (2.3 | ) | (1.4 | ) | ||||
Gain on sales of equity of CEP | 63.3 | 39.2 | ||||||
Loss from discontinued operations | ||||||||
High Desert | (2.4 | ) | (0.3 | ) | ||||
Puna | — | (0.6 | ) | |||||
Total loss from discontinued | ||||||||
operations | (2.4 | ) | (0.9 | ) | ||||
Total other items | $ | 38.4 | $ | 24.7 | ||||
| Pre-Tax | After-Tax | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Impairment losses and other costs | $ | (2,476.8 | ) | $ | (1,487.1 | ) | |
International coal contract dispute settlement | 56.6 | 35.4 | |||||
Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits | (8.8 | ) | |||||
Amortization of basis difference in CENG | (195.2 | ) | (117.5 | ) | |||
Loss on early retirement of 2012 Notes | (51.6 | ) | (30.9 | ) | |||
Impact of power purchase agreement with CENG | (185.6 | ) | (113.3 | ) | |||
Gain on divestitures | 240.0 | 146.0 | |||||
Total other items | $ | (2,612.6 | ) | $ | (1,576.2 | ) | |
Impairment Losses and Other Costs
Impairment Evaluations
We discuss our policy for evaluation of assets for impairment and other than temporary declines in value inNote 1. We perform impairment evaluations for our long-lived assets, equity method and cost method investments, and goodwill when events occur that indicate that the potential for an impairment exists.
During the third quarter of 2010, the following events resulted in the need for us to perform impairment evaluations of our equity method investments as well as the power plants we own:
As a result of these evaluations, we recorded impairments of several of our equity method investments. We describe the impairment evaluations we performed in the following sections.
Equity Method Investments
We evaluated certain of our equity method investments in light of recent declines in commodity prices and the completion of the process that led to our rejection of the terms and conditions of the DOE loan guarantee for the development of new nuclear assets. The investments we evaluated include our investment in CENG, our investment in UNE, and our investments in certain qualifying facilities.
We record an impairment if an investment has experienced a decline in fair value to a level less than our carrying value and the decline is "other than temporary." We do not record an impairment if the decline in value is temporary and we have the ability to recover the carrying amount of our investment. In making this determination, we evaluate the reasons for an investment's decline in value, the extent and length of that decline, and factors that indicate whether and when the value will recover.
CENG
As of September 30, 2010, the estimated fair value of our investment in CENG was $2.9 billion, which was lower than its carrying value of $5.2 billion. The carrying value of our investment reflected fair value as of the November 9, 2009 closing of EDF's investment in CENG. At that time, we were required to deconsolidate CENG and record our retained investment at fair value. We describe this transaction in more detail inNote 16.
There is no active market for the ownership interests in CENG or comparable entities that solely own and operate nuclear power plants. Therefore, we were required to exercise significant judgment in estimating the fair value of our investment based upon information that a market participant would consider. We believe our estimate incorporates the best data available as of September 30, 2010 for each input, which we describe below. However, the resulting fair value amount remains an estimate and is subject to change in the future based upon changes in any of the inputs or the underlying operating, market, and economic conditions we considered.
Because of the absence of relevant market transactions for similar entities, we estimated the fair value of CENG using discounted future cash flows based upon inputs that we believe reflect a market participant's perspective. Our methodology was consistent with the methodology used to estimate fair value in November 2009. The most significant inputs to our estimate of fair value include expectations of nuclear plant performance, future power prices, nuclear fuel and operating costs, forecasted capital expenditures, existing power sales commitments and a discounting factor reflective of an investor's required risk-adjusted return. To the extent possible, we considered available market information and other third-party data for each of the inputs. However, because of the long operating lives of nuclear power plants, we were required to estimate inputs for many years beyond periods for which observable market data is available. Additionally, we compared the inputs to relevant historical information, and we benchmarked our valuation using implied market data of other companies that own nuclear generation facilities.
Upon completion of our evaluation, we determined that the fair value of our investment in CENG had declined by approximately $2.3 billion on a pre-tax basis as of September 30, 2010. The decline in fair value is primarily attributable to the following factors:
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Based upon the extent of the decline below carrying value, the fundamental reasons for the decline, and our assessment that a sufficient improvement in these factors necessary to produce a recovery in fair value is not likely to occur in the near term, we determined that the decline is other than temporary. Therefore, we recorded an approximately $2.3 billion pre-tax impairment charge during the quarter ended September 30, 2010 to write-down our investment to fair value as of that date. We recorded this charge in "Impairment losses and other costs" in our Consolidated Statements of Income (Loss). To the extent that the fair value of our investment declines further in future quarters, we may record additional write-downs if we determine that any additional declines are other than temporary.
UNE
As of September 30, 2010, the estimated fair value of our investment in UNE was zero as compared to its carrying value of $143.4 million.
Prior to the third quarter of 2010, we believed that we would recover our investment in UNE through the development and operation of a new nuclear power plant. However, during the third quarter of 2010, several factors led to a decline in the fair value of our investment, including:
As a result of evaluating these factors, we determined that, as of September 30, 2010, we would not be able to recover the value of our investment. Our determination was based primarily on market-related factors that indicated that a market participant would assign little or no value to this entity due to the absence of a DOE loan guarantee.
We also evaluated whether this decline in fair value was temporary. Based upon the nature of the factors leading to the decline, we determined, at September 30, 2010, that it was unlikely that these matters would be resolved in the near term in a way that would permit recovery in the fair value of our investment. Therefore, we concluded that the decline in the value of our investment in UNE was other than temporary, and we recorded a $143.4 million pre-tax impairment charge during the quarter ended September 30, 2010 to write-down our investment to estimated fair value as of that date. We recorded this charge in "Impairment losses and other costs" in our Consolidated Statements of Income (Loss).
Qualifying Facilities
As a result of the significant declines in power prices during the third quarter of 2010, we determined that the fair values of three of our equity method investments in coal-fired generating plants in California declined substantially below book value. As a result, we recorded a $50.0 million pre-tax impairment charge during the quarter ended September 30, 2010 to write down our investments to fair value as of that date.
Additionally, as a result of a sale of an ownership interest by our partner in the fourth quarter of 2010, we recorded an $8.4 million pre-tax impairment charge on one other equity method investment in California at December 31, 2010. We recorded these charges in the "Impairment losses and other costs" line in our Consolidated Statements of Income (Loss).
Generating Plants
We evaluated the impact of the events that occurred during the third quarter of 2010 on the recoverability of our generating plants. As discussed inNote 1, we evaluated whether these plants would generate undiscounted cash flows from operations that are at least sufficient to recover the carrying value of our investment. Based upon our consideration of these events, the primary impact of which is a reduction in power prices, and the status of the generating plants' activities, we determined that our generating plants were not impaired as of September 30, or December 31, 2010.
Goodwill
We performed our annual impairment review in the quarter ended September 30, 2010 and determined that our goodwill is not impaired.
International Coal Contract Dispute Settlement
During 2010, we finalized the settlement of a contract dispute with a third party international coal supplier recognizing net pre-tax earnings of $56.6 million. We divested the majority of our international commodities operations in 2009.
Deferred Income Tax Expense Relating to Federal Subsidies for Providing Post-Employment Prescription Drug Benefits
During March 2010, the Patient Protection and Affordable Care Act and the Healthcare and Education Reconciliation Act of 2010 were signed into law. These laws eliminate the tax exempt status of drug subsidies provided to companies under Medicare Part D after December 31, 2012. As a result of this new legislation, we recorded a noncash charge to reflect additional deferred income tax expense of $8.8 million in March 2010.
Amortization of Basis Difference in CENG
On November 6, 2009, Constellation Energy sold a 49.99% membership interest in CENG to EDF for total consideration of approximately $4.7 billion (includes $3.5 billion in cash at close, the non-cash redemption of the $1.0 billion Series B Preferred Stock held by EDF, and certain expense reimbursements). As a result, we ceased to have a controlling financial interest in CENG and deconsolidated CENG in the fourth quarter of 2009.
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On November 6, 2009, we began to account for our retained investment in CENG using the equity method and report our share of its earnings in our Generation business segment. As a result, we no longer record the individual income statement line items, but instead record our share of the investment's earnings in a single line in our Consolidated Statements of Income (Loss).
We had an initial basis difference of approximately $3.9 billion between the initial carrying value of our investment in CENG and our underlying equity in CENG. This basis difference was caused by the requirement to record our investment in CENG at fair value at closing while CENG's assets and liabilities retained their carrying value. We are amortizing this basis difference over the respective useful lives of the assets of CENG or as those assets impact the earnings of CENG.
Beginning in the fourth quarter of 2010, the amortization of the basis difference in CENG is lower as the basis difference was reduced by the amount of the impairment charge recorded on our investment in CENG during the quarter ended September 30, 2010. The new basis difference as of September 30, 2010 is $1.5 billion.
For the year ended December 31, 2010, we recorded $195.2 million of pre-tax basis difference amortization as a reduction to our equity investment earnings in CENG. We discuss the components of our equity investment earnings inNote 4.
Loss on Early Retirement of 2012 Notes
In February 2010, we retired an aggregate principal amount of $486.5 million of our 7.00% Notes due April 1, 2012 as part of a cash tender offer, at a premium of approximately 11%. We recognized a pre-tax loss on this transaction of $51.6 million within "Interest Expense" on our Consolidated Statements of Income (Loss).
Impact of Power Purchase Agreement with CENG
In connection with the terminationclosing of the mergerCENG membership sale transaction with EDF, we entered into a five year power purchase agreement (PPA) with CENG with an initial fair value of $0.8 billion.
Based on energy prices at the time of closing of the EDF transaction, we recorded the approximately $0.8 billion "Unamortized energy contract asset" for the value of our PPA with CENG, and CENG recorded an approximately ($0.8) billion "Unamortized energy contract liability." Both entities are amortizing these amounts over the initial two years of the five-year term of the PPA, with the total net economic value to be realized by us in the form of lower purchased power costs equal to approximately $0.4 billion as a result of our 50.01% ownership interest in CENG. During 2010, we realized approximately $185.6 million pre-tax in economic value relating to its PPA with CENG.
Divestitures
BGE
In January 2010, BGE completed the sale of its interest in a nonregulated subsidiary that owns a district chilled water facility to a third party. BGE received net cash proceeds of $20.9 million. No gain or loss was recorded on this transaction in 2010. BGE has no further involvement in the activities of this entity.
Mammoth Lakes Geothermal Generating Facility
In August 2010, we completed the sale of our 50% equity interest in the Mammoth Lakes geothermal generating facility in California. We received net cash proceeds of approximately $72.5 million. In the third quarter of 2010, our Generation business recorded a $38.0 million pre-tax gain on this transaction. We will have no further involvement in the activities of this generating facility.
Comprehensive Agreement with EDF
In November 2010, we closed on the comprehensive agreement with FPL Group, Inc. (FPL Group) in October 2006, which is discussed furtherEDF that restructured the relationship between Constellation Energy and EDF, eliminated the outstanding asset put arrangement, and transferred to EDF the full ownership of UNE. We received approximately $140 million of cash, and $75.2 million of Constellation Energy common stock and recorded a $202.0 million pre-tax gain on this transaction. We discuss the comprehensive agreement with EDF inNote 154,.
Quail Run Energy Center
In December 2010, we acquired certain rights relatingsigned an agreement to sell our Quail Run Energy Center, a wind development project550 MW natural gas plant in Western Maryland. Inwest Texas, to High Plains Diversified Energy Corporation (HPDEC) for $185.3 million. This agreement is contingent upon HPDEC obtaining financing through the second quartersale of 2007, we elected not to make the additional investment that was required at that time to retain our rights in the project; therefore, we recorded a chargemunicipal bonds.
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Table of $20.2 million pre-tax to write-off our investment in these development rights.Contents
Workforce Reduction Costs2009 Events
In June 2007, we approved a restructuring of the workforce at our Nine Mile Point nuclear facility related to the elimination of 23 positions. We recognized costs of $2.3 million pre-tax related to recording a liability for severance and other benefits under our existing benefit programs.
The following table summarizes the status of this involuntary severance liability for Nine Mile Point at December 31, 2007:
| (In millions) | |||
---|---|---|---|---|
Initial severance liability balance (1) | $ | 2.6 | ||
Amounts recorded as pension and postretirement liabilities | (1.5 | ) | ||
Net cash severance liability | 1.1 | |||
Cash severance payments | — | |||
Other | — | |||
Severance liability balance at December 31, 2007 | $ | 1.1 | ||
| Pre-Tax | After-Tax | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Gain on sale of 49.99% membership interest in our nuclear generation and operation business (CENG) to EDF | $ | 7,445.6 | $ | 4,456.1 | |||
Amortization of basis difference in CENG | (29.6 | ) | (17.8 | ) | |||
Net loss on divestitures | (468.8 | ) | (293.2 | ) | |||
Impairment losses and other costs (1) | (124.7 | ) | (96.2 | ) | |||
Impairment of nuclear decommissioning trust assets through November 6, 2009 | (62.6 | ) | (46.8 | ) | |||
Loss on redemption of Zero Coupon Senior Notes | (16.0 | ) | (10.0 | ) | |||
Maryland PSC order—BGE residential customer credits | (112.4 | ) | (67.1 | ) | |||
Merger termination and strategic alternatives costs | (145.8 | ) | (13.8 | ) | |||
Workforce reduction costs | (12.6 | ) | (9.3 | ) | |||
Total other items | $ | 6,473.1 | $ | 3,901.9 | |||
Gain on SalesSale of Equity of CEP49.99% Membership Interest in CENG to EDF
On December 17, 2008, we entered into an Investment Agreement with EDF under which EDF would purchase from us a 49.99% membership interest in CENG for $4.5 billion (subject to certain adjustments).
In November 2006, CEP,October 2009, the Maryland PSC issued an order approving the sale of a limited liability company formed49.99% membership interest in CENG to EDF subject to the following conditions:
With the receipt of the Maryland PSC's order, Constellation Energy and EDF closed the transaction on November 6, 2009. Upon closing of the transaction, we did not participate.
sold a 49.99% membership interest in CENG to EDF for total consideration of approximately $4.7 billion (includes $3.5 billion in cash at close, the non-cash redemption of the $1.0 billion Series B Preferred Stock held by EDF, and certain expense reimbursements). As a result, we retained a 50.01% economic interest in CENG, but we and EDF have equal voting rights over the activities of CENG. Accordingly, we deconsolidated CENG in the fourth quarter of 2009.
We recorded this transaction as follows:
| (In billions) | |||
---|---|---|---|---|
Fair value of the consideration received from EDF | $ | 4.7 | ||
Estimated fair value of our retained interest in CENG | 5.1 | |||
Carrying amount of CENG's assets and liabilities prior to deconsolidation | (2.4 | ) | ||
Pre-tax gain | $ | 7.4 | ||
On November 6, 2009, we began to account for our retained investment in CENG using the equity method and report our share of its earnings in our Generation business segment. As a result, we no longer record the individual income statement line items, but instead record our share of the investment's earnings in a single line in our Consolidated Statements of Income (Loss).
We estimated the fair value of CENG for purposes of recording our retained interest upon closing of the sale. Our estimate considered the replacement cost, discounted future cash
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flows, and comparable market transactions valuation approaches. After correlating the valuations under these three approaches, the ultimate fair value estimate reflects the discounted future expected cash flows of the business using various inputs that we believe are reflective of a market participant's perspective. The most significant inputs include our expectations of nuclear plant performance, future power prices, nuclear fuel and operating costs, forecasted capital expenditures, existing power sales commitments, and a discounting factor reflective of an investor's required risk-adjusted return.
The fair value of our investment in CENG exceeded our share of CENG's equity because CENG's assets and liabilities retained their historical carrying value. This basis difference totaled approximately $3.9 billion, and we assigned it to the noncurrent assets of CENG based on fair value. We will amortize this difference as a reduction in our equity investment earnings in CENG as follows:
Difference | Amortization Period | |
---|---|---|
Property, plant and equipment | Depreciable life | |
Power purchase agreements and revenue sharing agreements | Term of the agreement | |
Land and intangibles with indefinite lives | Upon sale by CENG | |
For the period November 6, 2009 through December 31, 2009, we recorded $29.6 million of basis difference amortization as a reduction to our equity investment earnings in CENG. We discuss the components of our equity investment earnings inNote 4.
Also, if we were to sell an additional portion of our investment, we would recognize a proportionate amount of the basis difference.
Divestitures
In 2009, we completed many of the strategic initiatives we identified in 2008 to improve liquidity and reduce our business risk.
The transactions to sell a majority of our international commodities, our Houston-based gas trading and other operations were structured in two parts:
Under the TRS, we entered into offsetting trades with the buyers that matched the terms of the remaining third party contracts for which we were unable to complete assignment to the buyers as of the transaction dates. This structure transferred the risks associated with changes in commodity prices as of the transaction dates to the buyers in all instances. However, the trades under the TRS are newly executed transactions, and we remain the principal under both the unassigned third party trades and the matching trades with the buyers under the TRS with no right of either financial or legal offset. We continue to pursue the assignment of these remaining contracts to the buyers.
The matching contracts under the TRS include both derivatives and non-derivatives and were executed at prices that differed from market prices at closing, which resulted in a net cash payment to/from the buyers. We recorded the underlying contracts at fair value on a gross basis as assets or liabilities in our Consolidated Balance Sheets depending on whether the contract prices were above- or below-market prices at closing. As a result, the derivative contracts have been included in "Derivative Assets and Liabilities" and the nonderivative contracts have been included in "Unamortized Energy Contract Assets and Liabilities." The derivative contracts are subject to mark-to-market accounting until they are realized or assigned. The nonderivative contracts will be amortized into earnings as the underlying contracts are realized, or sooner if those contracts are assigned.
We record the cash proceeds we pay or receive at the inception of energy purchase and sale contracts based upon whether the contracts are in-the-money or out-of-the-money as follows:
In-the-money contracts—proceeds paid | Investing Outflow | |
Out-of-the-money contracts—proceeds received | Financing Inflow | |
After inception, we record the cash flows from all energy purchase and sale contracts as operating activities, except for out-of-the-money derivative contracts that were liabilities at inception. We record the ongoing cash flows from these out-of-the-money derivative contracts as financing activities, regardless of whether they are purchase or sale contracts.
International Commodities Operation
In January 2009, we entered into a definitive agreement to sell a majority of our international commodities operation. We completed this transaction on March 23, 2009 and recognized the following impacts during 2009:
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We removed the contracts that were assigned from our balance sheet, paid the buyer approximately $90 million, and reflected the impact of this payment on our working capital in the operating activities section of our Consolidated Statements of Cash Flows.
The net cash payment to the buyer upon completion of the TRS was $2.5 million. As part of the consideration, we acquired matching nonderivative contracts that resulted in a net liability of approximately $75 million, which will be amortized into earnings as the underlying contracts are realized, or sooner if the original nonderivative contracts are assigned.
We have reflected the contracts under the TRS on a gross basis in cash flows from investing and financing activities in our Consolidated Statements of Cash Flows as follows:
Year Ended December 31, 2009 | | |||
---|---|---|---|---|
| (In millions) | |||
Investing activities—Contract and portfolio acquisitions | $ | (866.3 | ) | |
Financing activities—Proceeds from contract and portfolio acquisitions | 863.8 | |||
Net cash flows from contract and portfolio acquisitions | $ | (2.5 | ) | |
In addition to the March 23, 2009 transaction for a majority of our international commodities operation, on June 30, 2009 we completed the sale of a uranium market participant that we owned. We received cash proceeds of approximately $43 million and recorded a $27.2 million loss on this sale. This loss from our NewEnergy business segment is included in the "Net (loss) gain on divestitures" line in our Consolidated Statements of Income (Loss).
Houston-Based Gas and Other Trading Operations
On February 3, 2009, we entered into a definitive agreement to sell our Houston-based gas trading operation. We transferred control of this operation on April 2007 equity issuance by CEP, our ownership percentage1, 2009. In addition, in CEP fell below 50 percent. Therefore, during the second quarter of 2007,2009 we deconsolidated CEPalso sold certain other trading operations. In total, we received proceeds of approximately $61 million, and began accountingrecorded a $102.5 million net loss on these sales in 2009. The net loss on sale primarily relates to nonderivative accrual contracts, which were not recorded on our Consolidated Balance Sheet, the cost associated with disposing of an entire portfolio and not merely individual contracts, and the cost of capital, including contingent capital, to support the operation.
The matching derivative and nonderivative transactions under the TRS discussed above were executed at prices that differed from market prices at closing. As a result, we record the ongoing cash flows related to the out-of-the-money derivative contracts that were liabilities at inception as financing cash flows. This resulted in cash outflows related to financing activities of $858.5 million in our Consolidated Statements of Cash Flows for the year ended December 31, 2009 associated with derivative liabilities that were out-of-the-money.
The net cash receipt from the buyers upon completion of the TRS was $91.9 million in the second quarter of 2009. We have reflected these contracts on a gross basis in cash flows from investing and financing activities in our Consolidated Statements of Cash Flows as follows:
Year Ended December 31, 2009 | | |||
---|---|---|---|---|
| (In millions) | |||
Investing activities—Contract and portfolio acquisitions | $ | (1,287.4 | ) | |
Financing activities—Proceeds from contract and portfolio acquisitions | 1,379.3 | |||
Net cash flows from contract and portfolio acquisitions | $ | 91.9 | ||
In addition, we incurred other costs of $7.0 million for 2009 related to leasehold improvements, furniture, computer hardware and software costs, which are recorded as part of "Impairment losses and other costs" on our Consolidated Statements of Income (Loss).
On April 1, 2009, we executed an agreement with the buyer of our Houston-based gas trading operation under which the buyer will provide us with the gas supply needed to support our NewEnergy retail gas customer supply activities through March 31, 2011. This agreement was structured such that our requirements to post collateral are reduced. The supplier has liens on the assets of the retail gas supply business as well as our investment usingin the stock of these entities to secure our obligations under the gas supply agreement. In connection with this agreement, we posted approximately $160 million of collateral. This was subsequently reduced to $100 million. The initial $160 million posted represented approximately 25 percent of the previous collateral requirements to support this operation.
Shipping Joint Venture
We completed the sale of our equity method under Accounting Principles Board Opinion (APB) No. 18,The Equity Methodinvestment in a shipping joint venture during the third quarter of Accounting for Investments in Common Stock.2009. No gain or loss was recognized on the sale. We discuss the sale of the shipping joint venture below.
Other Nonregulated Divestiture
During the fourth quarter of 2009, one of our nonregulated subsidiaries sold an energy project and recorded a net loss of $4.6 million.
Impairment Losses and Other Costs
We discuss our evaluation of assets for impairment and other than temporary declines in value inNote 1. We perform impairment evaluations for our long-lived assets, equity method investments, and goodwill when triggering events occur that indicate the potential for an impairment exists.
Available for Sale Securities
We evaluated certain of accountingour investments in equity securities during 2009. The investments we evaluated included our nuclear decommissioning trust fund assets (through November 6, 2009)
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and other marketable securities. We record an impairment charge if an investment has experienced a decline in fair value to a level less than our carrying value and the decline is "other than temporary."
In making this determination, we evaluate the reasons for an investment's decline in value, the extent and duration of that decline, and factors that indicate whether and when the value will recover. For securities held in our nuclear decommissioning trust fund for which the market value is below book value, the decline in fair value is considered other than temporary and we write them down to fair value. We discuss our impairment policy in more detail inNote 1.
In July and September 2007, CEP issued additional equity. In connection with our equity ownership in CEP, we recognize gains on CEP's equity issuances in the period that the equity is sold as common units or when converted to common units. The detailsfair values of certain of the 2007 CEP equity issuances, as well as the gains recognized by us, are summarized below:
| Units Issued | Price/ Unit | Proceeds to CEP | Pre-tax gain | |||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions, except price/unit) | ||||||||||
April 2007 Sale | |||||||||||
Common units | 2.2 | $ | 26.12 | $ | 58 | $ | 12.5 | ||||
Class E units | 0.1 | 25.84 | 2 | 0.4 | |||||||
July 2007 Sale | |||||||||||
Common units | 2.7 | 35.25 | 94 | 20.0 | |||||||
Class F units | 2.6 | 35.25 | 92 | 11.2 | |||||||
September 2007 Sale | |||||||||||
Common units | 2.5 | 42.50 | 105 | 19.2 |
Discontinued operations
In the fourth quarter of 2006, we completed the sale of six natural gas-fired plants, including the High Desert facility, which was classified as discontinued operations. We recognized an after-tax loss of $0.3 million as a component of "Income (loss) from discontinued operations" for 2007 due to post-closing working capital and income tax adjustments. In addition, during 2007, we recognized an after-tax loss of $0.6 million relating to income tax adjustments arising from the June 2004 sale of a geothermal generating facility in Hawaii that was also previously classified as discontinued operations.
Presented in the table below are the amounts related to discontinued operations that are included in "Income from discontinued operations"securities held in our Consolidated Statements of Income:
| High Desert | Oleander | International Investments | Total | |||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||
Revenues | $ | — | $ | 161.2 | $ | 163.7 | $ | — | $ | — | $ | 14.7 | $ | — | $ | — | $ | 228.1 | $ | — | $ | 161.2 | $ | 406.5 | |||||||||||||
(Loss) income before income taxes | (2.4 | ) | 108.9 | 111.0 | — | — | 8.5 | — | — | 14.5 | (2.4 | ) | 108.9 | 134.0 | |||||||||||||||||||||||
Net (loss) income | (0.3 | ) | 70.2 | 70.8 | — | — | 5.3 | — | — | 4.5 | (0.3 | ) | 70.2 | 80.6 | |||||||||||||||||||||||
Pre-tax impairment charge | — | — | — | — | — | (4.8 | ) | — | — | — | — | — | (4.8 | ) | |||||||||||||||||||||||
After-tax impairment charge | — | — | — | — | — | (3.0 | ) | — | — | — | — | — | (3.0 | ) | |||||||||||||||||||||||
Pre-tax gain on sale | — | 185.2 | — | — | — | 1.2 | — | 1.4 | 25.6 | — | 186.6 | 26.8 | |||||||||||||||||||||||||
After-tax gain on sale | — | 116.7 | — | — | — | 0.7 | — | 0.9 | 16.1 | — | 117.6 | 16.8 | |||||||||||||||||||||||||
(Loss) income from discontinued operations, net of taxes | (0.3 | ) | 186.9 | 70.8 | — | — | 3.0 | — | 0.9 | 20.6 | (0.3 | ) | 187.8 | 94.4 |
During 2007,nuclear decommissioning trust fund held through November 6, 2009 and other marketable securities declined below book value. As a result, we recognized an after-tax loss from discontinued operations of $(0.6) million, related to tax adjustments from the sale of Puna,recorded a Hawaiian Geothermal facility, in 2004.
2006 Events
| Pre-Tax | After-Tax | ||||||
---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||
Gain on sale of gas-fired plants | $ | 73.8 | $ | 47.1 | ||||
Workforce reduction costs | (28.2 | ) | (17.0 | ) | ||||
Merger-related costs | (18.3 | ) | (5.7 | ) | ||||
Gain on initial public offering of CEP | 28.7 | 17.9 | ||||||
Income from discontinued operations | ||||||||
High Desert | 294.1 | 186.9 | ||||||
International investments | 1.4 | 0.9 | ||||||
Total income from discontinued operations | 295.5 | 187.8 | ||||||
Total other items | $ | 351.5 | $ | 230.1 | ||||
Sale of Gas-Fired Plants
In December 2006, we completed the sale of the following natural gas-fired plants owned by our merchant energy business:
We sold these gas-fired plants for cash of $1.6 billion, and recognized a pre-tax gain on the sale of $259.0 million of which $73.8 million was included in "Gain on sale of gas-fired plants" and $185.2 million was included in "Income from discontinued operations" in our Consolidated Statements of Income.
At the time of the agreement for sale, we evaluated these plants for classification as discontinued operations under SFAS No. 144. Discontinued operations classification only applies to assets held for sale that meet the definition of a component of an entity. A component of an entity comprises operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity.
High Desert met the requirements to be classified as a discontinued operation because it had a power sales agreement for its full output, was determined to be a component of Constellation Energy, and had separately identifiable cash flows. The table above provides additional detail about the amounts recorded in "Income from discontinued operations" related to our High Desert facility.
The remaining gas-fired plants were managed within our merchant business as a group or on a portfolio basis because they have aggregated risks, were hedged as a group, and generated joint cash flows. These gas-fired plants do not meet the requirements to be classified as discontinued operations. The results of operations for these gas-fired plants, as well as the $73.8$62.6 million pre-tax gain on sale, remain classified in continuing operations.
International Investments
In the fourth quarter of 2005, we completed the sale of Constellation Power International Investments, Ltd. (CPII). We recognized an after-tax gain of $0.9 millionimpairment charge for the year ended December 31, 2006 due2009 for our nuclear decommissioning trust fund assets in the "Other income (expense)" line in our Consolidated Statements of Income (Loss). We also recorded an impairment charge of $0.5 million for other marketable securities not included in our nuclear decommissioning trust funds for the year ended December 31, 2009.
The estimates we utilize in evaluating impairment of our available for sale securities require judgment and the evaluation of economic and other factors that are subject to variation, and the impact of such variations could be material.
Equity Method Investments
Shipping Joint Venture
We record an impairment if an equity method investment has experienced a decline in fair value to a level less than our carrying value and the decline is other than temporary. During the quarter ended June 30, 2009, we contemplated several potential courses of action together with our partner relating to the resolutionstrategic direction of our shipping joint venture and our continuing involvement. This led to a decision to explore a plan to sell our 50% interest to a party related to our joint venture partner for negligible proceeds. We completed the sale of this investment in the third quarter of 2009. We have no further involvement in the activities of the joint venture.
As a result of the events that occurred during the second quarter of 2009, we concluded that the fair value of our investment had declined to a level below the carrying value at June 30, 2009 and that this decline was other than temporary. As such, we recorded a pre-tax impairment charge of $59.0 million associated with our equity investment in our shipping joint venture within the "Impairment losses and other costs" line in our Consolidated Statements of Income (Loss), and reported the charge in our NewEnergy business segment results for 2009.
Constellation Energy Partners LLC
As of March 31, 2009, the fair value of our investment in Constellation Energy Partners LLC (CEP) based upon its closing unit price was $10.0 million, which was lower than its carrying value of $24.0 million.
The decline in fair value of our investment in CEP at that time reflected a number of factors, primarily including difficulties in the financial and credit markets and the decreases in the market price of natural gas and oil.
As a result of evaluating these factors, we determined that the decline in the value of our investment is other than temporary. Therefore, we recorded a $14.0 million pre-tax impairment charge at March 31, 2009 to write-down our investment to fair value. We recorded this charge in "Impairment losses and other costs" in our Consolidated Statements of Income (Loss). We did not record an impairment charge for the remainder of 2009.
District Chilled Water
During 2009, BGE entered into an agreement to sell its interest in a nonregulated subsidiary that owns a district chilled water facility to a third party. We completed this sale in January 2010. We have no further involvement in the activities of this entity.
As a result of these events, we concluded that the fair value of our investment in this subsidiary had declined to a level below carrying value at December 31, 2009 and that this decline was other than temporary. As such, we recorded a pre-tax impairment charge of $12.0 million, net of the noncontrolling interest impact of $8.0 million. The gross impairment charge of $20.0 million is recorded within the "Impairment losses and other costs" line in both our and BGE's Consolidated Statements of Income (Loss). The noncontrolling interest portion of $8.0 million is recorded within the "Net Income Attributable to Noncontrolling Interests and BGE Preference Stock Dividends" line in our Consolidated Statements of Income (Loss) and within the "Net Income Attributable to Noncontrolling Interests" line in BGE's Consolidated Statements of Income.
Other Costs
During 2009, we recorded $31.2 million pre-tax charges in the "Impairment losses and other costs" line in our Consolidated Statements of Income (Loss) primarily related to:
Loss on Redemption of Zero Coupon Senior Notes
In November 2009, we redeemed the Zero Coupon Senior Notes early and recognized a pre-tax loss on redemption of $16.0 million within "Interest Expense" on our Consolidated Statements of Income (Loss).
Merger Termination and Strategic Alternatives Costs
We incurred additional costs during 2009 related to the sale. We discussterminated merger agreement with MidAmerican, the detailstransactions related to EDF, and other strategic alternatives costs. These costs totaled $145.8 million pre-tax for the year ended December 31, 2009, and primarily relate to fees incurred to complete the transactions with EDF and the first quarter of 2009 write-off of the outstanding contingency laterunamortized debt discount associated with the 14% Senior Notes (Senior Notes) that were repaid in full to MidAmerican in January 2009. Upon the closing of the
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transaction with EDF on November 6, 2009, certain of the costs incurred in 2008 and 2009 became tax deductible. We reflected this Note.impact in 2009.
Workforce Reduction Costs
In March 2006, we approved a restructuring of theWe incurred workforce at our Ginna nuclear facility. In connection with this restructuring, 32 employees were terminated. During the quarter ended March 31, 2006, we recognized costs of
$2.2 million pre-tax related to recording a liability for severance and other benefits under our existing benefit programs.
We completed this workforce reduction effort in 2006. As a result, no involuntary severance liability was recorded at December 31, 2006.
In July 2006, we announced a planned restructuring of the workforce at our Nine Mile Point nuclear facility. We recognized costs during the fourth quarter ended September 30, 2006 of $15.12008, primarily related to workforce reduction efforts across all of our operations (Q4 2008 Program), and during the first quarter of 2009, primarily related to the divestiture of a majority of our international commodities operation as well as some smaller restructurings elsewhere in our organization (Q1 2009 Program). For the Q1 2009 Program, we recognized a $12.6 million pre-tax charge during 2009 related to the elimination of 126 positions associated with this restructuring.approximately 180 positions. We also initiated a restructuring of thesubstantially completed these workforce at our Calvert Cliffs nuclear facilityreductions during the third quarter of 2006 and we recognized costs of $2.9 million pre-tax related to the elimination of 30 positions associated with this restructuring.
In addition, we incurred a pre-tax settlement charge of $12.7 million in accordance with Statement of Financial Accounting Standards (SFAS) No. 88,Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits. This charge reflects recognition of the portion of deferred actuarial gains and losses associated with employees who were terminated as part of the restructuring or retired in 2006 and who elected to receive their pension benefit in the form of a lump-sum payment. In accordance with SFAS No. 88, a settlement charge must be recognized when lump-sum payments exceed annual pension plan service and interest cost. The total SFAS No. 88 settlement charge incurred in 2006 includes a pre-tax charge of $8.0 million as a result of the Nine Mile Point restructuring. We discuss the settlement charges that we recorded during 2006 inNote 7.2010.
The following table summarizes the status of the involuntary severance liability for Nine Mile Point and Calvert Cliffsliabilities at December 31, 2007:2009:
| (In millions) | |||
---|---|---|---|---|
Initial severance liability balance | $ | 19.6 | ||
Amounts recorded as pension and postretirement liabilities | (7.3 | ) | ||
Net cash severance liability | 12.3 | |||
Cash severance payments | (11.0 | ) | ||
Other | — | |||
Severance liability balance at December 31, 2007 | $ | 1.3 | ||
| Q1 2009 Program | Q4 2008 Program | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Initial severance liability balance | $ | 10.8 | $ | 19.7 | |||
Additional expenses recorded in 2009 | 1.8 | — | |||||
Amounts recorded as pension and postretirement liabilities | — | (3.0 | ) | ||||
Net cash severance liability | 12.6 | 16.7 | |||||
Cash severance payments | (12.0 | ) | (15.8 | ) | |||
Severance liability balance at December 31, 2009 | $ | 0.6 | $ | 0.9 | |||
The severance liability above includes $1.6 million of costs that the joint owner of Nine Mile Point Unit 2 reimbursed us.2008 Events
| Pre-Tax | After-Tax | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Merger termination and strategic alternatives costs | $ | (1,204.4 | ) | $ | (1,204.4 | ) | |
Impairment losses and other costs | (741.8 | ) | (470.7 | ) | |||
Workforce reduction costs | (22.2 | ) | (13.4 | ) | |||
Emissions allowances write-down | (46.7 | ) | (28.7 | ) | |||
Net gain on divestitures | 25.5 | 16.0 | |||||
Gain on sale of dry bulk vessel | 29.0 | 18.9 | |||||
Maryland settlement credit (after-tax amount reflects the effective tax rate impact on BGE) | (189.1 | ) | (110.5 | ) | |||
Impairment of nuclear decommissioning trust assets | (165.0 | ) | (82.0 | ) | |||
Total other items | $ | (2,314.7 | ) | $ | (1,874.8 | ) | |
Merger-Related costsMerger Termination and Strategic Alternatives Costs
We incurred costs during 20062008 related to the proposedterminated merger agreement with FPL Group. The merger was terminated in October 2006.MidAmerican, the conversion of Series A Preferred Stock, the execution of the Investment Agreement and related agreements with EDF, and our pursuit of other strategic alternatives. These costs totaled $18.3 million pre-tax$1.2 billion pre-tax. We did not record a tax benefit for 2006. In addition, during 2006 we recognized tax benefitsany of $5.3 million on mergerthese costs in our Consolidated Statement of Income (Loss) in 2008.
A significant portion of these costs was incurred in 2005 that were not considered deductible for income tax purposes untilpursuant to the termination of the merger agreement with MidAmerican and the conversion of the Series A Preferred Stock. Specifically, Constellation Energy incurred the following charges:
The above amounts do not include $150 million of cash received from EDF in conjunction with the Investment Agreement entered into on December 17, 2008. We recorded this $150 million as additional purchase price at closing.
BGE recorded $16 million as its allocable portion of these costs through November 30, 2008 when the merger with MidAmerican was still pending. However, in light of the EDF transaction involving an investment in our nonregulated nuclear generation and operation business rather than a merger with Constellation Energy, BGE was not allocated any further costs effective in December 2008 and all of the previously allocated costs recorded by BGE were allocated to the Generation and NewEnergy segments.
Impairment Losses and Other Costs
Impairment Evaluations
We discuss our evaluation of assets for impairment and other than temporary declines in value inNote 151. We perform impairment evaluations for our long-lived assets, equity method investments, and goodwill when triggering events occur that would indicate that the potential for an impairment exists. We perform an impairment evaluation for our nuclear decommissioning trust fund assets quarterly.
Initial Public Offering In addition, we evaluate goodwill for impairment on an annual basis regardless of CEPwhether any triggering events have occurred. Our accounting policy is to perform an annual goodwill impairment review in the third quarter of each year.
In November 2006, CEP, a limited liability company formed by Constellation Energy, completed an initial public offering During the third quarter of 5.2 million common units at $21 per unit. The initial public offering2008, the following triggering events resulted in the need for us to perform impairment analyses:
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As a result of these evaluations, we recorded impairments of our upstream gas properties, goodwill, and certain investments in debt and equity securities. Additionally, in the fourth quarter of 2008, there were continued declines in commodity prices and the overall stock market. This led to further impairment of our upstream gas properties, and certain investments in debt and equity securities. We describe the impairment evaluations we performed in the following sections.
Long-Lived Assets
We evaluate potential impairment of long-lived assets classified as held for use and recognize an impairment loss if the carrying amount of such assets is not recoverable. The carrying amount of an asset held for use is not recoverable if it exceeds the total undiscounted future cash flows expected to result from the use and eventual disposition of the asset.
This evaluation requires us to estimate uncertain future cash flows. In order to estimate future cash flows, we consider historical cash flows and changes in the market environment and other factors that may affect future cash flows. The assumptions we use are consistent with forecasts that we make for other purposes (for example, in preparing our other earnings forecasts) or have been adjusted to reflect relevant subsequent changes. If we are considering alternative courses of action (such as the potential sale of an asset), we probability- weight the alternative courses of action to estimate the expected cash flows.
We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
Upstream Gas Properties
During 2008, we performed impairment analyses for our upstream gas properties as a result of the following triggering events:
We evaluated both proved and unproved property for impairments. Unproved property is impaired if there are no firm plans to continue drilling, lease expiration is at risk, or historical experience necessitates a valuation allowance. To the extent that unproved property is part of an asset that contains proved property, we applied the accounting guidance for proved property for evaluating impairment.
During the third quarter of 2008, we began the process necessary to sell our upstream gas properties, and, while we sold some of these properties by December 31, 2008, we had not yet obtained the formal approval of our Board of Directors for the sale of our other remaining properties. This approval was required to commit to a plan for sale. As a result, we continued to classify these properties as held for use as of December 31, 2008. Accordingly, our impairment evaluation consisted of estimating expected undiscounted cash flows under various scenarios as discussed below and comparing those amounts to the carrying value.
We evaluated our upstream gas portfolio for impairment at the individual property level, which is the lowest level of identifiable cash flows, since each property has separate financial statements identifying and capturing the related cash flows. We evaluated a combination of cash flows from operations scenarios for the remaining period for which we expected to hold these properties as well as estimates of proceeds from each property's ultimate disposal. The primary inputs to our estimates of $101.3 million, after expensescash flows from operations were reserve estimates and natural gas and oil prices based upon forward curves and modeled data for unobservable periods. The primary inputs to our estimate of proceeds from disposal were a combination of external market bids, internal models and reserve reports, and information from external advisors assisting in the sale of these assets. We maximized the use of market information to the extent it was available. We evaluated several possible courses of action and timing, and we probability-weighted the cash flows associated with each of these scenarios based upon our best estimates of the offering,expected outcome and timing in order to arrive at each property's expected future cash flows.
Our evaluation indicated that estimated cash flows were less than the carrying value of three of our seven upstream gas properties at September 30, 2008. At December 31, 2008, our evaluation indicated that estimated cash flows were less than the carrying value for Constellation Energy.two additional properties and for one property in which that property's estimated cash flows were less than its post-impairment carrying value at September 30, 2008 as well. The primary factors leading to the declines in expected cash flows were the decrease in market prices for natural gas and oil during the third and fourth quarters of 2008 combined with our expectation that we would sell these properties rather than hold them for their full useful lives.
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As a result, we recorded the following pre-tax impairment charges:
Asset Groups | At September 30, 2008 | At December 31, 2008 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Interest in proved and unproved natural gas and crude oil reserves in south Texas | $ | 62.6 | $ | — | |||
Interest in proved natural gas reserves in the Rocky Mountains | 73.2 | — | |||||
Interest in proved and unproved natural gas reserves in the Offshore-Gulf of Mexico | 7.1 | 3.8 | |||||
Interest in proved and unproved crude oil and natural gas reserves in eastern Oklahoma | — | 30.0 | |||||
Interest in proved and unproved natural gas reserves in central Oklahoma | — | 153.2 | |||||
Total impairment charges | $ | 142.9 | $ | 187.0 | |||
We recorded these impairment charges in the "Impairment losses and other costs" line in our Consolidated Statements of Income (Loss), and they are reported in our NewEnergy business segment results.
Generating Plants
We evaluated the impact of the events that occurred in 2008 on the recoverability of our generating plants. Based upon our consideration of these events and the status of the generating plant's activities, we determined that our generating plants were not impaired as of September 30, 2008 and December 31, 2008.
Debt and Equity Securities and Investments
We evaluated certain of our investments in debt and equity securities (both equity-method and cost-method investments) in light of declines in market prices during the third and fourth quarters of 2008. The investments we evaluated included our investment in CEP, other marketable securities, our nuclear decommissioning trust fund assets, and our investment in UNE. We record an impairment if an investment has experienced a decline in fair value to a level less than our carrying value and the decline is other than temporary. We do not record an impairment if the decline in value is temporary and we have the ability and intent to hold the investment until its value recovers.
In making this determination, we evaluate the reasons for an investment's decline in value, the extent and length of that decline, and factors that indicate whether and when the value will recover. For securities held in our nuclear decommissioning trust fund for which the market value is below book value, the decline in fair value for these securities is considered other than temporary and we write them down to fair value.
The fair value of our investment in CEP fell below carrying value at the end of August, and continued to decline through the end of 2008. As of September 30, 2008, the fair value of our investment in CEP based upon its closing unit price was $73 million, which was lower than its carrying value of $128 million. As of December 31, 2008, the fair value of our investment in CEP based upon its closing unit price was $17 million, which was lower than its carrying value at December 31, 2008 of $87 million.
While CEP's estimate of net asset value exceeded our carrying value, the decline in fair value of our investment in CEP at that time reflected a number of factors, primarily including difficulties in the financial and credit markets and the decreases in the market price of natural gas and oil.
As a result of evaluating these factors at both September 30, 2008 and December 31, 2008, we determined that the initial public offeringdeclines in the value of CEP,our investment at both dates were other than temporary. Therefore, we recognizedrecorded a $54.7 million pre-tax impairment charge at September 30, 2008 and an additional $69.7 million pre-tax impairment charge at December 31, 2008 to write-down our investment to fair value. We recorded these charges in "Impairment losses and other costs" in our Consolidated Statements of Income (Loss). To the extent that the market price of our investment declines further in future quarters, we may record additional write-downs if we determine that those additional declines are other than temporary.
As a result of significant declines in the stock market during 2008, the fair values of certain of our marketable securities and many of the securities held in our nuclear decommissioning trust fund declined below book value. As a result, we recorded impairment charges of $31.0 million and $122.0 million pre-tax at September 30, 2008 and December 31, 2008, respectively, for our nuclear decommissioning trust fund investments in the "Other (expense) income" line in our Consolidated Statements of Income (Loss). We had previously recorded impairment charges for our nuclear decommissioning trust fund at both March 31, 2008 and June 30, 2008, totaling $12.0 million pre-tax. We also recorded an impairment charge of $7.0 million pre-tax for certain of our other marketable securities in the fourth quarter of 2008. In addition, we recorded other changes in the fair value of our nuclear decommissioning trust fund assets that are not impaired in other comprehensive income.
We also evaluated the impact of the events that occurred in 2008 on the recoverability of our investment in UNE. Based upon our consideration of these events and the status of UNE's activities, we determined that our investment in UNE was not impaired as of December 31, 2008.
The estimates we utilize in evaluating impairment of our debt and equity securities require judgment and the evaluation of economic and other factors that are subject to variation, and the impact of such variations could be material.
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Goodwill
Goodwill is the excess of the purchase price of an acquired business over the fair value of the net assets acquired. We evaluate goodwill for impairment at least annually or more frequently if events and circumstances indicate the business might be impaired. Goodwill is impaired if the carrying value of the business exceeds fair value. Annually, in the third quarter of each year, we evaluate goodwill for impairment.
The primary judgment affecting our impairment evaluation is the requirement to estimate fair value of the reporting units to which the goodwill relates. We evaluate impairment at the reportable segment level, which is the lowest level in the organization that constitutes a business for which discrete financial information is available.
Prior to September 30, 2008, substantially all of our goodwill related to our merchant energy segment, one of our reportable segments at that time. The lack of observable market prices for the merchant energy segment required us to estimate fair value, which we determined on a preliminary basis using the income valuation approach by computing discounted cash flows, consistent with prior evaluations. Although our estimate of discounted cash flows exceeded the carrying value of the merchant energy segment, because our common stock continued to trade at a price less than carrying value for the entire company throughout the last half of September and all of October, we also estimated fair value for the merchant energy segment using current market price information.
The primary inputs and assumptions to our estimate of fair value based upon market information were as follows:
Using this information, we deducted the estimated fair value of non-merchant energy segment businesses from the fair value of Constellation Energy as a whole in order to estimate the fair value of the merchant energy segment as of September 2008. Based upon this estimate, the fair value of the merchant energy segment was substantially less than its carrying value. The primary difference between this estimate and our modeled estimates using the discounted cash flow income approach is that the market price approach incorporated the market's valuation discount associated with our merchant energy segment due to its significant liquidity and collateral requirements. We believe that this was a more appropriate method for estimating fair value than the modeled valuation techniques because it incorporated observable market information to a greater extent, which reflects current market conditions, and because it required fewer and less subjective judgments and estimates than our modeled estimates.
As a final consideration during our September 2008 impairment evaluation, we also evaluated the circumstances surrounding MidAmerican's purchase of Constellation Energy and whether the current market price of our common stock should be considered to represent fair value for accounting purposes. While the transaction price for the purchase of Constellation Energy resulted from negotiations that occurred over an abbreviated period of time during which the Company was experiencing financial difficulty, ongoing trading of the stock at levels approximating the transaction price represented the market's present assessment of fair value in a liquid, active market. This is consistent with guidance issued by the Securities Exchange Commission Office of the Chief Accountant and FASB Staff on the determination of fair value in distressed markets.
Based on our evaluation of these alternative measures of fair value, we determined that the fair value of the merchant energy business segment was less than its carrying value. Therefore, in order to measure the potential impairment of goodwill, we estimated the fair value of the merchant energy segment's assets and liabilities. We determined that the fair value of its assets net of liabilities substantially exceeded the segment's total fair value, indicating that the merchant energy segment's goodwill was impaired as of September 30, 2008. Accordingly, we recorded a pre-tax gaincharge of $28.7��$266.5 million or $17.9 million after recording deferred taxes onto write-off the gain.entire balance of our merchant energy segment goodwill substantially all of which was recorded in the third quarter of 2008. This charge is recorded in "Impairment losses and other costs" in our Consolidated Statements of Income (Loss).
2005 Events
| Pre-Tax | After-Tax | ||||||
---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||
Merger-related costs | $ | (17.0 | ) | $ | (15.6 | ) | ||
Workforce reduction costs | (4.4 | ) | (2.6 | ) | ||||
Income from discontinued operations | ||||||||
High Desert | 111.0 | 70.8 | ||||||
International investments | 40.1 | 20.6 | ||||||
Oleander | 4.9 | 3.0 | ||||||
Total income from discontinued operations | 156.0 | 94.4 | ||||||
Total other items | $ | 134.6 | $ | 76.2 | ||||
Merger-RelatedOther Costs
We incurred external costs associated withIn September 2008, we entered into a non-binding agreement to settle a class action complaint that alleged a subsidiary's ash placement operations at a third party site damaged surrounding properties. In December 2008, the executionsettlement was approved by the court. As a result of thethis agreement, relating to our proposed merger with FPL Group. We discuss the terminated merger in more detail inNote 15.we recorded a $14.0 million pre-tax charge net of an expected insurance recovery.
Workforce Reduction Costs
In September 2008, our NewEnergy business approved a restructuring of its workforce. We recognized a $2.5 million pre-tax charge during 2008 related to the elimination of approximately 100 positions associated with this restructuring. We substantially completed this workforce reduction during 2009.
During the fourth quarter of 2008, we approved a restructuring of the workforce across all of our operations. We recognized a $19.7 million pre-tax charge in 2008 related to the elimination of approximately 380 positions.
Emissions Allowances
The Clean Air Interstate Rule (CAIR) required states in the eastern United States to reduce emissions of sulfur dioxide (SO2) and established a cap-and-trade program for annual nitrogen oxide (NOx) emission allowances. On July 11, 2008, the United States Court of Appeals for the D.C. Circuit (the "Court") issued an opinion vacating CAIR, subject to petitions for rehearing. The Environmental Protection Agency (EPA) filed a petition for rehearing. On December 23, 2008, the Court reversed its earlier decision to revoke CAIR and allowed CAIR to remain in effect until it is replaced by a revised rule issued by the EPA that would preserve the environmental rules established by CAIR. The Court did not propose a deadline by which the
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EPA must correct the flaws identified with CAIR but it did state that it will accept petitions if the EPA does not remedy the problems previously identified in its July 11, 2008 opinion. The EPA proposed regulations in July 2010, which are pending final adoption.
As a result of the workforce reduction efforts initiatedCourt's December 2008 decision, the annual NOx program became effective in 2004,2009 as originally established by CAIR. In addition, since the December 2008 decision, market prices for 2009 NOx allowances have increased significantly, with lesser increases shown in 2005 we wereallowances for subsequent years. There was also an increase in trading volumes for annual NOx. For the SO2 program, the EPA will be required to recordissue a new rule that would replace the allowances issued under Title IV of the Clean Air Act with a new, reduced pool of allowances which would meet or exceed existing CAIR targets. Market prices for SO2 allowances have also risen since the Court's decision.
We account for our emission allowance inventory at the lower of cost or market, which includes consideration of our expected requirements related to the future generation of electricity. The weighted-average cost of our 2008 SO2 allowance inventory in excess of amounts needed to satisfy these requirements was greater than market value at June 30, 2008 and market prices decreased further for both SO2 and annual NOx emission allowances through September 30, 2008. After giving consideration to the Court's July 11, 2008 decision and the subsequent decline in the market price of these allowances, we recorded a write-down of our SO2 allowance inventory totaling $22.1 million pre-tax settlement chargeto reflect the June 30, 2008 market prices. At September 30, 2008, we recorded an additional write-down of our SO2 emission allowance inventory and recorded a write-down of our annual NOx allowance inventory totaling $58.9 million to reflect the September 30, 2008 prices. These write-downs were recorded in the "Nonregulated revenues" line in our Consolidated Statements of Income (Loss). The third quarter 2008 write-down was partially offset by mark-to-market gains totaling $22.2 million pre-tax on derivative contracts for the forward sale of $4.4emission allowances. This gain reflects the impact of lower market prices on the value of those derivative contracts.
Due to the increases in SO2 and NOx emission allowance prices stemming from the December 23, 2008 Court ruling, we evaluated the value of our emissions allowances and determined that a partial reversal of prior interim period write-downs was appropriate. At December 31, 2008, we reversed $11.4 million of the second and third quarter of 2008 write-downs. The prices at December 31, 2008 create a new cost basis for SO2 and annual NOx emission allowances and cannot be further written-up in future periods. Our mark-to-market gains on derivative contracts for the forward sale of emission allowances were $0.7 million for onethe quarter ended December 31, 2008. We cannot predict the outcome of our qualified pension plans under SFAS No. 88.
In 2005, we completedany further judicial, regulatory or legislative developments or their impact on the 2004 workforce reduction effort.emission allowance markets.
Discontinued OperationsNet Gain on Divestitures
On March 31, 2008, we sold our working interest in oil and natural gas producing properties in Oklahoma to CEP, a related party, and recognized a gain of $14.3 million, net of the minority interest gain of $0.7 million. We discuss this transaction in more detail inOleanderNote 16.
In addition, on June 30, 2008, our NewEnergy business sold a portion of its working interests in proved natural gas reserves and unproved properties in Arkansas to an unrelated party for total proceeds of $145.4 million, which is subject to certain purchase price adjustments. Our NewEnergy business recognized a $77.7 million pre-tax gain on this sale.
In December 2008, our NewEnergy business sold working interests in proved natural gas reserves in Wyoming, and our equity investment in certain entities that own interests in proved natural gas reserves and unproved properties in Texas and Montana to unrelated parties for total proceeds of $55.7 million, subject to certain purchase price adjustments. Our NewEnergy business recognized a $67.2 million pre-tax loss on these sales.
The net gain is included in "Net (Loss) Gains on Divestitures" line in our Consolidated Statements of Income (Loss).
Gain on Sale of Dry Bulk Vessel
On July 10, 2008, a shipping joint venture, in which our NewEnergy business has a 50% ownership interest, sold one of the six dry bulk vessels it owns. Our NewEnergy business recognized a $29.0 million pre-tax gain on this sale. The gain is included in "Nonregulated revenues" line in our Consolidated Statements of Income (Loss).
Maryland Settlement Agreement—Customer Rate Credit
In March 2005, we reached an2008, Constellation Energy, BGE and a Constellation Energy affiliate entered into a settlement agreement in principlewith the State of Maryland, the Maryland PSC and certain State of Maryland officials to sell our Oleander generating facility, a four-unit peaking plant located in Florida. Our merchant energy business classified Oleander as held for saleresolve pending litigation and performed an impairment test under SFAS No. 144 asto settle other prior legal, regulatory and legislative issues. On April 24, 2008, the Governor of March 31, 2005. The impairment test indicatedMaryland signed enabling legislation, which became effective on June 1, 2008. Pursuant to the terms of the settlement agreement:
In June 2005, we completed1993 dollars adjusted for inflation, pursuant to the sale of this facility for $217.6 million, and recognized a pre-tax gain on the sale of $1.2 million as part of discontinued operations.1999 Maryland PSC order
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International InvestmentsTable of Contents
In October 2005, we sold CPII. CPII held our other nonregulated international investments,regarding the deregulation of electric generation. BGE will continue to collect the $18.7 million annual nuclear decommissioning charge from all electric customers through 2016 and continue to rebate this amount to residential electric customers, as previously required by Senate Bill 1, which represented an interesthad been enacted in a PanamanianJune 2006.
109
Table of certain receivables by March 31, 2006. At December 31, 2005, we recognized approximately $2.2 million of this amount based on cash collections, which was included in the $25.6 million pre-tax gain. We recognized the remaining $1.4 million of contingent proceeds in 2006 once realization was assured beyond a reasonable doubt.Contents
3Information by Operating Segment
Our reportable operating segments are—Merchant Energy,are Generation, NewEnergy, Regulated Electric, and Regulated Gas:
Our remaining nonregulated businesses:
During 2006, we sold six of our gas-fired facilities. In addition, we own several investments that we do not consider to be core operations. These include financial investments and real estate projects. During 2005, we sold our other nonregulated international investments. We discuss the sales of our gas-fired plants and our international investments in more detail inNote 2.
Our Merchant Energy,Generation, NewEnergy, Regulated Electric, and Regulated Gas reportable segments are strategic businesses based principally upon regulations, products, and services that require different technologytechnologies and marketing strategies. We evaluate the performance of these segments based on net income. We account for intersegment revenues using market prices. We present aA summary of information by operating segment onis shown in the next page.table below.
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| Reportable Segments | | | | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Merchant Energy Business | Regulated Electric Business | Regulated Gas Business | Other Nonregulated Businesses | Eliminations | Consolidated | |||||||||||||
| (In millions) | ||||||||||||||||||
2007 | |||||||||||||||||||
Unaffiliated revenues | $ | 17,545.1 | $ | 2,455.6 | $ | 943.0 | $ | 249.5 | $ | — | $ | 21,193.2 | |||||||
Intersegment revenues | 1,199.4 | 0.1 | 19.8 | 0.3 | (1,219.6 | ) | — | ||||||||||||
Total revenues | 18,744.5 | 2,455.7 | 962.8 | 249.8 | (1,219.6 | ) | 21,193.2 | ||||||||||||
Depreciation, depletion, and amortization | 269.9 | 187.4 | 46.8 | 53.7 | — | 557.8 | |||||||||||||
Fixed charges | 86.9 | 107.6 | 30.9 | 8.6 | 71.6 | 305.6 | |||||||||||||
Income tax expense (benefit) | 332.7 | 64.6 | 22.8 | 8.2 | — | 428.3 | |||||||||||||
Income from discontinued operations | (0.9 | ) | — | — | — | — | (0.9 | ) | |||||||||||
Net income (a) | 678.3 | 97.9 | 28.8 | 16.5 | — | 821.5 | |||||||||||||
Segment assets | 16,151.1 | 4,378.4 | 1,293.6 | 458.6 | (336.0 | ) | 21,945.7 | ||||||||||||
Capital expenditures | 1,178.0 | 340.0 | 62.0 | 85.0 | — | 1,665.0 | |||||||||||||
2006 | |||||||||||||||||||
Unaffiliated revenues | $ | 16,048.2 | $ | 2,115.9 | $ | 890.0 | $ | 230.8 | $ | — | $ | 19,284.9 | |||||||
Intersegment revenues | 1,118.0 | — | 9.5 | 0.2 | (1,127.7 | ) | — | ||||||||||||
Total revenues | 17,166.2 | 2,115.9 | 899.5 | 231.0 | (1,127.7 | ) | 19,284.9 | ||||||||||||
Depreciation, depletion, and amortization | 258.7 | 181.5 | 46.0 | 37.7 | — | 523.9 | |||||||||||||
Fixed charges | 191.7 | 86.9 | 28.9 | 10.5 | 10.7 | 328.7 | |||||||||||||
Income tax expense (benefit) | 250.2 | 78.0 | 27.0 | (4.2 | ) | — | 351.0 | ||||||||||||
Income from discontinued operations | 186.9 | — | — | 0.9 | — | 187.8 | |||||||||||||
Net income (b) | 767.0 | 120.2 | 37.0 | 12.2 | — | 936.4 | |||||||||||||
Segment assets | 16,387.3 | 3,783.2 | 1,252.8 | 887.8 | (509.5 | ) | 21,801.6 | ||||||||||||
Capital expenditures | 768.0 | 297.0 | 63.0 | 21.0 | — | 1,149.0 | |||||||||||||
2005 | |||||||||||||||||||
Unaffiliated revenues | $ | 13,763.1 | $ | 2,036.5 | $ | 961.7 | $ | 207.0 | $ | — | $ | 16,968.3 | |||||||
Intersegment revenues | 859.3 | — | 11.1 | — | (870.4 | ) | — | ||||||||||||
Total revenues | 14,622.4 | 2,036.5 | 972.8 | 207.0 | (870.4 | ) | 16,968.3 | ||||||||||||
Depreciation, depletion and amortization | 250.4 | 185.8 | 46.6 | 40.2 | — | 523.0 | |||||||||||||
Fixed charges | 178.0 | 80.3 | 26.4 | 10.0 | 15.5 | 310.2 | |||||||||||||
Income tax expense (benefit) | 41.7 | 101.2 | 21.2 | (0.2 | ) | — | 163.9 | ||||||||||||
Income from discontinued operations | 73.8 | — | — | 20.6 | — | 94.4 | |||||||||||||
Cumulative effects of changes in accounting principles | (7.4 | ) | — | — | 0.2 | — | (7.2 | ) | |||||||||||
Net income (c) | 425.8 | 149.4 | 26.7 | 21.2 | — | 623.1 | |||||||||||||
Segment assets | 16,620.4 | 3,424.4 | 1,222.5 | 476.1 | (269.5 | ) | 21,473.9 | ||||||||||||
Capital expenditures | 709.0 | 241.0 | 50.0 | 32.0 | — | 1,032.0 |
| Reportable Segments | | | | ||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Holding Company and Other | | | |||||||||||||||||||
| Generation | NewEnergy | Regulated Electric | Regulated Gas | Eliminations | Consolidated | ||||||||||||||||
| (In millions) | |||||||||||||||||||||
2010 | ||||||||||||||||||||||
Unaffiliated revenues | $ | 1,189.2 | $ | 9,692.6 | $ | 2,752.1 | $ | 704.9 | $ | 1.2 | $ | — | $ | 14,340.0 | ||||||||
Intersegment revenues | 1,055.1 | 428.8 | 0.2 | 4.5 | — | (1,488.6 | ) | — | ||||||||||||||
Total revenues | 2,244.3 | 10,121.4 | 2,752.3 | 709.4 | 1.2 | (1,488.6 | ) | 14,340.0 | ||||||||||||||
Depreciation, depletion, and amortization | 136.1 | 83.4 | 205.2 | 44.0 | 48.9 | — | 517.6 | |||||||||||||||
Fixed charges | 142.0 | 3.0 | 106.3 | 24.0 | (0.2 | ) | 2.7 | 277.8 | ||||||||||||||
Income tax (benefit) expense | (873.1 | ) | 106.5 | 72.6 | 24.5 | 3.8 | — | (665.7 | ) | |||||||||||||
Net (loss) income (1) | (1,255.3 | ) | 176.2 | 110.0 | 37.6 | (0.3 | ) | — | (931.8 | ) | ||||||||||||
Net (loss) income attributable to common stock | (1,255.3 | ) | 138.6 | 99.8 | 34.6 | (0.3 | ) | — | (982.6 | ) | ||||||||||||
Segment assets | 9,789.6 | 3,836.2 | 5,287.4 | 1,379.9 | 858.0 | (1,132.6 | ) | 20,018.5 | ||||||||||||||
Capital expenditures | 327.4 | 127.2 | 499.1 | 103.0 | — | — | 1,056.7 | |||||||||||||||
2009 | ||||||||||||||||||||||
Unaffiliated revenues | $ | 664.2 | 11,345.8 | $ | 2,820.7 | $ | 753.8 | $ | 14.3 | $ | — | $ | 15,598.8 | |||||||||
Intersegment revenues | 2,110.0 | 163.4 | — | 4.5 | 0.1 | (2,278.0 | ) | — | ||||||||||||||
Total revenues | 2,774.2 | 11,509.2 | 2,820.7 | 758.3 | 14.4 | (2,278.0 | ) | 15,598.8 | ||||||||||||||
Depreciation, depletion, and amortization | 176.8 | 82.5 | 218.1 | 44.0 | 67.7 | — | 589.1 | |||||||||||||||
Fixed charges | 166.5 | 39.7 | 113.3 | 26.0 | 2.4 | 2.2 | 350.1 | |||||||||||||||
Income tax expense (benefit) | 3,107.1 | (179.1 | ) | 50.9 | 17.1 | (9.2 | ) | — | 2,986.8 | |||||||||||||
Net income (loss) (2) | 4,766.7 | (348.2 | ) | 79.1 | 25.5 | (19.7 | ) | — | 4,503.4 | |||||||||||||
Net income (loss) attributable to common stock | 4,766.7 | (402.3 | ) | 68.9 | 22.5 | (12.4 | ) | — | 4,443.4 | |||||||||||||
Segment assets | 12,402.1 | 4,167.5 | 4,994.6 | 1,413.4 | 4,573.7 | (4,006.9 | ) | 23,544.4 | ||||||||||||||
Capital expenditures | 1,039.2 | 116.8 | 373.0 | 66.0 | — | — | 1,595.0 | |||||||||||||||
2008 | ||||||||||||||||||||||
Unaffiliated revenues | $ | 856.2 | 15,185.4 | $ | 2,679.5 | $ | 1,004.8 | $ | 16.0 | $ | — | $ | 19,741.9 | |||||||||
Intersegment revenues | 2,102.3 | 666.3 | 0.2 | 19.2 | 0.1 | (2,788.1 | ) | — | ||||||||||||||
Total revenues | 2,958.5 | 15,851.7 | 2,679.7 | 1,024.0 | 16.1 | (2,788.1 | ) | 19,741.9 | ||||||||||||||
Depreciation, depletion, and amortization | 174.3 | 118.7 | 184.2 | 43.7 | 62.3 | — | 583.2 | |||||||||||||||
Fixed charges | 140.7 | 50.6 | 113.5 | 26.3 | 2.3 | 15.7 | 349.1 | |||||||||||||||
Income tax expense (benefit) | 121.3 | (226.0 | ) | (4.9 | ) | 25.5 | 5.8 | — | (78.3 | ) | ||||||||||||
Net (loss) income (3) | (357.7 | ) | (1,011.4 | ) | 11.1 | 40.4 | (0.8 | ) | — | (1,318.4 | ) | |||||||||||
Net (loss) income attributable to common stock | (357.7 | ) | (994.2 | ) | 1.1 | 37.2 | (0.8 | ) | — | (1,314.4 | ) | |||||||||||
Segment assets (4) | 11,205.9 | 7,063.5 | 4,583.1 | 1,392.4 | 3,431.6 | (5,392.4 | ) | 22,284.1 | ||||||||||||||
Capital expenditures | 1,445.2 | 315.8 | 388.0 | 74.0 | — | — | 2,223.0 |
4Investments
Investments in Joint Ventures, Qualifying Facilities and Power Projects, CEP, and Joint VenturesCEP
Qualifying FacilitiesInvestments in joint ventures, qualifying facilities, domestic power projects, and Power Projects
Our merchant energy business holds up to a 50% voting interest in 24 operating domestic energy projects thatCEP consist of electric generation, fuel processing, or fuel handling facilities. Of these 24the following:
At December 31, | 2010 | 2009 | ||||||
---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||
Joint Ventures: | ||||||||
CENG | $ | 2,991.1 | $ | 5,222.9 | ||||
UNE | — | 122.0 | ||||||
Qualifying facilities and domestic power projects: | ||||||||
Coal | 65.0 | 119.7 | ||||||
Hydroelectric | 46.3 | 55.2 | ||||||
Geothermal | — | 40.0 | ||||||
Biomass | 55.1 | 56.2 | ||||||
Fuel Processing | 16.7 | 24.3 | ||||||
Solar | 6.8 | 6.9 | ||||||
Total | $ | 3,181.0 | $ | 5,647.2 | ||||
Investments in joint ventures, qualifying facilities, domestic power projects, 17 are "qualifying facilities" that receive certain exemptions and pricingCEP were accounted for under the Public Utility Regulatory Policies Act of 1978 based on the facilities' energy source or the use of a cogeneration process.following methods:
CEP
At December 31, | 2010 | 2009 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Equity method | $ | 3,174.2 | $ | 5,640.3 | |||
Cost method | 6.8 | 6.9 | |||||
Total | $ | 3,181.0 | $ | 5,647.2 | |||
In November 2006, CEP, a limited liability company formed by We are actively involved in our merchant energy business, completed an initial public offering. As of December 31, 2006, we owned approximately 54% of CEPCENG nuclear joint venture, qualifying facilities and consolidated CEP. During the second quarter of 2007, CEP issued additional equity to the public and our ownershippower projects. Our percentage fell below 50%. Therefore, we deconsolidated CEP and began accountingvoting interests in these investments accounted for our investment usingunder the equity method under Accounting Principles Board Opinion (APB) No. 18,range from 20% to 50.01%. Equity in earnings of these investments is as follows:
Year ended December 31, | 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
CENG | $ | 218.8 | $ | 33.9 | $ | — | ||||
Amortization of basis difference in CENG (seeNote 2 for more detail) | (195.2 | ) | (29.6 | ) | — | |||||
Total equity investment earnings—CENG (1) | 23.6 | 4.3 | — | |||||||
UNE | (16.8 | ) | (24.7 | ) | (5.9 | ) | ||||
Shipping JV | — | (1.8 | ) | 37.4 | ||||||
CEP | — | (4.6 | ) | 7.7 | ||||||
Qualifying facilities and domestic power projects | 18.2 | 20.7 | 37.2 | |||||||
Total equity investment earnings | $ | 25.0 | $ | (6.1 | ) | $ | 76.4 | |||
We describe each of these investments below. Additionally, we recorded impairment charges on certain of our equity method investments. We discuss these impairment charges inThe Equity Method of Accounting for Investments in Common StockNote 2. As of December 31, 2007, we hold a 28.5% voting interest in CEP.
Joint Ventures
CENG
On November 6, 2009, we completed the sale of a 49.99% membership interest in CENG, our nuclear generation and operation business, to EDF. As a result of this transaction, we deconsolidated CENG and began to record our 50.01% investment in CENG under the equity method of accounting. Because the transaction occurred on November 6, 2009, we recorded $4.3 million of equity investment earnings in CENG, which represents our share of earnings from CENG from November 6, 2009 through December 31, 2009, net of the amortization of the basis difference in CENG. The basis difference is the difference between the fair value of our investment in CENG at closing and our share of the underlying equity in CENG, because the underlying assets and liabilities of CENG were retained at their carrying value. SeeNote 2 for a more detailed discussion.
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Summarized balance sheet information for CENG is as follows:
At December 31, | 2010 | 2009 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Current assets | $ | 507.4 | $ | 513.0 | |||
Noncurrent assets | 4,583.0 | 4,404.2 | |||||
Current liabilities | 630.9 | 556.9 | |||||
Noncurrent liabilities | 1,338.7 | 1,716.1 |
Summarized income statement information for CENG is as follows:
| For the Year Ended December 31, 2010 | For the Period from November 6, 2009 through December 31, 2009 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Revenues | $ | 1,575.3 | $ | 217.6 | |||
Expenses | 1,174.5 | 153.0 | |||||
Income from operations | 400.8 | 64.6 | |||||
Net income | 441.6 | 68.5 |
In December 2006,future periods, we formedmay be eligible for distributions from CENG in excess of our 50.01% ownership interest based on tax sharing provisions contained in the operating agreement for CENG. We would record these distributions, if realized, in earnings in the period received.
Comprehensive Agreement with EDF
On October 26, 2010, we reached a shipping joint venture in whichcomprehensive agreement with EDF that restructured the relationship between our merchant energy business has atwo companies, eliminated the outstanding asset put arrangement, and transferred to EDF the full ownership of UNE. This comprehensive agreement was approved by the boards of directors of both Constellation Energy and EDF, and the transaction closed on November 3, 2010. The agreement includes the following significant terms:
Later in November 2010, EDF transferred to us 0.1 million shares of Constellation Energy common stock, with a fair value of $2.8 million, in a noncash financing, upon our registering EDF's remaining shares of Constellation Energy common stock with the Securities and Exchange Commission. This enables EDF to transfer its remaining shares without restriction. We recorded a total pre-tax gain of $202.0 million in the fourth quarter of 2010 related to the joint venture.above aspects of our comprehensive agreement with EDF.
In addition, upon receipt of necessary approvals:
We and EDF will remain owners in CENG under the same ownership percentages—Constellation Energy holding a 50.01% interest and EDF holding a 49.99% interest. Further:
We discuss the PPA and ASA in more detail inNote 16.
UNE
In August 2007, we formed a joint venture, UniStar Nuclear Energy, LLC (UNE)UNE, with an affiliate of Electricite de France, SA (EDF). We have a 50% ownership interest in this joint ventureEDF to develop, own, and operate new nuclear projects in the United States and Canada. The agreement withOn November 3, 2010, we sold our 50% ownership interest in UNE to EDF. As a result of this transaction, EDF includes a phased-in investmentis the sole owner of $625 million by EDF in UNE. In 2007, EDF invested $350 million in UNE, and we contributed thewill no longer have responsibility for developing or financing new nuclear line of businesses we have developed over the past two years, which included assets with a book value of $48.7 millionplants through UNE.
Qualifying Facilities and the right to develop possible new nuclear projects at our existing nuclear plant locations. Upon reaching certain licensing milestones, EDF will contributePower Projects
Our Generation business holds up to a 50% voting interest in 15 operating domestic energy projects that consist of electric generation, fuel processing, or fuel handling facilities. Of these 15 projects, 13 are "qualifying facilities" that receive certain exemptions and pricing under the Public Utility Regulatory Policies Act of 1978 based on the facilities' energy source or the use of a cogeneration process.
CEP
In November 2006, CEP, a limited liability company formed by our NewEnergy business, completed an additional $275 million in UNE.
initial public offering. As of December 31, 2006, we owned approximately 54% of CEP and consolidated CEP. During the second quarter of 2007, UNE's capitalized construction work in progress was approximately $135 million. InCEP issued additional equity to the event thatpublic and our portion of any losses incurred by UNE exceedownership percentage fell below 50%. Therefore, we deconsolidated CEP and began accounting for our investment we will continue to record those losses in earnings unless it is determined that UNE will cease operations and is subsequently dissolved.
Investments in qualifying facilities, domestic power projects, joint ventures and CEP consist of the following:
At December 31, | 2007 | 2006 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Qualifying facilities and domestic power projects: | |||||||
Coal | $ | 119.6 | $ | 125.7 | |||
Hydroelectric | 54.7 | 55.1 | |||||
Geothermal | 37.6 | 40.5 | |||||
Biomass | 43.6 | 46.6 | |||||
Fuel Processing | 26.8 | 33.7 | |||||
Solar | 7.0 | 7.0 | |||||
CEP | 143.0 | — | |||||
Joint Ventures: | |||||||
Shipping JV | 56.6 | — | |||||
UNE | 52.2 | — | |||||
Other | 1.1 | — | |||||
Total | $ | 542.2 | $ | 308.6 | |||
Investments in qualifying facilities, domestic power projects, CEP and joint ventures were accounted for under the following methods:
At December 31, | 2007 | 2006 | ||||
---|---|---|---|---|---|---|
| (In millions) | |||||
Equity method | $ | 535.2 | $ | 301.6 | ||
Cost method | 7.0 | 7.0 | ||||
Total | $ | 542.2 | $ | 308.6 | ||
Our percentage voting interests in these investments accounted for underusing the equity method range from 16% to 50%. Equity in earnings
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Investments Classified as Available-for-SaleContents
We classify the following investments as available-for-sale:
This means we do not expect to hold them to maturity, and we do not consider them trading securities.
We show the fair values, gross unrealized gains and losses, and book value basis for allmethod. As of our available-for-sale securities in the following tables. We use specific identification to determine cost in computing realized gains and losses.
At December 31, 2007 | Book Value | Unrealized Gains | Unrealized Losses | Fair Value | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||
Marketable equity securities | $ | 819.9 | $ | 266.3 | $ | (0.2 | ) | $ | 1,086.0 | |||
Corporate debt and U.S. treasuries | 224.5 | 5.4 | — | 229.9 | ||||||||
State municipal bonds | 48.3 | 2.5 | — | 50.8 | ||||||||
Totals | $ | 1,092.7 | $ | 274.2 | $ | (0.2 | ) | $ | 1,366.7 | |||
At December 31, 2006 | Book Value | Unrealized Gains | Unrealized Losses | Fair Value | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||
Marketable equity securities | $ | 811.0 | $ | 221.1 | $ | (3.3 | ) | $ | 1,028.8 | |||
Corporate debt and U.S. treasuries | 160.1 | 1.9 | (0.3 | ) | 161.7 | |||||||
State municipal bonds | 68.1 | 5.4 | (0.2 | ) | 73.3 | |||||||
Totals | $ | 1,039.2 | $ | 228.4 | $ | (3.8 | ) | $ | 1,263.8 | |||
In addition to the above securities, the nuclear decommissioning trust funds included $11.7 million at December 31, 2007 and $24.1 million at December 31, 2006 of cash and cash equivalents.2010, we hold a 28.5% voting interest in CEP.
The preceding tables include $256.7 million in 2007 of net unrealized gains and $206.1 million in 2006 of net unrealized gains associated with the nuclear decommissioning trust funds that are reflected as a change in the nuclear decommissioning trust funds in our Consolidated Balance Sheets.
Our available-for-sale investments in our nuclear decommissioning trust funds are managed by third parties who have independent discretion over the purchases and sales of securities. Effective January 1, 2007, we recognize impairments for any of these investments for which the fair value declines below our book value. In 2007, we recognized $8.5 million pre-tax of impairment losses on our nuclear decommissioning trust investments.
Prior to 2007, we had unrealized losses relating to certain available-for-sale investments in our nuclear decommissioning trust funds that we considered to be temporary in nature and, therefore, we did not recognize an impairment for any security with an unrealized loss. We show the fair values and unrealized losses of our investments that were in a loss position at December 31, 2006 and were not impaired in the table below.
At December 31, 2006 | |||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Less than 12 months | 12 months or more | Total | ||||||||||||||||
| |||||||||||||||||||
Description of Securities | Fair Value | Unrealized Losses | Fair Value | Unrealized Losses | Fair Value | Unrealized Losses | |||||||||||||
| (In millions) | ||||||||||||||||||
Marketable equity securities | $ | 9.5 | $ | (0.8 | ) | $ | 12.4 | $ | (1.7 | ) | $ | 21.9 | $ | (2.5 | ) | ||||
Corporate debt and U.S. treasuries | 10.3 | — | 23.7 | (0.3 | ) | 34.0 | (0.3 | ) | |||||||||||
State municipal bonds | 4.8 | — | 14.0 | (0.2 | ) | 18.8 | (0.2 | ) | |||||||||||
Total temporarily impaired securities | $ | 24.6 | $ | (0.8 | ) | $ | 50.1 | $ | (2.2 | ) | $ | 74.7 | $ | (3.0 | ) | ||||
Gross and net realized gains and losses on available-for-sale securities were as follows:
Year ended December 31, | 2007 | 2006 | 2005 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Gross realized gains | $ | 33.5 | $ | 13.3 | $ | 12.3 | ||||
Gross realized losses | (30.9 | ) | (13.0 | ) | (9.3 | ) | ||||
Net realized gains | $ | 2.6 | $ | 0.3 | $ | 3.0 | ||||
Gross realized losses for 2007 include an $8.5 million pre-tax other than temporary impairment (as explained above) for investments whose fair value declined below their book value.
The corporate debt securities, U.S. Government agency obligations, and state municipal bonds mature on the following schedule:
At December 31, 2007 | | ||
---|---|---|---|
| (In millions) | ||
Less than 1 year | $ | 10.9 | |
1-5 years | 97.4 | ||
5-10 years | 74.5 | ||
More than 10 years | 97.9 | ||
Total maturities of debt securities | $ | 280.7 | |
Investments in Variable Interest Entities
As of December 31, 2010, we consolidated three VIEs in which we were the primary beneficiary, and we had significant interests in six VIEs for which we did not have controlling financial interests and, accordingly, were not the primary beneficiary.
RSB BondCo LLCConsolidated Variable Interest Entities
In 2007, BGE formed RSB BondCo LLC (BondCo), a special purpose bankruptcy-remotebankruptcy- remote limited liability company.company, to acquire and hold rate stabilization property and to issue and service bonds secured by the rate stabilization property. In June 2007, BondCo purchased rate stabilization property from BGE, including the right to assess, collect, and receive non-bypassable rate stabilization charges payable by all residential electric customers of BGE. These charges are being assessed in order to recover previously incurred power purchase costs that BGE deferred pursuant to Senate Bill 1.
BGE has determined that BondCo is a variable interest entityVIE for which it is also the primary beneficiary. As a result, BGE, and we, consolidated BondCo.
The BondCo assets are restricted and can only be used to settle the obligations of BondCo. Further, BGE is required to remit all payments it receives from customers for rate stabilization charges to BondCo. During 2010, 2009, and 2008, BGE remitted $90.3 million, $85.8 million, and $87.2 million, respectively, to BondCo.
BGE did not provide any additional financial support to BondCo during 2010 or 2009. Further, BGE does not have any contractual commitments or obligations to provide additional financial support to BondCo unless additional rate stabilization bonds are issued. The BondCo creditors do not have any recourse to the general credit of BGE in the event the rate stabilization charges are not sufficient to cover the bond principal and interest payments of BondCo.
During 2009, our NewEnergy business formed two new entities and combined them with its existing retail gas activities into a retail gas entity group for the purpose of entering into a collateralized gas supply agreement with a third party gas supplier. While we own 100% of these entities, we determined that the retail gas entity group is a VIE because there is not sufficient equity to fund the group's activities without the additional credit support we provide in the form of a letter of credit and a parental guarantee. We discussare the primary beneficiary of the retail gas entity group; accordingly, we consolidate the retail gas entity group as a VIE, including the existing retail gas customer supply operation, which we formerly consolidated as a voting interest entity.
The gas supply arrangement is collateralized as follows:
Other than credit support provided by the parental guarantee and the letter of credit, we do not have any contractual or other obligations to provide additional financial support to the retail gas entity group. The retail gas entity group creditors do not have any recourse to our general credit. Finally, we did not provide any financial support to the retail gas entity group during 2010, other than the equity contributions, parental guarantee and the letter of credit.
We also consolidate a retail power supply VIE for which we became the primary beneficiary in 2008 as a result of a modification to its contractual arrangements that changed the allocation of the economic risks and rewards of the VIE among the variable interest holders. The consolidation method of accountingthis VIE did not have a material impact on our financial results or financial condition.
The carrying amounts and classification of the above consolidated VIEs' assets and liabilities included in more detailour consolidated financial statements at December 31, 2010 and 2009 are as follows:
| 2010 | 2009 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Current assets | $ | 516.6 | $ | 608.9 | |||
Noncurrent assets | 57.7 | 67.7 | |||||
Total Assets | $ | 574.3 | $ | 676.6 | |||
Current liabilities | $ | 345.5 | $ | 509.9 | |||
Noncurrent liabilities | 399.0 | 420.3 | |||||
Total Liabilities | $ | 744.5 | $ | 930.2 | |||
All of the assets in the table above are restricted for settlement of the VIE obligations and all of the liabilities in the preceding table can only be settled using VIE resources.
During 2010, as part of the 2009 order from the Maryland PSC approving our transaction with EDF, we created RF HoldCo LLC, a bankruptcy-remote special purpose subsidiary to hold all of the common equity interests in BGE. This subsidiary is not a VIE. However, due to our ownership of 100% of the voting interests of RF HoldCo LLC, we consolidate this subsidiary as a voting interest entity.
BGE and RF HoldCo are separate legal entities and are not liable for the debts of Constellation Energy. Accordingly, creditors of Constellation Energy may not satisfy their debts from the assets of BGE and RF HoldCo except as required by applicable law or regulation. Similarly, Constellation Energy is not liable for the debts of BGE or RF HoldCo. Accordingly, creditors of BGE and RF HoldCo may not satisfy their debts from the assets of Constellation Energy except as required by applicable law or regulation.
114
Note 1.Table of Contents
Unconsolidated Variable Interest Entities
WeAs of December 31, 2010 and 2009, we had significant interests in six VIEs for which we were not the primary beneficiary. Other than the obligations listed in the table below, we have a significant interestnot provided any material financial or other support to these entities during 2010 or 2009.
The nature of these entities and our involvement with them are described in the following variable interest entities (VIE) for which we are not the primary beneficiary:table:
VIE Category | Nature of Financing | Nature of Constellation Energy Involvement | Obligations or Requirement to Provide Financial Support | Initial Date of Involvement | ||||
---|---|---|---|---|---|---|---|---|
Power contract monetization entities (2 entities) | Combination of debt and equity financing | Power sale agreements, loans, and guarantees | $24.9 million and $34.7 million in letters of credit at December 31, 2010 and 2009, respectively | March 2005 | ||||
Power projects and fuel supply entities (4 entities) | Combination of debt and equity financing | Equity | ||||||
$5.0 million and $2.0 million debt guarantee and working capital funding at December 31, 2010 and 2009, respectively | Prior to 2003 |
For purposes of aggregating the various VIEs for disclosure, we evaluated the risk and reward characteristics for, and the significance of, each VIE. We discuss in greater detail the nature of our involvement with the power contract monetization VIEs in theCustomerPower Contract RestructuringMonetization VIEs section below.
We concluded that power over the most economically significant activities of two of the power project VIEs is shared equally among the equity holders. Accordingly, neither of the equity holders consolidates these VIEs. The equity holders own 50% interests in these VIEs and all of the significant decisions require the mutual consent of the equity holders.
The following is summary information available as of December 31, 20072010 about the VIEs in which we have a significant interest, but are not the primary beneficiary:these entities:
| Power Contract Monetization VIEs | All Other VIEs | Total | ||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Total assets | $ | 736.6 | $ | 358.1 | $ | 1,094.7 | |||
Total liabilities | 583.2 | 195.6 | 778.8 | ||||||
Our ownership interest | — | 46.1 | 46.1 | ||||||
Other ownership interests | 153.4 | 116.4 | 269.8 | ||||||
Our maximum exposure to loss | 56.5 | 158.0 | 214.5 |
| Power Contract Monetization VIEs | All Other VIEs | Total | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||
Total assets | $ | 492.9 | $ | 288.3 | $ | 781.2 | ||||||
Total liabilities | 382.6 | 113.2 | 495.8 | |||||||||
Our ownership interest | — | 48.7 | 48.7 | |||||||||
Other ownership interests | 110.3 | 126.4 | 236.7 | |||||||||
Our maximum exposure to loss | 24.9 | 46.4 | 71.3 | |||||||||
Carrying amount and location of variable interest on balance sheet: | ||||||||||||
—Other investments | — | 41.4 | 41.4 |
The following is summary information available as of December 31, 2009 about these entities:
| Power Contract Monetization VIEs | All Other VIEs | Total | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||
Total assets | $ | 568.3 | $ | 338.6 | $ | 906.9 | ||||||
Total liabilities | 460.4 | 77.9 | 538.3 | |||||||||
Our ownership interest | — | 62.6 | 62.6 | |||||||||
Other ownership interests | 107.9 | 198.1 | 306.0 | |||||||||
Our maximum exposure to loss | 34.7 | 64.6 | 99.3 | |||||||||
Carrying amount and location of variable interest on balance sheet: | ||||||||||||
���Other investments | — | 62.6 | 62.6 |
Our maximum exposure to loss representsis 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 December 31, 20072010 and 2009 consists of the following:
We assess the risk of a loss equal to our maximum exposure to be remote.remote and, accordingly have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would affect the fair value or risk of our variable interests in these variable interest entities.
CustomerPower Contract RestructuringMonetization VIEs
In March 2005, our merchant energyNewEnergy business closed a transaction in which we assumed from a counterparty two power sales contracts with previously 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 betweenUnder the contract prices at which the VIEs purchase and sell power is used to service the debt of the VIEs, which totaled $558 million at December 31, 2007.
The market price for power at the closing of our transaction was higher than the contract price under the existing power sales contracts, we assumed. Therefore, we received compensation totaling $308.5 million, equalsell power to the net present valueVIEs which, in turn, sell that power to an electric distribution utility through 2013. In connection with this transaction, a third party acquired the equity 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,VIEs 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:
| (In millions) | |||
---|---|---|---|---|
Gross compensation from original power sales contracts counterparty equal to fair value of power sales contracts at closing | $ | 308.5 | ||
Settlement of existing derivative liabilities | (68.5 | ) | ||
Third-party loan secured by equity in VIE | (82.8 | ) | ||
Net cash received at closing | $ | 157.2 | ||
We recorded the closing of this transaction in our financial statements 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 forthat party 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. We record the ongoing cash flows related to the sale of power to the VIEs as a financing cash inflow in accordance with SFAS No. 149,Amendment of FASB Statement No. 133 on Derivative and Hedging Activities.
purchase price. 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.
115
5Intangible Assets
Goodwill
Goodwill is the excess of the cost of an acquisition over the fair value of the net assets acquired. OurAs of December 31, 2010 and 2009, our goodwill balance iswas primarily related to our merchantretail energy reporting unit within our NewEnergy business acquisitions. The changes in the carrying amount of goodwill for the years ended December 31, 2007 and 2006 are as follows:
2007 | Balance at January 1, | Goodwill Acquired | Other(a) | Balance at December 31, | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||
Goodwill | $ | 157.6 | $ | 103.4 | $ | 0.3 | $ | 261.3 | ||||
2006 | Balance at January 1, | Goodwill Acquired | Other(a) | Balance at December 31, | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||
Goodwill | $ | 147.1 | $ | 11.1 | $ | (0.6 | ) | $ | 157.6 | |||
(a) Other represents purchase price adjustments.
segment. Goodwill is not amortized; rather, it is evaluated for impairment at least annually.
The changes in the gross amount of goodwill and the accumulated impairment losses for the years ended December 31, 2010 and 2009 are as follows:
At December 31, | 2010 | 2009 | ||||||
---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||
Balance as of January 1, | ||||||||
Gross goodwill | $ | 292.0 | $ | 271.1 | ||||
Accumulated impairment losses | (266.5 | ) | (266.5 | ) | ||||
Net goodwill | 25.5 | 4.6 | ||||||
Goodwill acquired (1) | 51.5 | 18.6 | ||||||
Impairment losses | — | — | ||||||
Other purchase price adjustments | — | 2.3 | ||||||
Balance as of December 31, | ||||||||
Gross goodwill | 343.5 | 292.0 | ||||||
Accumulated impairment losses | (266.5 | ) | (266.5 | ) | ||||
Net goodwill | $ | 77.0 | $ | 25.5 | ||||
For tax purposes, $227.6$169.4 million of our gross goodwill balance at December 31, 2010 is deductible.
Intangible Assets Subject to Amortization
Intangible assets with finite lives are subject to amortization over their estimated useful lives. The primary assets included in this category are as follows:
At December 31, | 2007 | 2006 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Gross Carrying Amount | Accumul- ated Amortiz- ation | Net Asset | Gross Carrying Amount | Accumul- ated Amortiz- ation | Net Asset | ||||||||||||
| (In millions) | |||||||||||||||||
Software | $ | 494.0 | $ | (232.3 | ) | $ | 261.7 | $ | 392.3 | $ | (182.6 | ) | $ | 209.7 | ||||
Permits and licenses | 62.3 | (8.0 | ) | 54.3 | 60.4 | (5.9 | ) | 54.5 | ||||||||||
Operating manuals and procedures | 38.6 | (8.4 | ) | 30.2 | 38.5 | (7.1 | ) | 31.4 | ||||||||||
Other | 26.8 | (19.9 | ) | 6.9 | 26.3 | (17.2 | ) | 9.1 | ||||||||||
Total | $ | 621.7 | $ | (268.6 | ) | $ | 353.1 | $ | 517.5 | $ | (212.8 | ) | $ | 304.7 | ||||
| 2010 | | | | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
At December 31, | | | 2009 | ||||||||||||||||
| Gross Carrying Amount | Accumul- ated Amortiz- ation | Net Asset | Gross Carrying Amount | Accumul- ated Amortiz- ation | Net Asset | |||||||||||||
| (In millions) | ||||||||||||||||||
Software | $ | 596.8 | $ | (397.1 | ) | $ | 199.7 | $ | 580.5 | $ | (347.3 | ) | $ | 233.2 | |||||
Permits and licenses | 2.7 | (1.0 | ) | 1.7 | 2.2 | (0.8 | ) | 1.4 | |||||||||||
Other | 22.3 | (8.2 | ) | 14.1 | 29.0 | (13.9 | ) | 15.1 | |||||||||||
Total | $ | 621.8 | $ | (406.3 | ) | $ | 215.5 | $ | 611.7 | $ | (362.0 | ) | $ | 249.7 | |||||
BGE had intangible assets with a gross carrying amount of $194.1$250.2 million and accumulated amortization of $124.4$171.4 million at December 31, 20072010 and $191.3$242.5 million and accumulated amortization of $109.2$148.8 million at December 31, 20062009 that are included in the table above. Substantially all of BGE's intangible assets relate to software.
We recognized amortization expense related to our intangible assets as follows:
Year Ended December 31, | 2007 | 2006 | 2005 | ||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Nonregulated businesses | $ | 51.9 | $ | 37.2 | $ | 30.6 | |||
BGE | 20.2 | 18.6 | 26.3 | ||||||
Total Constellation Energy | $ | 72.1 | $ | 55.8 | $ | 56.9 | |||
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Nonregulated businesses | $ | 64.8 | $ | 74.2 | $ | 66.8 | ||||
BGE | 25.8 | 23.6 | 20.1 | |||||||
Total Constellation Energy | $ | 90.6 | $ | 97.8 | $ | 86.9 | ||||
The following is our, and BGE's, estimated amortization expense related to our intangible assets for 20082011 through 20122015 for the intangible assets included in our, and BGE's, Consolidated Balance Sheets at December 31, 2007:2010:
Year Ended December 31, | 2008 | 2009 | 2010 | 2011 | 2012 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||||||
Estimated amortization expense—Nonregulated businesses | $ | 61.4 | $ | 60.2 | $ | 53.9 | $ | 48.3 | $ | 37.2 | |||||
Estimated amortization expense—BGE | 18.3 | 15.0 | 13.1 | 10.9 | 6.1 | ||||||||||
Total estimated amortization expense—Constellation Energy | $ | 79.7 | $ | 75.2 | $ | 67.0 | $ | 59.2 | $ | 43.3 | |||||
Year Ended December 31, | 2011 | 2012 | 2013 | 2014 | 2015 | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||||||
Estimated amortization expense—Nonregulated businesses | $ | 58.5 | $ | 37.4 | $ | 19.5 | $ | 8.8 | $ | 3.9 | ||||||
Estimated amortization expense—BGE | 23.7 | 17.2 | 13.2 | 8.6 | 6.7 | |||||||||||
Total estimated amortization expense—Constellation Energy | $ | 82.2 | $ | 54.6 | $ | 32.7 | $ | 17.4 | $ | 10.6 | ||||||
Unamortized Energy Contracts
As discussed inNote 1, unamortized energy contract assets and liabilities represent the remaining unamortized balance of nonderivative energy contracts acquired, certain contracts which no longer qualify as derivatives due to the absence of a liquid market, or derivatives designated as normal purchases and normal sales, which we previously recorded as derivative assets and liabilities. Unamortized energy contract assets also include the power purchase agreement entered into with CENG with an initial fair value of approximately $0.8 billion. See
During 2007, we acquired several pre-existing power-related contracts that had been originated by other parties in prior periods when market prices were lower than current levels. The net proceeds received inNote 16 for more details on this transaction were primarily recorded as a net liability in "Unamortized energy contracts."power purchase agreement.
We present separately in our Consolidated Balance Sheets the net unamortized energy contract assets and liabilities for these contracts. The table below presents the gross and net carrying amount and accumulated amortization of the net liability that we have recorded in our Consolidated Balance Sheets:
At December 31 | 2007 | 2006 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Carrying Amount | Accumul- ated Amortiz- ation | Net Liability | Carrying Amount | Accumul- ated Amortiz- ation | Net Liability | |||||||||||||
| (In millions) | ||||||||||||||||||
Unamortized energy contracts, net | $ | (2,290.0 | ) | $ | 889.5 | $ | (1,400.5 | ) | $ | (1,642.0 | ) | $ | 464.5 | $ | (1,177.5 | ) | |||
| 2010 | | | | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
At December 31 | | | 2009 | ||||||||||||||||
| Carrying Amount | Accumul- ated Amortiz- ation | Net Asset | Carrying Amount | Accumul- ated Amortiz- ation | Net Liability | |||||||||||||
| (In millions) | ||||||||||||||||||
Unamortized energy contracts, net | $ | (1,360.9 | ) | $ | 1,473.8 | $ | 112.9 | $ | (1,587.1 | ) | $ | 1,584.5 | $ | (2.6 | ) | ||||
We recognized amortization expense of $106.8 million, $353.1 million, and $390.4 million related to these energy contract assets for the years ended December 31, 2010, 2009, and 2008 for our nonregulated businesses.
The table below presents the estimated net favorable impact on our operating results for the amortization for these assets and liabilities over the next five-years:
Year Ended December 31, | 2008 | 2009 | 2010 | 2011 | 2012 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||||||
Estimated amortization | $ | 358.9 | $ | 308.8 | $ | 289.4 | $ | 84.4 | $ | 79.3 | |||||
Year Ended December 31, | 2011 | 2012 | 2013 | 2014 | 2015 | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||||||
Estimated amortization | $ | 414.1 | $ | (49.2 | ) | $ | (71.8 | ) | $ | (71.3 | ) | $ | (68.8 | ) | ||
116
6Regulatory Assets (net)
As discussed inNote 1, the Maryland PSC and the FERC provide the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under accounting principles generally accepted in the United States of America. However, sometimes the Maryland PSC or FERC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers. When this happens, we must defer certain regulated expenses and income in our Consolidated Balance Sheets as regulatory assets and liabilities. We then record them in our Consolidated Statements of Income (Loss) (using amortization) when we include them in the rates we charge our customers.
We summarize regulatory assets and liabilities in the following table, and we discuss each of them separately below.
At December 31, | 2007 | 2006 | |||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Deferred fuel costs | |||||||||
Rate stabilization deferral | $ | 593.4 | $ | 326.9 | |||||
Other | 19.4 | 37.8 | |||||||
Electric generation-related regulatory asset | 135.9 | 154.8 | |||||||
Net cost of removal | (182.3 | ) | (161.3 | ) | |||||
Income taxes recoverable through future rates (net) | 63.9 | 67.1 | |||||||
Deferred postretirement and postemployment benefit costs | 16.1 | 19.3 | |||||||
Deferred environmental costs | 8.9 | 10.0 | |||||||
Workforce reduction costs | 2.4 | 4.9 | |||||||
Other (net) | (6.6 | ) | (8.0 | ) | |||||
Total regulatory assets (net) | 651.1 | 451.5 | |||||||
Less: Current portion of regulatory assets | |||||||||
(net) | 74.9 | 62.5 | |||||||
Long-term portion of regulatory assets | |||||||||
(net) | $ | 576.2 | $ | 389.0 | |||||
At December 31, | 2010 | 2009 | ||||||
---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||
Deferred fuel costs | ||||||||
Rate stabilization deferral | $ | 415.6 | $ | 477.5 | ||||
Other | 8.8 | 14.3 | ||||||
Electric generation-related regulatory asset | 86.9 | 102.5 | ||||||
Net cost of removal | (210.5 | ) | (210.1 | ) | ||||
Income taxes recoverable through future rates (net) | 68.3 | 67.6 | ||||||
Deferred Smart Energy Savers ProgramSM costs | 64.3 | 10.8 | ||||||
Deferred Advanced Meter Infrastructure costs | 12.2 | 11.3 | ||||||
Deferred postretirement and postemployment benefit costs | 8.4 | 9.6 | ||||||
Deferred environmental costs | 5.6 | 6.5 | ||||||
Workforce reduction costs | 1.3 | 1.5 | ||||||
Other (net) | (8.1 | ) | (4.6 | ) | ||||
Total regulatory assets (net) | 452.8 | 486.9 | ||||||
Less: Current portion of regulatory assets (net) | 78.7 | 72.5 | ||||||
Long-term portion of regulatory assets (net) | $ | 374.1 | $ | 414.4 | ||||
Deferred Fuel Costs
Rate Stabilization Deferral
In June 2006, Senate Bill 1 was enacted in Maryland and imposed a rate stabilization measure that capped rate increases by BGE for residential electric customers at 15% from July 1, 2006 to May 31, 2007. As a result, BGE recorded a regulatory asset on its Consolidated Balance Sheets equal to the difference between the costs to purchase power and the revenues collected from customers, as well as related carrying charges based on short-term interest rates from July 1, 2006 to May 31, 2007. In addition, as required by Senate Bill 1, the Maryland PSC approved a plan that allowed residential electric customers the option to further defer the transition to market rates from June 1, 2007 to January 1, 2008. Customers participating in the deferral from June 1, 2007 to December 31, 2007 will repay the deferred charges without interest. During 2007, and 2006, BGE deferred $306.4 million and $326.9 million, respectively, of electricity purchased for resale expenses and certain applicable carrying charges if applicable, as a regulatory asset related to the rate stabilization plans. During 2007,2010 and 2009, BGE recovered $39.2$61.8 million and $51.4 million, respectively, of electricity purchased for resale expenses and carrying charges related to the rate stabilization plan regulatory asset. BGE began amortizing the regulatory asset associated with the deferral which ended in May 2007 to earnings over a period not to exceed ten years when collection from customers began in June 2007. Customers who participated in the deferral from June 1, 2007 to December 31, 2007 repaid the deferred charges without interest over a 21-month period which began in April 2008 and ended in December 2009.
Other
As described inNote 1, deferred fuel costs are the difference between our actual costs of purchased energy and our fuel rate revenues collected from customers. We reduce deferred fuel costs as we collect them from our customers and increase deferred fuel costs when we refund them to our customers.
We exclude other deferred fuel costs from rate base because their existence is relatively short-lived. These costs are recovered in the following year through our fuel rates.
Electric Generation-Related Regulatory Asset
As a result of the deregulation of electric generation, BGE ceased to meet the requirements for the application of SFAS No. 71accounting for a regulated business for the previous electric generation portion of its business. In accordance with SFAS No. 101,Regulated Enterprises—Accounting for the Discontinuation of Application of FASB Statement No. 71, and EITF 97-4,Deregulation of the Pricing of Electricity—Issues Related to the Application of FASB Statements No. 71 and 101,As a result, BGE wrote-off all of its entire individual, generation-related regulatory assets and liabilities. BGE established a single, generation-related regulatory asset to be collected through its regulated transmission and distribution business,rates, which is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules.
A portion of this regulatory asset represents income taxes recoverable through future rates that do not earn a regulated rate of return. These amounts were $81.1$53.3 million as of December 31, 20072010 and $89.4$62.8 million as of December 31, 2006.2009. We will continue to amortize this amount through 2017.
Another portion of this regulatory asset represents the decommissioning and decontamination fund payment for federal uranium enrichment facilities that do not earn a regulated rate of return on the rate base investment. These amounts were $2.3 million at December 31, 2007 and $5.5 million at December 31, 2006. Prior to the deregulation of electric generation, these costs were recovered through the electric fuel rate mechanism, and were excluded from rate base. We will continue to amortize this amount through 2008.
Net Cost of Removal
As discussed inNote 1, we use the group depreciation method for the regulated business. This method is currently an acceptable method of accounting under accounting principles generally accepted in the United States of America and ishas been widely used in the energy, transportation, and telecommunication industries.
Historically, under the group depreciation method, the anticipated costs of removing assets upon retirement were provided for over the life of those assets as a component of depreciation expense. However, effective January 1, 2003, we adopted SFAS No. 143,Accounting for Asset Retirement Obligations. In addition to providing the accounting requirements for recognizing an estimated liability for legal obligations associated with the retirement of tangible long-lived assets, SFAS No. 143 precludes the recognition of expected net future costs of removal is shown as a component of depreciation expense or accumulated depreciation.
BGE is required by the Maryland PSC to use the group depreciation method, including cost of removal, under regulatory accounting. For ratemaking purposes, net cost of removal is a
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component of depreciation expense and the related accumulated depreciation balance is included as a net reduction to BGE's rate base investment. For financial reporting purposes, BGE continues to accrue for the future cost of removal for its regulated gas and electric assets by increasing itsa regulatory liability. This liability is relieved when actual removal costs are incurred.
Income Taxes Recoverable Through Future Rates (net)
As described inNote 1, income taxes recoverable through future rates are the portion of our net deferred income tax liability that is applicable to our regulated business, but has not been reflected in the rates we charge our customers. These income taxes represent the tax effect of temporary differences in depreciation and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on deferred investment tax credits. We amortize these amounts as the temporary differences reverse.
Deferred Smart Energy Savers ProgramSM Costs
Deferred Smart Energy Savers ProgramSM costs are the costs incurred to implement demand response and conservation programs. These programs are designed to help BGE manage peak demand, improve system reliability, reduce customer consumption, and improve service to customers by giving customers greater control over their energy use. Actual costs incurred in the demand response program, which began in January 2008, are being recovered over a 5-year amortization period from the date incurred pursuant to an order by the Maryland PSC. Actual costs incurred in the conservation program, which began in February 2009, are being amortized as incurred pursuant to an order by the Maryland PSC.
Deferred Advanced Meter Infrastructure Costs
Between 2007 and 2009, the Maryland PSC approved and BGE conducted a series of successful smart grid pilot programs for a total cost of $11.3 million, which, pursuant to a Maryland PSC order, was deferred in a regulatory asset, without earning a regulatory rate of return. In August 2010, the Maryland PSC approved a comprehensive smart grid initiative for BGE which included the planned installation of 2 million residential and commercial electric and gas smart meters. As part of the Maryland PSC's August 2010 order, BGE has been authorized to establish a separate regulatory asset for incremental costs incurred to implement the initiative, net depreciation and amortization associated with the meters, plus an appropriate return on these costs. Additionally, the Maryland PSC order requires that BGE prove the cost effectiveness of the entire smart grid initiative prior to seeking recovery of the costs deferred in these regulatory assets. Therefore, the commencement and timing of the amortization of these deferred costs is currently unknown.
Deferred Postretirement and Postemployment Benefit Costs
DeferredWe record a regulatory asset for the deferred postretirement and postemployment benefit costs are the costs we recorded under SFAS No. 106,Employers' Accounting for Postretirement Benefits Other Than Pensions, and SFAS No. 112,Employers' Accounting for Postemployment Benefits, in excess of the costs we included in the rates we chargecharged our customers.customers through 1997. We began amortizing these costs over a 15-year period in 1998.
Deferred Environmental Costs
Deferred environmental costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss this further inNote 12. We amortized $21.6 million of these costs (the amount we had incurred through October 1995) and are amortizing $6.4 million of these costs (the amount we incurred from November 1995 through June 2000) over 10-year periods in accordance with the Maryland PSC's orders. We applied for and received rate relief for an additional $5.4 million of clean-up costs incurred during the period from July 2000 through November 2005. These costs are being amortized over a 10-year period that began in January 2006.
Workforce Reduction Costs
The portionsportion of the costs associated with our Voluntary Special Early Retirement Program and2008 workforce reduction programsprogram that relate to BGE's gas business arewere deferred in 2009 as a regulatory assetsasset in accordance with the Maryland PSC's orders in prior rate cases. As a result of a 2005 gas base rate case, the remaining regulatory assets associated with workforce reductions totaling $7.3 million as of December 31, 2005cases and are being amortized over a 3-year5-year period that began in January 2006. These remaining regulatory assets were previously amortized over 5-year periods beginning in January and February 2002.2009.
Other (Net)
Other regulatory assets are comprised of a variety of current assets and liabilities that do not earn a regulatory rate of return due to their short-term nature.
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7Pension, Postretirement, Other Postemployment, and Employee Savings Plan Benefits
We offer pension, postretirement, other postemployment, and employee savings plan benefits. BGE employees participate in the benefit plans that we offer. We describe each of our plans separately below. Nine Mile Point, owned by CENG, offers its own pension, postretirement, other postemployment, and employee savings plan benefits to its employees. The benefits forIn connection with the deconsolidation of CENG as a result of the investment in CENG by EDF on November 6, 2009, the Nine Mile Point areplan is no longer included in our consolidated results. In addition, benefit plan assets and obligations relating to CENG employees that previously participated in our plans were transferred into new CENG plans that are no longer included in our consolidated results. Therefore, the tables beginning below.below include the benefits for the CENG plans, including Nine Mile Point, through November 6, 2009.
We use a December 31 measurement date for our pension, postretirement, other postemployment, and employee savings plans. The following table summarizes our defined benefit liabilities and their classification in our Consolidated Balance Sheets:
At December 31, | 2007 | 2006 | ||||
---|---|---|---|---|---|---|
| (In millions) | |||||
Pension benefits | $ | 385.7 | $ | 468.6 | ||
Postretirement benefits | 421.5 | 441.5 | ||||
Postemployment benefits | 66.3 | 57.0 | ||||
Total defined benefit obligations | 873.5 | 967.1 | ||||
Less: Amount recorded in other current liabilities | 44.9 | 38.8 | ||||
Total noncurrent defined benefit obligations | $ | 828.6 | $ | 928.3 | ||
At December 31, | 2010 | 2009 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Pension benefits | $ | 218.0 | $ | 411.7 | |||
Postretirement benefits | 334.9 | 322.3 | |||||
Postemployment benefits | 55.0 | 50.6 | |||||
Total defined benefit obligations | 607.9 | 784.6 | |||||
Less: Amount recorded in other current liabilities | 33.2 | 40.7 | |||||
Total noncurrent defined benefit obligations | $ | 574.7 | $ | 743.9 | |||
Pension Benefits
We sponsor several defined benefit pension plans for our employees. These include basic qualified plans that most employees participate in and several non-qualified plans that are available only to certain employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. Employees do not contribute to these plans. Generally, we calculate the benefits under these plans based on age, years of service, and pay.
Sometimes we amend the plans retroactively. These retroactive plan amendments require us to recalculate benefits related to participants' past service. We amortize the change in the benefit costs from these plan amendments on a straight-line basis over the average remaining service period of active employees.
We fund the qualified plans by contributing at least the minimum amount required under IRS regulations. We calculate the amount of funding using an actuarial method called the projected unit credit cost method. The assets in all of the plans at December 31, 2007 and 2006 were mostly marketable equity and fixed income securities.
Postretirement Benefits
We sponsor defined benefit postretirement health care and life insurance plans that cover the majority of our employees. Generally, we calculate the benefits under these plans based on age, years of service, and pension benefit levels or final base pay. We do not fund these plans. For nearly all of the health care plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs.
Effective in 2002, we amended our postretirement medical plans for all subsidiaries other than Nine Mile Point. Our contributions for retiree medical coverage for future retirees who were under the age of 55 on January 1, 2002 are capped at the 2002 level. We also amended our plans to increase the Medicare eligible retirees' share of medical costs.
In 2003, the President signed into law the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Act). This legislation provides a prescription drug benefit for Medicare beneficiaries, a benefit that we provide to our Medicare eligible retirees. Our actuaries concluded that prescription drug benefits available under our postretirement medical plan are "actuarially equivalent" to Medicare Part D and thus qualify for the subsidy under the Act. This subsidy reduced our 20072010 Accumulated Postretirement Benefit Obligation by $40.8$30.9 million and our 20072010 postretirement medical payments by $2.7$2.2 million.
Liability Adjustments
Our pension accumulated benefit obligation has exceeded the fair value of our plan assets since 2001. At December 31, 20072010 and 2006,2009, our pension obligations were greater thanand the fair value of our plan assets for our qualified and our nonqualified pension plans were as follows:
| Qualified Plans | | | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
At December 31, 2007 | Nine Mile | Other | Non-Qualified Plans | Total | ||||||||
| (In millions) | |||||||||||
Accumulated benefit obligation | $ | 98.0 | $ | 1,332.2 | $ | 69.7 | $ | 1,499.9 | ||||
Fair value of assets | 78.6 | 1,179.9 | — | 1,258.5 | ||||||||
Unfunded obligation | $ | 19.4 | $ | 152.3 | $ | 69.7 | $ | 241.4 | ||||
| Qualified Plans | | | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| Non-Qualified Plans | | ||||||||||
At December 31, 2006 | Nine Mile | Other | Total | |||||||||
| (In millions) | |||||||||||
Accumulated benefit obligation | $ | 107.5 | $ | 1,306.0 | $ | 63.8 | $ | 1,477.3 | ||||
Fair value of assets | 54.6 | 1,106.6 | — | 1,161.2 | ||||||||
Unfunded obligation | $ | 52.9 | $ | 199.4 | $ | 63.8 | $ | 316.1 | ||||
We were required to remeasure the additional minimum pension liability prior to calculating the impact of adopting SFAS No. 158,Employer's Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statement No. 87, 106 and 132(R), on December 31, 2006. We recorded additional minimum pension liability adjustments through December 31, 2006 as follows:
| Increase (Decrease) | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| |||||||||||||
| | | Accumulated Other Comprehensive Loss | ||||||||||
| Pension Liability Adjustment | | |||||||||||
| Intangible Asset * | ||||||||||||
| Pre-tax | After-tax | |||||||||||
| (In millions) | ||||||||||||
Cumulative through 2004 | $ | 359.6 | $ | 40.6 | $ | (319.0 | ) | $ | (192.8 | ) | |||
2005 | 121.4 | (6.1 | ) | (127.5 | ) | (77.1 | ) | ||||||
2006 | (131.1 | ) | (5.9 | ) | 125.2 | 75.6 | |||||||
Total | $ | 349.9 | $ | 28.6 | $ | (321.3 | ) | $ | (194.3 | ) | |||
* Included in "Other assets" in our Consolidated Balance Sheets.
At December 31, 2010 | Qualified Plan | Non-Qualified Plans | Total | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Accumulated benefit obligation | $ | 1,405.2 | $ | 87.8 | $ | 1,493.0 | ||||
Fair value of assets | 1,408.1 | — | 1,408.1 | |||||||
Net (asset) unfunded obligation | $ | (2.9 | ) | $ | 87.8 | $ | 84.9 | |||
Under SFAS No. 158, we
At December 31, 2009 | Qualified Plan | Non-Qualified Plans | Total | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Accumulated benefit obligation | $ | 1,277.5 | $ | 84.1 | $ | 1,361.6 | ||||
Fair value of assets | 1,058.1 | — | 1,058.1 | |||||||
Net unfunded obligation | $ | 219.4 | $ | 84.1 | $ | 303.5 | ||||
We are required to reflect the funded status of our pension plans in terms of the projected benefit obligation, which is higher than the accumulated benefit obligation because it includes the impact of expected future compensation increases on the pension obligation. In addition, SFAS No. 158 requires us toWe reflect the funded status of our
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postretirement benefits in terms of the accumulated postretirement benefit obligation.
Upon adoption of SFAS No. 158, we reversed the intangible asset associated with the minimum pension liability adjustment above, increased our pension and postretirement liabilities, and reduced equity. The following table summarizes the impactimpacts of SFAS No. 158funded status adjustments recorded at December 31, 2007during 2010 and 2006:2009:
| Increase (Decrease) | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | | | Accumulated Other Comprehensive (Income) Loss | ||||||||||||
| | Postretirement Benefit Liability | | |||||||||||||
| Pension Liability | Intangible Asset | ||||||||||||||
| Pre-tax | After-tax | ||||||||||||||
| (In millions) | |||||||||||||||
December 31, 2007 (1) | $ | 3.1 | $ | (22.5 | ) | $ | — | $ | 19.4 | $ | 11.6 | |||||
December 31, 2006 | $ | 152.5 | $ | 99.7 | $ | (28.6 | ) | $ | (280.8 | ) | $ | (169.5 | ) | |||
| | | Accumulated Other Comprehensive Income (Loss) | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Postretirement Benefit Liability | |||||||||||
| Pension Liability | ||||||||||||
| Pre-tax | After-tax | |||||||||||
| (In millions) | ||||||||||||
December 31, 2010 | $ | 73.7 | $ | 10.9 | $ | (84.6 | ) | $ | (54.6 | ) | |||
December 31, 2009 | $ | (49.3 | ) | $ | 1.0 | $ | 48.3 | $ | 25.4 | ||||
November 6, 2009 (1) | $ | (211.7 | ) | $ | (20.9 | ) | $ | 232.6 | $ | 138.0 | |||
Obligations and Assets
As a result of workforce reduction initiatives in the generation business, pension and postretirement special termination benefits were recorded in 2007 and 2006. We discuss the workforce reduction initiatives further inNote 2.
We show the change in the benefit obligations and plan assets of the pension and postretirement benefit plans in the following tables. Postretirement benefit plan amounts are presented net of expected reimbursements under Medicare Part D.
| Pension Benefits | Postretirement Benefits | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2007 | 2006 | 2007 | 2006 | |||||||||
| (In millions) | ||||||||||||
Change in benefit obligation (1) | |||||||||||||
Benefit obligation at January 1 | $ | 1,629.8 | $ | 1,678.6 | $ | 441.5 | $ | 460.4 | |||||
Service cost | 49.4 | 49.0 | 6.5 | 7.7 | |||||||||
Interest cost | 94.7 | 89.3 | 24.4 | 23.7 | |||||||||
Plan participants' contributions | — | — | 8.7 | 8.3 | |||||||||
Actuarial (gain) loss | (27.6 | ) | (49.1 | ) | (22.3 | ) | (27.1 | ) | |||||
Special termination benefits | 1.2 | 4.2 | 0.3 | 3.5 | |||||||||
Benefits paid (2) (3) | (103.3 | ) | (142.2 | ) | (37.6 | ) | (35.0 | ) | |||||
Benefit obligation at December 31 | $ | 1,644.2 | $ | 1,629.8 | $ | 421.5 | $ | 441.5 | |||||
| Pension Benefits | Postretirement Benefits | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | 2010 | 2009 | |||||||||
| (In millions) | ||||||||||||
Change in benefit obligation (1) | |||||||||||||
Benefit obligation at January 1 | $ | 1,469.8 | $ | 1,804.3 | $ | 322.3 | $ | 415.4 | |||||
Service cost | 37.9 | 50.8 | 2.4 | 6.3 | |||||||||
Interest cost | 84.7 | 101.1 | 17.7 | 22.6 | |||||||||
Plan amendments | — | 2.4 | (3.3 | ) | — | ||||||||
Plan participants' contributions | — | — | 10.5 | 10.2 | |||||||||
Actuarial loss (gain) | 124.0 | 55.8 | 14.2 | 1.0 | |||||||||
Separation of CENG plans | (3.0 | ) | (410.5 | ) | — | (98.6 | ) | ||||||
Settlements | (5.2 | ) | (19.0 | ) | — | — | |||||||
Special termination benefits | 0.6 | 0.1 | 0.1 | — | |||||||||
Benefits paid (2)(3) | (82.7 | ) | (115.2 | ) | (29.0 | ) | (34.6 | ) | |||||
Benefit obligation at December 31 | $ | 1,626.1 | $ | 1,469.8 | $ | 334.9 | $ | 322.3 | |||||
| Pension Benefits | Postretirement Benefits | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2007 | 2006 | 2007 | 2006 | |||||||||
| (In millions) | ||||||||||||
Change in plan assets | |||||||||||||
Fair value of plan assets at January 1 | $ | 1,161.2 | $ | 1,107.1 | $ | — | $ | — | |||||
Actual return on plan assets | 71.3 | 141.1 | — | — | |||||||||
Employer contribution(1) | 129.3 | 55.2 | 28.9 | 26.7 | |||||||||
Plan participants' contributions | — | — | 8.7 | 8.3 | |||||||||
Benefits paid(2) (3) | (103.3 | ) | (142.2 | ) | (37.6 | ) | (35.0 | ) | |||||
Fair value of plan assets at December 31 | $ | 1,258.5 | $ | 1,161.2 | $ | — | $ | — | |||||
| Pension Benefits | Postretirement Benefits | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | 2010 | 2009 | |||||||||
| (In millions) | ||||||||||||
Change in plan assets | |||||||||||||
Fair value of plan assets at January 1 | $ | 1,058.1 | $ | 867.6 | $ | — | $ | — | |||||
Actual return on plan assets | 148.8 | 217.6 | — | — | |||||||||
Employer contribution (1) | 289.1 | 341.5 | 18.5 | 24.4 | |||||||||
Plan participants' contributions | — | — | 10.5 | 10.2 | |||||||||
Separation of CENG Plan | — | (234.4 | ) | — | — | ||||||||
Settlements | (5.2 | ) | (19.0 | ) | — | — | |||||||
Benefits paid (2)(3) | (82.7 | ) | (115.2 | ) | (29.0 | ) | (34.6 | ) | |||||
Fair value of plan assets at December 31 | $ | 1,408.1 | $ | 1,058.1 | $ | — | $ | — | |||||
Net Periodic Benefit Cost and Amounts Recognized in Other Comprehensive Income
We show the components of net periodic pension benefit cost in the following table:
Year Ended December 31, | 2007 | 2006 | 2005 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Components of net periodic pension benefit cost | ||||||||||
Service cost | $ | 49.4 | $ | 49.0 | $ | 44.8 | ||||
Interest cost | 94.7 | 89.3 | 83.9 | |||||||
Expected return on plan assets | (102.6 | ) | (96.6 | ) | (100.2 | ) | ||||
Amortization of unrecognized prior service cost | 5.2 | 5.7 | 5.7 | |||||||
Recognized net actuarial loss | 32.7 | 37.3 | 25.1 | |||||||
Amount capitalized as construction cost | (11.7 | ) | (13.4 | ) | (7.4 | ) | ||||
Net periodic pension benefit cost (1) | $ | 67.7 | $ | 71.3 | $ | 51.9 | ||||
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Components of net periodic pension benefit cost | ||||||||||
Service cost | $ | 37.9 | $ | 50.8 | $ | 55.4 | ||||
Interest cost | 84.7 | 101.1 | 100.2 | |||||||
Expected return on plan assets | (101.8 | ) | (118.9 | ) | (111.3 | ) | ||||
Amortization of unrecognized prior service cost | 3.9 | 10.9 | 10.9 | |||||||
Recognized net actuarial loss | 34.4 | 38.3 | 24.7 | |||||||
Amount capitalized as construction cost | (10.2 | ) | (10.2 | ) | (10.2 | ) | ||||
Net periodic pension benefit cost (1) | $ | 48.9 | $ | 72.0 | $ | 69.7 | ||||
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We show the components of net periodic postretirement benefit cost in the following table:
Year Ended December 31, | 2007 | 2006 | 2005 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Components of net periodic postretirement benefit cost | ||||||||||
Service cost | $ | 6.5 | $ | 7.7 | $ | 7.6 | ||||
Interest cost | 24.4 | 23.7 | 23.8 | |||||||
Amortization of transition obligation | 2.1 | 2.1 | 2.1 | |||||||
Recognized net actuarial loss | 4.1 | 6.6 | 6.4 | |||||||
Amortization of unrecognized prior service cost | (3.5 | ) | (3.5 | ) | (3.5 | ) | ||||
Amount capitalized as construction cost | (7.7 | ) | (8.2 | ) | (7.7 | ) | ||||
Net periodic postretirement benefit cost (1) | $ | 25.9 | $ | 28.4 | $ | 28.7 | ||||
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Components of net periodic postretirement benefit cost | ||||||||||
Service cost | $ | 2.4 | $ | 6.3 | $ | 6.1 | ||||
Interest cost | 17.7 | 22.6 | 24.0 | |||||||
Amortization of transition obligation | 2.1 | 2.1 | 2.1 | |||||||
Recognized net actuarial loss | 0.4 | 2.2 | 2.0 | |||||||
Amortization of unrecognized prior service cost | (2.6 | ) | (3.4 | ) | (3.5 | ) | ||||
Amount capitalized as construction cost | (5.4 | ) | (6.3 | ) | (7.6 | ) | ||||
Net periodic postretirement benefit cost (1) | $ | 14.6 | $ | 23.5 | $ | 23.1 | ||||
As In determining net periodic pension benefit cost, we apply our expected return on plan assets to a resultmarket-related value of adopting SFAS No. 158, theplan assets that recognizes asset gains and losses ratably over a five-year period.
The following is a summary of amounts we have recorded in "Accumulated other comprehensive income"loss" and of expected amortization of those amounts over the next twelve months:
| | | | | Expected Amortiz- ation Next 12 Months | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Pension Benefits | Postretirement Benefits | |||||||||||||
| 2007 | 2006 | 2007 | 2006 | |||||||||||
| (In millions) | ||||||||||||||
Unrecognized actuarial loss | $ | 445.9 | $ | 475.7 | $ | 90.2 | $ | 116.6 | $ | 30.6 | |||||
Unrecognized prior service cost | 21.4 | 26.7 | (26.2 | ) | (29.7 | ) | 1.4 | ||||||||
Unrecognized transition obligation | — | — | 10.7 | 12.8 | 2.1 | ||||||||||
Total | $ | 467.3 | $ | 502.4 | $ | 74.7 | $ | 99.7 | $ | 34.1 | |||||
| Pension Benefits | Postretirement Benefits | | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Expected Amortiz- ation Next 12 Months | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | ||||||||||||
| (In millions) | |||||||||||||||
Unrecognized actuarial loss | $ | 741.4 | $ | 702.2 | $ | 65.3 | $ | 51.5 | $ | 49.5 | ||||||
Unrecognized prior service cost | 6.1 | 9.9 | (14.0 | ) | (13.9 | ) | 1.1 | |||||||||
Unrecognized transition obligation | — | — | 3.5 | 6.2 | 1.8 | |||||||||||
Total | $ | 747.5 | $ | 712.1 | $ | 54.8 | $ | 43.8 | $ | 52.4 | ||||||
Expected Cash Benefit Payments
The pension and postretirement benefits we expect to pay in each of the next five calendar years and in the aggregate for the subsequent five years are shown below.in the following table. These estimated benefits are based on the same assumptions used to measure the benefit obligation at December 31, 2007,2010, but include benefits attributable to estimated future employee service.
| | Postretirement Benefits | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| Pension Benefits* | Before Medicare Part D | Subsidy | After Medicare Part D | ||||||||
| (In millions) | |||||||||||
2008 | $ | 107.2 | $ | 31.2 | $ | (2.4 | ) | $ | 28.8 | |||
2009 | 102.3 | 32.3 | (2.6 | ) | 29.7 | |||||||
2010 | 115.9 | 33.0 | (2.8 | ) | 30.2 | |||||||
2011 | 108.4 | 33.6 | (2.9 | ) | 30.7 | |||||||
2012 | 121.8 | 33.9 | (3.1 | ) | 30.8 | |||||||
2013-2017 | 763.4 | 178.6 | (16.2 | ) | 162.4 |
| Pension Benefits | Postretirement Benefits (1) | |||||
---|---|---|---|---|---|---|---|
2011 | $ | 105.5 | $ | 23.0 | |||
2012 | 100.5 | 23.3 | |||||
2013 | 108.1 | 23.8 | |||||
2014 | 111.3 | 24.4 | |||||
2015 | 147.9 | 24.8 | |||||
2016-2020 | 669.3 | 127.4 | |||||
* Excludes transfers to nonqualified deferred compensation plans
Assumptions
We made the assumptions below to calculate our pension and postretirement benefit obligations and periodic cost.
| Pension Benefits | Postretirement Benefits | Assumption Impacts Calculation of | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| 2007 | 2006 | 2007 | 2006 | ||||||
Discount rate | 6.25 | % | 6.00 | % | 6.25 | % | 6.00 | % | Benefit Obligation and Periodic Cost | |
Expected return on plan assets | 8.75 | 8.75 | N/A | N/A | Periodic Cost | |||||
Rate of compensation increase | 4.0 | 4.0 | 4.0 | 4.0 | Benefit Obligation and Periodic Cost |
| Pension Benefits | Postretirement Benefits | | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Assumption Impacts Calculation of | |||||||||||||
| 2010 | 2009 | 2010 | 2009 | ||||||||||
Discount rate | 5.50 | % | 6.00 | % | 5.50 | % | 6.00 | % | Benefit Obligation and Periodic Cost | |||||
Expected return on plan assets | 8.50 | 8.50 | N/A | N/A | Periodic Cost | |||||||||
Rate of compensation increase | 4.0 | 4.0 | 4.0 | 4.0 | Benefit Obligation and Periodic Cost |
Our discount rate is based on a bond portfolio analysis of high quality corporate bonds whose maturities match our expected benefit payments. Our 8.75%8.50% overall expected long-term rate of return on plan assets reflectsreflected our long-term investment strategy in terms of asset mix targets and expected returns for each asset class at the beginning of 2010. Effective in 2011, we reduced our expected long-term rate of return assumption to 8.00% reflecting our updated investment strategy, asset mix, and expected return for each asset class.
Annual health care inflation rate assumptions also impact the calculation of our postretirement benefit obligation and periodic cost. We assumed the following health care inflation rates to produce average claims by year as shown below:
At December 31, | 2007 | 2006 | ||
---|---|---|---|---|
Next year | 9.0% | 8.5% | ||
Following year | 8.0% | 8.0% | ||
Ultimate trend rate | 5.0% | 5.0% | ||
Year ultimate trend rate reached | 2014 | 2014 |
At December 31, | 2010 | 2009 | |||||
---|---|---|---|---|---|---|---|
Next year | 8.5 | % | 8.0 | % | |||
Following year | 7.5 | % | 7.5 | % | |||
Ultimate trend rate | 5.0 | % | 5.0 | % | |||
Year ultimate trend rate reached | 2017 | 2016 |
A one-percentone-percentage point increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit obligation by approximately $29$21.6 million as of December 31, 20072010 and would increase the combined service and interest costs of the postretirement benefit cost by approximately $2$1.2 million annually.
A one-percentone-percentage point decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretirement benefit obligation by approximately $25$18.8 million
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as of December 31, 20072010 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $2$1.1 million annually.
Qualified Pension Plan Assets
The asset allocations forInvestment Strategy
We invest our qualified pension plan assets using the following investment objectives:
To achieve these objectives, Constellation Energy, through a management Investment Committee (the Committee), has adopted an investment strategy that divides its pension investment program into two primary portfolios:
Currently, the Committee allocates 60% of its plan assets to return seeking assets to help reduce existing deficits in the funded status of the plan. As the funded status of our plans wereimprove, the Committee expects to reduce its exposure to return seeking assets and increase its liability hedging assets to reduce its total risk.
Return Seeking Assets
The purpose of return seeking assets is to provide investment returns in excess of the growth of pension liabilities. This category includes a diversified portfolio of public equities, private equity, real estate, hedge funds, high yield bonds and other instruments. These assets are likely to have lower correlations with the pension liabilities and lead to higher funded status risk over shorter periods of time.
Liability Hedging Assets
The purpose of liability hedging assets, such as follows:long duration bonds and interest rate derivatives, is to hedge against interest rate changes. Exposure to liability hedging assets is intended to reduce the volatility of plan funded status, contributions, and pension expense.
At December 31, | 2007 | 2006 | |||
---|---|---|---|---|---|
Equity securities | 62 | % | 64 | % | |
Debt securities | 31 | 28 | |||
Other | 7 | 8 | |||
Total | 100% | 100% | |||
Risk Management
The Committee manages plan asset risk using several approaches. First, the assets are invested in two diverse portfolios, each of which contains investments across a spectrum of asset classes. Second, the Committee considers the long-term investment horizon of the plan, which is greater than ten years. The long-term horizon enables the Committee to tolerate the risk of investment losses in the short-term with the expectation of higher returns in the long-term. Third, the Committee employs a thorough due diligence program prior to selecting an investment, and a rigorous ongoing monitoring program once assets are invested. The Committee evaluates risk on an ongoing basis.
Asset Allocation
Plan assets are diversified across various asset classes and securities based on the investment strategy approved by the Committee. This policy allocation is long-term oriented and consistent with the risk tolerance and funded status. The target asset allocation as well as the actual allocations for 2010 and 2009 are provided below.
| Target Allocation | Actual Allocation | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
At December 31, | 2010 | 2009 | 2010 | 2009 | |||||||||
Global equity securities | 42 | % | 48 | % | 42 | % | 57 | % | |||||
Fixed income securities | 40 | 30 | 37 | 27 | |||||||||
Alternative investments | 12 | 15 | 8 | 7 | |||||||||
High yield bonds | 6 | 7 | 6 | 7 | |||||||||
Cash and cash equivalents | — | — | 7 | 2 | |||||||||
Derivative instruments | — | — | — | — | |||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | |||||
The category "Other" primarily representstarget asset allocation also allows for investments in financial limited partnerships. Our long-term pension plan investment strategy isinstruments, including asset-backed securities and collateralized mortgage obligations, which are exposed to seekinterest rate and market risk as well as overall market volatility. These instruments are sensitive to changes in economic conditions. Such changes could materially affect the amounts reported.
The actual portfolio was rebalanced in December 2010 in accordance with policy target allocations and an asset mix of 58% equity, 30% fixed income, and 12% other investments. Weimprovement in funded status. The Committee will also rebalance our portfolio periodically when the sumactual allocations fall outside of equity and other investments differs from 70% by three percentage pointsthe ranges prescribed in the investment policy or more, we change an outside investment advisor, or we make contributions toas the trust.funded status improves.
Fair Value Hierarchy
We determine expected return onthe fair value of the plan assets using unadjusted quoted prices in active markets (Level 1) or pricing inputs that are observable (Level 2) whenever that information is available. We use unobservable inputs (Level 3) to estimate fair value only when relevant observable inputs are not available. We classify assets within this fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset taken as a market-relatedwhole.
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The following tables set forth by level, within the fair value hierarchy, the investments in the Plans' master trust at fair value as of December 31, 2010 and 2009:
At December 31, 2010 | Level 1 | Level 2 | Level 3 | Total Fair Value | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||||
Global equity securities: | ||||||||||||||
Marketable equity securities | $ | 143.6 | $ | — | $ | — | $ | 143.6 | ||||||
Common collective trusts | — | 447.5 | — | 447.5 | ||||||||||
Fixed income securities: | ||||||||||||||
Corporate debt securities | — | 327.9 | — | 327.9 | ||||||||||
Government / agency securities | — | 113.0 | — | 113.0 | ||||||||||
Municipal bonds | — | 54.8 | — | 54.8 | ||||||||||
Guarantee insurance contracts | — | 21.6 | — | 21.6 | ||||||||||
High yield bonds | — | 86.9 | — | 86.9 | ||||||||||
Cash equivalents | 93.6 | — | — | 93.6 | ||||||||||
Derivative instruments | — | 0.9 | — | 0.9 | ||||||||||
Alternative investments | — | — | 118.3 | 118.3 | ||||||||||
Total | $ | 237.2 | $ | 1,052.6 | $ | 118.3 | $ | 1,408.1 | ||||||
At December 31, 2009 | Level 1 | Level 2 | Level 3 | Total Fair Value | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||||
Global equity securities | $ | 215.4 | $ | 383.0 | $ | — | $ | 598.4 | |||||
Fixed income securities | — | 289.2 | — | 289.2 | |||||||||
High yield bonds | 0.6 | 75.6 | — | 76.2 | |||||||||
Cash equivalents | 19.9 | — | — | 19.9 | |||||||||
Alternative investments | — | — | 74.4 | 74.4 | |||||||||
Total | $ | 235.9 | $ | 747.8 | $ | 74.4 | $ | 1,058.1 | |||||
The following is a description of the valuation methodologies used for assets measured at fair value:
The following table summarizes the changes in the fair value of the Level 3 assets for the years ended December 31, 2010 and 2009:
| Year Ended December 31, | |||||||
---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | ||||||
| (In millions) | |||||||
Balance at beginning of period | $ | 74.4 | $ | 96.3 | ||||
Actual return on plan assets: | ||||||||
Assets still held at year end | (32.1 | ) | (2.5 | ) | ||||
Assets sold during the year | 37.0 | 6.4 | ||||||
Purchases, sales, and settlements | 22.2 | (10.8 | ) | |||||
Transfers into Level 3 | 16.8 | |||||||
Transfers out of Level 3 | — | |||||||
Net transfers into and out of Level 3 | 16.8 | (15.0 | ) | |||||
Balance at end of year | $ | 118.3 | $ | 74.4 | ||||
Contributions and Benefit Payments
We contributed $125$279.7 million to our qualified pension plans in March 2007, even though there2010. $243.0 million of this contribution was no IRS required minimum contribution in 2007. We expectan acceleration of estimated calendar year 2011 and 2012 contributions. Therefore, we do not plan to contribute $76 millionmake contributions to our qualified pension plans in 2008.2011 and 2012. Our non-qualified pension plans and our postretirement benefit programs are not funded. We estimate that we will incur approximately $8$7 million in pension benefits for our non-qualified pension plans and approximately $29$23 million for retiree health and life insurance costs net of Medicare Part D during 2008.2011.
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Other Postemployment Benefits
We provide the following postemployment benefits:
We recognized expense associated with our other postemployment benefits of $16.7$9.9 million in 2007, $9.62010, $5.3 million in 2006,2009, and $9.2$1.9 million in 2005.2008. BGE's portion of expense associated with other postemployment benefits was $10.2$7.6 million in 2007, $5.62010, $4.4 million in 2006,2009, and $5.4$2.2 million in 2005.2008.
We assumed the discount rate for other postemployment benefits to be 5.25%4.00% in 20072010 and 5.50%4.75% in 2006.2009. This assumption impacts the calculation of our other postemployment benefit obligation and periodic cost.
Employee Savings Plan Benefits
We sponsored two defined contribution plans until November 6, 2009, when upon the close of the sale of a 49.99% interest in CENG to EDF, we deconsolidated CENG and the defined contribution plan related to Nine Mile Point was removed from our books. For all remaining eligible employees of Constellation Energy, we continue to sponsor a defined contribution savings plans that are offered to all eligible employees.plan. The savings plans areplan is a qualified 401(k) plansplan under the Internal Revenue Code. In a defined contribution plan, the benefits a participant is to receive result from regular contributions to a participant account. Matching contributions to participant accounts are made under these plans. Matching contributions to these plans were as follows:
Year Ended December 31, | 2007 | 2006 | 2005 | ||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Nonregulated businesses | $ | 16.1 | $ | 14.6 | $ | 13.5 | |||
BGE | 5.8 | 5.4 | 5.1 | ||||||
Total Constellation Energy | $ | 21.9 | $ | 20.0 | $ | 18.6 | |||
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Nonregulated businesses | $ | 9.9 | $ | 14.8 | $ | 17.6 | ||||
BGE | 6.3 | 5.7 | 5.8 | |||||||
Total Constellation Energy | $ | 16.2 | $ | 20.5 | $ | 23.4 | ||||
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8Credit Facilities and Short-Term Borrowings
Our short-term borrowings may include bank loans, commercial paper, and bank lines of credit. Short-term borrowings mature within one year from the date of issuance. We pay commitment fees to banks for providing us lines of credit. When we borrow under the lines of credit, we pay market interest rates.
Constellation Energy
Constellation Energy had a committed bank line of credit under a five-year credit facility, expiring in July 2012, of $3.85 billion and a one year $250.0 million credit facility at December 31, 2007 for short-term financial needs.
We enter into these facilities to ensure adequate liquidity to support our operations. Currently, we
Constellation Energy
Our liquidity requirements are funded with credit facilities and cash. We fund our short-term working capital needs with existing cash and with our credit facilities, which support direct cash borrowings and the issuance of commercial paper, if available. We also use theour credit facilities to issuesupport the issuance of letters of credit, primarily for our merchant energyNewEnergy business. Additionally, we can borrow directly from the banks or use the facilities to allow the issuance of commercial paper.
These facilities can issue lettersConstellation Energy had bank lines of credit up to approximately $4.1 billion. Letters ofunder committed credit issued under this facility totaled $1.8facilities totaling $4.2 billion at December 31, 2007.2010 for short-term financial needs as follows:
Type of Credit Facility | Amount (In billions) | Expiration Date | Capacity Type | ||||
---|---|---|---|---|---|---|---|
Syndicated Revolver | $ | 2.50 | October 2013 | Letters of credit and cash | |||
Commodity-linked | 0.50 | August 2014 | Letter of credit and cash | ||||
Bilateral | 0.55 | September 2014 | Letters of credit | ||||
Bilateral | 0.25 | December 2014 | Letters of credit and cash | ||||
Bilateral | 0.25 | June 2014 | Letters of credit and cash | ||||
Bilateral | 0.15 | September 2013 | Letters of credit | ||||
Total | $ | 4.20 | |||||
At December 31, 2006,2010, we had approximately $1.6 billion in letters of credit issued, including $0.4 billion in letters of credit issued under previousthe commodities-linked credit facilities that were replaced withfacility discussed below, and no commercial paper outstanding under these facilities.
The commodity-linked credit facility currently allows for the five-year facility in 2007 totaled $1.6 billion. The increase inissuance of letters of credit issuedand, as modified in 2010, for cash borrowings, up to a maximum capacity of $0.5 billion. This commodity-linked facility is primarily duedesigned to changes inhelp manage our contingent collateral requirements associated with counterpartiesthe hedging of our NewEnergy business because its capacity increases up to the maximum capacity as natural gas price levels decrease compared to a result of commodityreference price changes.that is adjusted periodically.
In addition,At December 31, 2010, Constellation Energy had $14.0$32.4 million of short-term borrowingsnotes outstanding at December 31, 2007 underwith a three year $50 million line of credit expiring in 2010 relating to our merchant energy business. The weighted-average effective interest rate for this outstanding borrowing was 7.44% at December 31, 2007. There were no short-term borrowings outstanding under this line of credit at December 31, 2006.
In January 2008, we entered into a new six month line of credit totaling $500.0 million. This line of credit expires in July 2008 and has an option to be extended for an additional six months, subject to the lender's approval.6.56%.
BGE
BGE had no commercial paper outstanding at December 31, 2007 or 2006.
BGE has a $400.0$600.0 million five-year revolving credit facility expiring in 2011. As of December 31, 2007, BGE had $0.7 million of letters of credit issued under this facility.2011. BGE can borrow directly from the banks, use the facility to allow commercial paper to be issued, if available, or issue letters of credit. At December 31, 2010, BGE had no commercial paper outstanding. There were immaterial letters of credit outstanding at December 31, 2010.
Net Available Liquidity
The following table provides a summary of our net available liquidity at December 31, 2010:
At December 31, 2010 | Constellation Energy (excluding BGE) | BGE | |||||
---|---|---|---|---|---|---|---|
| (In billions) | ||||||
Credit facilities (1) | $ | 3.7 | $ | 0.6 | |||
Less: Letters of credit issued (1) | (1.2 | ) | — | ||||
Less: Cash drawn on credit facilities | — | — | |||||
Undrawn facilities | 2.5 | 0.6 | |||||
Less: Commercial paper outstanding | — | — | |||||
Net available facilities | 2.5 | 0.6 | |||||
Add: Cash and cash equivalents (2) | �� | 2.0 | — | ||||
Less: Reserved cash (3) | (1.2 | ) | — | ||||
Net available liquidity | $ | 3.3 | $ | 0.6 | |||
Credit Facility Compliance and Covenants
The credit facilities of Constellation Energy and BGE contain a material adverse change representation but draws on the facilities are not conditioned upon Constellation Energy and BGE making this representation at the time of the draw. However, to the extent a material adverse change has occurred and prevents Constellation Energy or BGE from making other representations that are required at the time of the draw, the draw would be prohibited.
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 December 31, 2010, the debt to capitalization ratio as defined in the credit agreements was 36%.
The credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At December 31, 2010, the debt to capitalization ratio for BGE as defined in this credit agreement was 43%.
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Decreases in Constellation Energy's or BGE's credit ratings would not trigger an early payment on any of our, or BGE's, credit facilities. However, the impact of a credit ratings downgrade on our financial ratios associated with our credit facility covenants would depend on our financial condition at the time of such a downgrade and on the source of funds used to satisfy the incremental collateral obligation resulting from a credit ratings downgrade. For example, if we were to use existing cash balances to fund the cash portion of any additional collateral obligations resulting from a credit ratings downgrade, we would not expect a material impact on our financial ratios. However, if we were to issue long-term debt or use our credit facilities to fund any additional collateral obligations, our financial ratios could be materially affected. Failure by Constellation Energy, or BGE, to comply with these covenants could result in the agreements to allowacceleration of the issuancematurity of commercial paper.the borrowings outstanding and preclude us from issuing letters of credit under these facilities.
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9 Capitalization
We detail in the table below our total capitalization, which includes long-term debt, common stock, noncontrolling interests, and preference stock, as of December 31, 2010 and 2009.
At December 31, | 2010 | 2009 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Long-Term Debt | ||||||||||
Long-term debt of Constellation Energy | ||||||||||
8.625% Series A Junior Subordinated Debentures, due June 15, 2063 | $ | 450.0 | $ | 450.0 | ||||||
7.00% Fixed-Rate Notes, due April 1, 2012 | 213.5 | 700.0 | ||||||||
4.55% Fixed-Rate Notes, due June 15, 2015 | 550.0 | 550.0 | ||||||||
5.15% Fixed-Rate Notes, due December 1, 2020 | 550.0 | — | ||||||||
7.60% Fixed-Rate Notes, due April 1, 2032 | 700.0 | 700.0 | ||||||||
Fair Value of Interest Rate Swaps | 36.2 | 38.6 | ||||||||
Total long-term debt of Constellation Energy | 2,499.7 | 2,438.6 | ||||||||
Long-term debt of nonregulated businesses | ||||||||||
Tax-exempt debt transferred from BGE effective July 1, 2000 | ||||||||||
4.10% Pollution control loan, due July 1, 2014 | 20.0 | 20.0 | ||||||||
Tax-exempt variable rate notes, due April 1, 2024 | 75.0 | 75.0 | ||||||||
Tax-exempt variable rate notes, due December 1, 2025 | — | 47.0 | ||||||||
Tax-exempt variable rate notes, due December 1, 2037 | — | 65.0 | ||||||||
5.00% Mortgage note, due June 15, 2010 | — | 0.4 | ||||||||
7.3% Fixed Rate Note, due June 1, 2012 | 1.7 | 1.7 | ||||||||
Asset-based lending agreement due July 16, 2012 | 18.0 | 27.1 | ||||||||
Total long-term debt of nonregulated businesses | 114.7 | 236.2 | ||||||||
Other long-term debt of BGE | ||||||||||
6.125% Notes, due July 1, 2013 | 400.0 | 400.0 | ||||||||
5.90% Notes, due October 1, 2016 | 300.0 | 300.0 | ||||||||
5.20% Notes, due June 15, 2033 | 200.0 | 200.0 | ||||||||
6.35% Notes, due October 1, 2036 | 400.0 | 400.0 | ||||||||
Medium-term notes, Series E | 131.5 | 131.5 | ||||||||
Total other long-term debt of BGE | 1,431.5 | 1,431.5 | ||||||||
6.20% deferrable interest subordinated debentures due October 15, 2043 to BGE wholly owned BGE Capital Trust II relating to trust preferred securities | 257.7 | 257.7 | ||||||||
Rate stabilization bonds | 454.4 | 510.9 | ||||||||
Unamortized discount and premium | (3.9 | ) | (4.0 | ) | ||||||
Current portion of long-term debt | (305.3 | ) | (56.9 | ) | ||||||
Total long-term debt | $ | 4,448.8 | $ | 4,814.0 | ||||||
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At December 31, | 2010 | 2009 | ||||||
---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||
Equity: | ||||||||
Noncontrolling Interests | $ | 88.8 | $ | 75.3 | ||||
BGE Preference Stock | ||||||||
Cumulative preference stock not subject to mandatory redemption, 6,500,000 shares authorized 7.125%, 1993 Series, 400,000 shares outstanding, callable at $101.07 per share until June 30, 2011, and at lesser amounts thereafter | 40.0 | 40.0 | ||||||
6.97%, 1993 Series, 500,000 shares outstanding, callable at $101.05 per share until September 30, 2011, and at lesser amounts thereafter | 50.0 | 50.0 | ||||||
6.70%, 1993 Series, 400,000 shares outstanding, callable at $101.01 per share until December 31, 2011, and at lesser amounts thereafter | 40.0 | 40.0 | ||||||
6.99%, 1995 Series, 600,000 shares outstanding, callable at $101.75 per share until September 30, 2011, and at lesser amounts thereafter | 60.0 | 60.0 | ||||||
Total BGE preference stock not subject to mandatory redemption | 190.0 | 190.0 | ||||||
Common Shareholders' Equity | ||||||||
Common stock without par value, 600,000,000 shares authorized; 199,788,658 and 200,985,414 shares issued and outstanding at December 31, 2010 and 2009, respectively. (At December 31, 2010, 12,818,160 shares were reserved for the long-term incentive plans, 8,788,849 shares were reserved for the shareholder investment plan, and 1,884,258 shares were reserved for the employee savings plan.) | 3,231.7 | 3,229.6 | ||||||
Retained earnings | 5,270.8 | 6,461.0 | ||||||
Accumulated other comprehensive loss | (673.3 | ) | (993.5 | ) | ||||
Total common shareholders' equity | 7,829.2 | 8,697.1 | ||||||
Total Equity | 8,108.0 | 8,962.4 | ||||||
Total Capitalization | $ | 12,556.8 | $ | 13,776.4 | ||||
Long-Term Debt,BGE Common Stock and Preference StockShareholder Equity
At December 31, | 2010 | 2009 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Common Stock | $ | 1,293.1 | $ | 1,293.1 | |||
Retained Earnings | 779.5 | 645.1 | |||||
Accumulated other comprehensive income | 0.6 | 0.6 | |||||
Total BGE common shareholder equity | $ | 2,073.2 | $ | 1,938.8 | |||
Certain prior-period amounts have been reclassified to conform with the current period's presentation.
Long-term Debt
Long-term debt matures in one year or more from the date of issuance. The long-term debt of Constellation Energy and BGE do not contain material adverse change clauses. We detail our long-term debt in our Consolidated Statements of Capitalization. As you read this section, it may be helpful to refer to those statements.the table above.
Constellation Energy
5.15% Notes due December 1, 2020
In December 2007,2010, we issued $65.0$550 million of tax-exempt variable5.15% Notes due December 1, 2020. Interest is payable semi-annually on June 1 and December 1, beginning June 1, 2011. At any time prior to September 1, 2020, we may redeem some or all of the notes at a price equal to the greater of 100% of the principal amount of the notes outstanding to be redeemed and the sum of the present values of the remaining scheduled payments of principal and interest on the notes being redeemed, discounted to the redemption date on a semi-annual basis at the Treasury rate plus 30 basis points, plus accrued interest. After September 1, 2020, we may redeem some or all of the notes at a price equal to finance100% of the acquisition, construction, installation and equippingprincipal amount of certain sewage and solid waste disposal facilities at onethe notes outstanding to be redeemed plus accrued interest on the principal amount being redeemed to the redemption date.
Additionally, in December 2010, we issued a notice to redeem $213.5 million of our coal-fired power plants in Maryland.
On October 31, 2006, CEP entered into a $200.0 million secured revolving credit facility, and at December 31, 2006, CEP had $22.0 million7.00% Notes, which represented the remaining outstanding 7.00% Notes due April 1, 2012. As such, we classified these notes as "Current portion of borrowings outstanding under this facility. However, during 2007, CEP issued additional equity to the public and our ownership percentage fell below 50 percent. Therefore, we deconsolidated CEP and began accounting for our investment using the equity method of accounting. As a result, the borrowings outstanding under the CEP credit facility at the time of deconsolidation are no longer includedlong-term debt" in our Consolidated Balance Sheets. In January 2011, we redeemed these notes with part of the proceeds from the issuance of the $550 million 5.15% Notes, terminated the associated interest rate swaps, and recognized a pre-tax loss of approximately $5 million on this transaction.
During February 2011, we entered into interest rate swaps qualifying as fair value hedges related to $350 million of our fixed rate debt maturing in 2015. We also entered into $150 million of interest rate swaps related to our fixed rate debt maturing in 2020 that do not qualify as fair value hedges, and will be marked to market through earnings. These swaps effectively converted $500 million notional amount of fixed rate debt to floating rate for the term of the swaps.
We discuss our interest rate swaps inNote 13.
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Upstream Gas Property Asset-Based Lending Agreement
In July 2009, we entered into a three year asset-based lending agreement associated with certain upstream gas properties that we own. At December 31, 2010, the borrowing base committed under the facility was $100 million, of which $18.0 million has been utilized and reflected in "Long-term debt" in our Consolidated Balance Sheets. The size of the facility may be increased up to $200 million with additional commitments by the lenders. Any debt issued under this facility is secured by the upstream gas properties, and the lenders do not have recourse against Constellation Energy in the event of a default. Interest is payable quarterly in March, June, September, and December.
This asset-based lending agreement contains a provision that requires certain of our entities that own our upstream gas properties to maintain a current ratio of one-to-one. As of December 31, 2010, these entities were in compliance with this provision.
Voluntary Debt Retirements
As part of our voluntary commitment to reduce our debt by $1 billion with funds received from the EDF transaction, we retired the following debt completing this commitment.
7.00% Notes due April 1, 2012
In February 2010, we retired an aggregate principal amount of $486.5 million of our 7.00% Notes due April 1, 2012 pursuant to a cash tender offer, at a premium of approximately 11%. We recorded a loss on this transaction of $51.6 million within "Interest expense" on our Consolidated Statements of Income (Loss).
Tax-Exempt Notes
During 2009, we retired approximately $150 million of variable rate tax exempt notes prior to maturity. In March, 2010, we repurchased our outstanding $47 million and $65 million variable rate tax-exempt notes. Since these notes are variable rate instruments, there was no gain or loss recorded upon repurchase.
Zero Coupon Senior Notes
In November 2009, we redeemed an aggregate principal amount of $267.6 million for the Zero Coupon Senior Notes early and recognized a pre-tax loss on redemption of $16.0 million. We recorded the loss within "Interest expense" in the Consolidated Statements of Income (Loss).
BGE
BGE's First Refunding Mortgage BondsSecured Indenture
BGE'sBGE entered into a secured indenture in July 2009. The secured indenture creates a first refunding mortgage bonds are secured by a mortgagepriority lien on substantially all of its assets. The generating assets BGE transferred to subsidiaries of Constellation Energy also remain subject toBGE's electric utility distribution equipment and fixtures and on BGE's franchises, permits, and licenses that are transferable and necessary for the lien of BGE's mortgage, along with the stock of Safe Harbor Water Power Corporation and Constellation Enterprises, Inc. We expect the assets to be released from this lien following payment in March 2008operation of the last seriesequipment and fixtures. As of December 31, 2010, BGE has not issued any secured bonds outstanding under the mortgage and the subsequent discharge of the mortgage.
BGE is required to make an annual sinking fund payment each August 1 to the mortgage trustee. The amount of the payment is equal to 1% of the highest principal amount of bonds outstanding during the preceding 12 months. The trustee uses these funds to retire bonds from any series through repurchases or calls for early redemption. However, the trustee cannot call the 65/8% Series, due 2008 outstanding bonds for early redemption.this indenture.
BGE's Rate Stabilization Bonds
In June 2007, BondCo, a subsidiary of BGE, issued an aggregate principal amount of $623.2 million of rate stabilization bonds to recover deferred power purchase costs. We discuss BondCo in more detail inNote 4. Below are the details of the rate stabilization bonds:bonds at December 31, 2010:
Principal | Interest Rate | Scheduled Maturity Date | ||
---|---|---|---|---|
$284.0 | 5.47 | % | October 2012 | |
220.0 | 5.72 | April 2016 | ||
119.2 | 5.82 | April 2017 |
Principal | Interest Rate | Scheduled Maturity Date | |||
---|---|---|---|---|---|
$115.2 | 5.47 | % | October 2012 | ||
220.0 | 5.72 | April 2016 | |||
119.2 | 5.82 | April 2017 |
The bonds are secured primarily by a usage-based, non-bypassable charge payable by all of BGE's residential electric customers over the nexta ten years.year period. The charges will be adjusted semi-annually to ensure that the aggregate charges collected are sufficient to pay principal and interest on the bonds, as well as certain on-going costs of administering and servicing the bonds. BondCo cannot use the charges collected to satisfy any other obligations. BondCo's assets are not assets of any affiliate and are not available to pay creditors of any affiliate of BondCo. If BondCo is unable to make principal and interest payments on the bonds, neither Constellation Energy, nor BGE, are required to make the payments on behalf of BondCo.
BGE's Other Long-Term Debt
On July 1, 2000, BGE transferred $278.0 million of tax-exempt debt to our merchant energyGeneration business related to the transferred generating assets. At December 31, 2007,2010, BGE remains contingently liable for the $147.8$20 million outstanding balance of this debt.
We show the weighted-average interest rates and maturity dates for BGE's fixed-rate medium-term notesnote, series E, outstanding at December 31, 2007 in the following table.2010 has a weighted average interest rate of 6.73%, maturing between 2011 and 2012.
Series | Weighted-Average Interest Rate | Maturity Dates | ||
---|---|---|---|---|
E | 6.66 | % | 2008-2012 | |
G | 6.08 | % | 2008 |
BGE Deferrable Interest Subordinated Debentures
On November 21, 2003, BGE Capital Trust II (BGE Trust II), a Delaware statutory trust established by BGE, issued 10,000,000 Trust Preferred Securities for $250 million ($25 liquidation amount per preferred security) with a distribution rate of 6.20%.
BGE Trust II used the net proceeds from the issuance of common securities to BGE and the Trust Preferred Securities to purchase a series of 6.20% Deferrable Interest Subordinated Debentures due October 15, 2043 (6.20% debentures) from BGE in the aggregate principal amount of $257.7 million with the same terms as the Trust Preferred Securities. BGE Trust II must redeem the Trust Preferred Securities at $25 per preferred security plus accrued but unpaid distributions when the 6.20% debentures are paid at maturity or upon any earlier redemption. BGE has the option to redeem the 6.20% debentures at any time on or after November 21, 2008 or at any time when certain tax or other events occur.
BGE Trust II will use the interest paid on the 6.20% debentures to make distributions on the Trust Preferred
129
Securities. The 6.20% debentures are the only assets of BGE Trust II.
BGE fully and unconditionally guarantees the Trust Preferred Securities based on its various obligations relating to the trust agreement, indentures, 6.20% debentures, and the preferred security guarantee agreement.
For the payment of dividends and in the event of liquidation of BGE, the 6.20% debentures are ranked prior to preference stock and common stock.
Revolving Credit Agreement
On December 18, 2001, BGE's subsidiary, District Chilled Water Partnership (ComfortLink) entered into a $25.0 million loan agreement with the Maryland Energy Financing Administration (MEFA). The terms of the loan exactly match the terms of variable rate, tax exempt bonds due December 1, 2031 issued by MEFA for ComfortLink to finance the cost of building a chilled water distribution system. The interest rate on this debt resets weekly. These bonds, and the corresponding loan, can be redeemed at any time at par plus accrued interest while under variable rates. The bonds can also be converted to a fixed rate at ComfortLink's option.
Debt Compliance and Covenants
The credit facilities of Constellation Energy and BGE discussed inNote 8 have limited material adverse change clauses, none of which would prohibit draws under the existing facilities. The long-term debt indentures of Constellation Energy and BGE do not contain material adverse change clauses or financial covenants.
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 December 31, 2007, the debt to capitalization ratio as defined in the credit agreements was 46%.
The credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At December 31, 2007, the debt to capitalization ratio for BGE as defined in this credit agreement was 47%. At December 31, 2007, no amounts were outstanding under these agreements.
Failure by Constellation Energy, or BGE, to comply with these covenants could result in the acceleration of the maturity of the debt outstanding under these facilities. The credit facilities of Constellation Energy contain usual and customary cross-default provisions that apply to defaults on debt by Constellation Energy and certain subsidiaries over a specified threshold.
The BGE credit facility also contains usual and customary cross-default provisions that apply to defaults on debt by BGE over a specified threshold. The indenture pursuant to which BGE has issued and outstanding mortgage bonds provides that a default under any debt instrument issued under the indenture may cause a default of all debt outstanding under such indenture.
Constellation Energy also provides credit support to Calvert Cliffs, Ginna, and Nine Mile Point to ensure these plants have funds to meet expenses and obligations to safely operate and maintain the plants.
Maturities of Long-Term Debt
OurAs of December 31, 2010, our long-term borrowings mature on the following schedule:
Year | Constellation Energy | Nonregulated Businesses | BGE | Total | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | | ||||||||||
2008 | $ | — | $ | 5.6 | $ | 350.0 | $ | 355.6 | ||||
2009 | 500.0 | 1.5 | 65.0 | 566.5 | ||||||||
2010 | — | 0.4 | 56.5 | 56.9 | ||||||||
2011 | — | 36.0 | 81.7 | 117.7 | ||||||||
2012 | 705.2 | 1.6 | 172.5 | 879.3 | ||||||||
Thereafter | 1,256.6 | 323.9 | 1,489.4 | 3,069.9 | ||||||||
Total long-term debt at December 31, 2007 | $ | 2,461.8 | $ | 369.0 | $ | 2,215.1 | $ | 5,045.9 | ||||
At December 31, 2007, we had long-term loans totaling $339.8 million that mature after 2007, which are periodically remarketed and could require repayment prior to maturity following any unsuccessful remarketing. As a result of these provisions, at December 31, 2007, $25.0 million is classified as current portion of long-term debt at BGE.
Year | Constellation Energy | Nonregulated Businesses | BGE | Total | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||||
2011 | $ | 223.6 | $ | — | $ | 81.7 | $ | 305.3 | |||||
2012 | — | 19.7 | 172.5 | 192.2 | |||||||||
2013 | — | — | 466.6 | 466.6 | |||||||||
2014 | — | 20.0 | 70.4 | 90.4 | |||||||||
2015 | 576.2 | — | 74.5 | 650.7 | |||||||||
Thereafter | 1,699.9 | 75.0 | 1,277.9 | 3,052.8 | |||||||||
Total | $ | 2,499.7 | $ | 114.7 | $ | 2,143.6 | $ | 4,758.0 | |||||
Weighted-Average Interest Rates for Variable Rate Debt
Our weighted-average interest rates for variable rate debt outstanding were:
At December 31, | 2007 | 2006 | ||||
---|---|---|---|---|---|---|
Nonregulated Businesses (including Constellation Energy) | ||||||
Loans under credit agreements | 3.77 | % | 3.69 | % | ||
Tax-exempt debt | 3.53 | % | 3.63 | % | ||
Fixed-rate debt converted to floating* | 6.43 | % | 6.26 | % |
At December 31, | 2010 | 2009 | ||||||
---|---|---|---|---|---|---|---|---|
Nonregulated Businesses | ||||||||
Loans under credit agreements | 4.50 | % | 4.50 | % | ||||
Tax-exempt debt | 0.30 | % | 1.22 | % | ||||
Fixed-rate debt converted to floating * | 1.23 | % | 2.30 | % |
Common Stock
Share Repurchase Program
In October 2007, our board of directors approved a common share repurchase program for up to $1 billion of our outstanding common shares. Subsequent to this approval, on October 31, 2007, we entered into an accelerated share repurchase agreement with a financial institution to repurchase a total of $250.0 million, and, on November 2, 2007, we purchased 2,023,527 of outstanding shares of our common stock, which represents the minimum number of shares deliverable under the agreement, for a total of $187.5 million.
We account for the accelerated share repurchase agreement as two separate transactions: as shares of common stock acquired at cost and a forward contract indexed to our own common stock. We accounted for the shares of common stock repurchased in November as a reduction to common shareholders' equity at cost. We accounted for the forward contract as a component of common shareholders' equity at fair value, which totaled $62.5 million at inception. The forward contract was settled on January 23, 2008 based on a discount to the volume-weighted average trading price of our common stock during that period. As a result, the financial institution delivered 514,376 additional shares to us to complete the transaction.
The remainder of the common share repurchase program is expected to be executed over the next 24 months in a manner that preserves flexibility to pursue additional strategic investment opportunities.
Preference Stock
Each series of BGE preference stock has no voting power, except for the following:
Dividend Restrictions
Constellation Energy
Constellation Energy pays dividends on its common stock after its Board of Directors declares them. There are no contractual limitations on Constellation Energy paying common stock dividends, unless Constellation Energy elects to defer interest payments on the 8.625% Series A Junior Subordinated Debentures due June 15, 2063, and any deferred interest remains unpaid.
BGE
BGE pays dividends on its common stock after its Board of Directors declares them. However, pursuant to the order issued by the Maryland PSC on October 30, 2009 in connection with its approval of the transaction with EDF, BGE cannot pay dividends to Constellation Energy if (a) after the dividend payment, BGE's equity ratio would be below 48% as calculated pursuant to the Maryland PSC's ratemaking precedents or (b) BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade.
10Taxes
The components of income tax expense are as follows:
Year Ended December 31, | 2007 | 2006 | 2005 | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (Dollar amounts in millions) | |||||||||||
Income Taxes | ||||||||||||
Current | ||||||||||||
Federal | $ | 168.2 | $ | 246.3 | $ | 14.3 | ||||||
State | 40.6 | 37.2 | 32.7 | |||||||||
Current taxes charged to expense | 208.8 | 283.5 | 47.0 | |||||||||
Deferred | ||||||||||||
Federal | 184.7 | 50.7 | 107.9 | |||||||||
State | 41.5 | 23.7 | 16.1 | |||||||||
Deferred taxes charged to expense | 226.2 | 74.4 | 124.0 | |||||||||
Investment tax credit adjustments | (6.7 | ) | (6.9 | ) | (7.1 | ) | ||||||
Income taxes per Consolidated Statements of Income | $ | 428.3 | $ | 351.0 | $ | 163.9 | ||||||
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (Dollar amounts in millions) | |||||||||||
Income Taxes | ||||||||||||
Current | ||||||||||||
Federal | $ | (46.9 | ) | $ | 891.5 | $ | 2.8 | |||||
State | 102.0 | 260.4 | 48.1 | |||||||||
Current taxes charged to expense | 55.1 | 1,151.9 | 50.9 | |||||||||
Deferred | ||||||||||||
Federal | (521.4 | ) | 1,474.5 | (101.6 | ) | |||||||
State | (194.9 | ) | 372.5 | (21.2 | ) | |||||||
Deferred taxes (credited) charged to expense | (716.3 | ) | 1,847.0 | (122.8 | ) | |||||||
Investment tax credit adjustments | (4.5 | ) | (12.1 | ) | (6.4 | ) | ||||||
Income taxes per Consolidated Statements of Income (Loss) | $ | (665.7 | ) | $ | 2,986.8 | $ | (78.3 | ) | ||||
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:
Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes | |||||||||||||
Income from continuing opera- tions before income taxes (excluding BGE preference stock dividends) | $ | 1,263.9 | $ | 1,112.8 | $ | 713.0 | |||||||
Statutory federal income tax rate | 35% | 35% | 35% | ||||||||||
Income taxes computed at statu- tory federal rate | 442.4 | 389.5 | 249.5 | ||||||||||
Increases (decreases) in income taxes due to | |||||||||||||
Depreciation differences not nor- malized on regulated activities | 3.7 | 3.6 | 3.8 | ||||||||||
Amortization of deferred investment tax credits | (6.7 | ) | (6.9 | ) | (7.1 | ) | |||||||
Synthetic fuel tax credits flowed through to income | (166.2 | ) | (120.2 | ) | (114.9 | ) | |||||||
Estimated synthetic fuel tax credit phase-out | 110.3 | 44.3 | — | ||||||||||
State income taxes, net of fed- eral income tax benefit | 53.4 | 42.6 | 31.5 | ||||||||||
Merger-related transaction costs | — | (5.3 | ) | 5.3 | |||||||||
Other | (8.6 | ) | 3.4 | (4.2 | ) | ||||||||
Total income taxes | $ | 428.3 | $ | 351.0 | $ | 163.9 | |||||||
Effective income tax rate | 33.9% | 31.5% | 23.0% | ||||||||||
In 2007, the State of Maryland increased its corporate tax rate from 7% to 8.25% effective January 1, 2008. In accordance with SFAS No. 109,Accounting for Income Taxes, the impact from adjusting all existing deferred income tax assets and liabilities for the effect of changes in tax laws or rates should be included in operating results in the period that includes the enactment date. In 2007, we recognized a $0.7 million after-tax charge for the net impact of the changes in the Maryland tax rate on deferred income tax assets and liabilities, net of the related federal deferred income tax benefit. The impact to BGE is discussed below.
Current income taxes will begin to be recorded at the higher Maryland corporate income tax rate effective in 2008 and will be reflected in our ongoing operating results beginning on January 1, 2008.
Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes | |||||||||||||
(Loss) Income from continuing operations before income taxes | $ | (1,597.5 | ) | $ | 7,490.2 | $ | (1,396.7 | ) | |||||
Statutory federal income tax rate | 35 | % | 35 | % | 35 | % | |||||||
Income taxes computed at statutory federal rate | (559.1 | ) | 2,621.6 | (488.8 | ) | ||||||||
Increases (decreases) in income taxes due to | |||||||||||||
State income taxes, net of federal income tax benefit | (60.4 | ) | 411.0 | 17.3 | |||||||||
Merger-related transaction costs | — | (79.3 | ) | 416.2 | |||||||||
Interest expense on mandatorily redeemable preferred stock | — | 23.7 | 7.8 | ||||||||||
Qualified decommissioning impairment losses | — | 3.1 | (28.5 | ) | |||||||||
Amortization of deferred investment tax credits | (4.5 | ) | (12.1 | ) | (6.4 | ) | |||||||
Noncontrolling interest operating results | (13.1 | ) | (16.4 | ) | 6.0 | ||||||||
Nondeductible international losses | — | 19.2 | — | ||||||||||
Other | (28.6 | ) | 16.0 | (1.9 | ) | ||||||||
Total income taxes | $ | (665.7 | ) | $ | 2,986.8 | $ | (78.3 | ) | |||||
Effective income tax rate | 41.7 | % | 39.9 | % | 5.6 | % | |||||||
BGE's effective tax rate was 40.7%39.7% in 2007, 37.5%2010, 41.3% in 2006,2009, and 38.8%28.7% in 2005. The2008. In general, the primary difference between BGE's effective tax rate and the 35% statutory federal income tax rate is primarily relatedfor all years relates to Maryland corporate income taxes, net of the related federal income tax benefit. BGE's after-tax effective state rate of 7.6% for 2007 includes an adjustment of deferred income tax liabilities to reflect the November 19, 2007 enactment into law of a changeThe decrease in the Maryland corporate income tax rate, as discussed above. In 2006, BGE's effective tax rate includesin 2010 is primarily due to the benefitinclusion of merger-related costs incurreda loss on the sale of a noncontrolling interest in 2005pretax earnings in 2009 that were deductiblewas not included in 20062010 pretax earnings as a result of the terminationJanuary 2010 sale of the merger with FPL Group (0.5%) and a deduction for dividends paidthat interest. The increase in BGE's 2009 effective tax rate from 2008 is primarily due to higher taxable income. For 2008, BGE had lower taxable income related to the employee savings plan (0.5%).2008 Maryland settlement agreement, which increased the relative impact of favorable permanent tax adjustments on BGE's 2008 effective tax rate.
The major components of our net deferred income tax liability are as follows:
| Constellation Energy | BGE | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
At December 31, | 2007 | 2006 | 2007 | 2006 | ||||||||||
| (In millions) | |||||||||||||
Deferred Income Taxes | ||||||||||||||
Deferred tax liabilities | ||||||||||||||
Net property, plant and equipment | $ | 1,570.7 | $ | 1,539.1 | $ | 583.8 | $ | 524.2 | ||||||
Qualified nuclear decommissioning trust funds | 360.3 | 339.5 | — | — | ||||||||||
Regulatory assets, net | 312.0 | 203.3 | 312.0 | 203.3 | ||||||||||
Mark-to-market energy assets and liabilities, net | 217.8 | 154.7 | — | — | ||||||||||
Other | 122.6 | 185.1 | 12.2 | 72.7 | ||||||||||
Total deferred tax liabilities | 2,583.4 | 2,421.7 | 908.0 | 800.2 | ||||||||||
Deferred tax assets | ||||||||||||||
Asset retirement obligation | 368.3 | 384.6 | — | — | ||||||||||
Defined benefit obligations | 362.0 | 390.6 | 61.6 | 39.8 | ||||||||||
Financial investments and hedging instruments | 426.1 | 757.2 | — | — | ||||||||||
Deferred investment tax credits | 20.4 | 22.1 | 4.8 | 4.7 | ||||||||||
Other | 118.8 | 105.7 | 11.9 | 10.6 | ||||||||||
Total deferred tax assets | 1,295.6 | 1,660.2 | 78.3 | 55.1 | ||||||||||
Total deferred tax liability, net | 1,287.8 | 761.5 | 829.7 | 745.1 | ||||||||||
Less: Current portion of deferred tax (asset)/liability | (300.7 | ) | (674.3 | ) | 44.1 | 47.4 | ||||||||
Long-term portion of deferred tax liability, net | $ | 1,588.5 | $ | 1,435.8 | $ | 785.6 | $ | 697.7 | ||||||
| Constellation Energy | BGE | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
At December 31, | 2010 | 2009 | 2010 | 2009 | |||||||||||
| (In millions) | ||||||||||||||
Deferred Income Taxes | |||||||||||||||
Deferred tax liabilities | |||||||||||||||
Net property, plant and equipment | $ | 1,768.3 | $ | 1,189.5 | $ | 1,152.3 | $ | 920.1 | |||||||
Regulatory assets, net | 256.8 | 263.0 | 256.8 | 263.0 | |||||||||||
Derivative assets and liabilities, net | (34.1 | ) | 329.6 | — | — | ||||||||||
Investment in CENG | 1,044.3 | 2,114.7 | — | — | |||||||||||
Other | 12.1 | 6.2 | (80.0 | ) | (55.1 | ) | |||||||||
Total deferred tax liabilities | 3,047.4 | 3,903.0 | 1,329.1 | 1,128.0 | |||||||||||
Deferred tax assets | |||||||||||||||
Defined benefit obligations | 249.0 | 311.7 | (79.7 | ) | (23.7 | ) | |||||||||
Financial investments and hedging instruments | 111.4 | 337.0 | — | — | |||||||||||
Deferred investment tax credits | 10.9 | 13.0 | 3.2 | 3.8 | |||||||||||
Other | 129.8 | 163.7 | 20.6 | 71.5 | |||||||||||
Total deferred tax assets | 501.1 | 825.4 | (55.9 | ) | 51.6 | ||||||||||
Total deferred tax liability, net | 2,546.3 | 3,077.6 | 1,385.0 | 1,076.4 | |||||||||||
Less: Current portion of deferred tax liability/(asset) | 56.5 | (127.9 | ) | 30.1 | (11.2 | ) | |||||||||
Long-term portion of deferred tax liability, net | $ | 2,489.8 | $ | 3,205.5 | $ | 1,354.9 | $ | 1,087.6 | |||||||
Synthetic Fuel Tax Credits
Our merchant energy business has investments in facilities that manufacture solid synthetic fuel produced from coal as defined under the Internal Revenue Code (IRC) for which we can claim tax credits on our Federal income tax return through 2007. 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. The synthetic fuel process involves combining coal material with a chemical reagent to create a significant chemical change. A taxpayer may request a private letter ruling from the IRS to support its position that the synthetic fuel produced undergoes a significant chemical change and thus qualifies for synthetic fuel tax credits.
We own a minority ownership in four synthetic fuel facilities located in Virginia and West Virginia. These facilities have received private letter rulings from the IRS. In 2004, the IRS concluded its examination of the partnership that owns these facilities for the tax years 1998 through 2001 and the IRS did not disallow any of the previously recognized synthetic fuel credits.
We also have a 99% ownership in a South Carolina facility that produces synthetic fuel. We have received favorable private letter rulings from the IRS on the South Carolina facility. In 2006, the IRS concluded its examination of the partnership that owns the South Carolina facility for the 2003 and 2004 tax years and the IRS did not disallow any of the previously recognized synthetic fuel credits.
The IRC provides for a phase-out of synthetic fuel tax credits if average annual wellhead oil prices increase above certain levels. To determine the amount of the phase-out, we are required to compare average annual wellhead oil prices per barrel as published by the IRS (reference price) to a Gross National Product inflation adjusted oil price for the year, also published by the IRS. The reference price is determined based on wellhead prices for all domestic oil production as published by the Energy Information Administration (EIA). For 2007, we estimate the tax credit reduction would begin if the reference price exceeds approximately $56 per barrel and would be fully phased out if the reference price exceeds approximately $71 per barrel.
Based on monthly EIA published wellhead oil prices for the ten months ended October 31, 2007 and November and December NYMEX prices for light, sweet, crude oil (adjusted for the 2007 difference between EIA and NYMEX prices), we estimate a 70% tax credit phase-out in 2007. We recorded the effect of this phase-out estimate as a reduction in tax credits of $110.3 million during 2007.
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 the IRC, we cannot predict the timing or outcome of any future challenge by the IRS, legislative or regulatory action, or the ultimate impact of such events on the synthetic fuel tax credits that we have claimed to date, but the impact could be material to our financial results.
Income Tax Audits
We file income tax returns in the United States and foreign jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for the years before 2002.2005. In February 2008,2009, the IRS completedexpanded its examinationcurrent audit of our consolidated federal income tax returns for the tax years 20022005 through 2004. We intend2007 to file an administrative appeal of certain audit adjustments made byinclude the IRS as part of its examination.2008 tax year. Although the final outcome of the 2002-20042005-2008 IRS audit and future tax audits is uncertain, we believe that adequate provisions for income taxes have been made for potential liabilities resulting from such matters.
Unrecognized Tax Benefits
The following table summarizes our total unrecognized tax benefits at January 1, 2007, the date of adoption of FIN 48:
At January 1, 2007 | | ||
---|---|---|---|
| (In millions) | ||
Total liabilities reflected in our balance sheet for unrecognized tax benefits of $56.7 million less $12.1 million of interest and penalties | $ | 44.6 | |
Other unrecognized tax benefits not reflected in our balance sheet | 59.4 | ||
Total unrecognized tax benefits | $ | 104.0 | |
The adoption of FIN 48 did not have a material impact on BGE's financial results.
Other unrecognized tax benefits relate to outstanding federal and state refund claims for which no tax benefit was previously provided in our financial statements because the claims do not meet the "more-likely-than-not" threshold. Included in this amount is $52.0 million of refund claims that have been disallowed by the applicable tax authorities for which we assess the probability of tax benefit recognition to be remote. We discuss the adoption of FIN 48 in more detail inNote 1.
The following table summarizes the change in unrecognized tax benefits during 20072010 and 2009 and our total unrecognized tax benefits at December 31, 2007:2010 and 2009:
At December 31, 2007 | | |||
---|---|---|---|---|
| (In millions) | |||
Total unrecognized tax benefits, January 1, 2007 | $ | 104.0 | ||
Increases in tax positions related to the current year | 13.3 | |||
Increases in tax positions related to prior years | 3.8 | |||
Reductions in tax positions related to prior years | (6.0 | ) | ||
Reductions in tax positions as a result of a lapse of the applicable statute of limitations | (0.6 | ) | ||
Total unrecognized tax benefits, December 31, 2007 (1) | $ | 114.5 | ||
| 2010 | 2009 | |||||
---|---|---|---|---|---|---|---|
| (In millions) | ||||||
Total unrecognized tax benefits, January 1 | $ | 312.5 | $ | 189.7 | |||
Increases in tax positions related to the current year | 5.9 | 101.5 | |||||
Increases in tax positions related to prior years | 26.0 | 148.4 | |||||
Reductions in tax positions related to prior years | (104.0 | ) | (126.3 | ) | |||
Reductions in tax positions as a result of a lapse of the applicable statute of limitations | (0.6 | ) | (0.8 | ) | |||
Total unrecognized tax benefits, December 31 (1) | $ | 239.8 | $ | 312.5 | |||
Increases in current and prior year tax positions and reductions in prior year tax positions are primarily due toIf the total amount of unrecognized tax benefits for repair deductions measured at amounts consistent with proposed IRS adjustments for prior years. There was no significant change inof $239.8 million were ultimately realized, our income tax expense would decrease by approximately $167 million. However, the $167 million includes state tax refund claims of $55.9 million that have been disallowed by tax authorities and are subject to appeals.
132
It is reasonably possible that unrecognized tax benefits could decrease within the next year by approximately $72.9 million as a result of 2007 activity.an expected settlement with the IRS regarding BGE's change of accounting method for tax purposes with respect to certain transmission and distribution expenditures. This decrease is not expected to have a material impact on BGE's financial condition or results of operation.
Interest and penalties recorded in our Consolidated Statements of Income (Loss) as tax (benefit) expense relating to liabilities for unrecognized tax benefits were $4.7 millionas follows:
| For the Year Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | 2008 | |||||||
| (In millions) | |||||||||
Interest and penalties recorded as tax (benefit) expense | $ | (6.3 | ) | $ | 12.8 | $ | (0.4 | ) | ||
BGE's portion of interest and penalties was immaterial for the year ended December 31, 2007. As a result, accruedall years.
Accrued interest and penalties recognized in our Consolidated Balance Sheets increased from $12.1were $16.8 million, at January 1, 2007 to $16.8of which BGE's portion was $3.8 million at December 31, 2007.
If the total amount2010, and $23.1 million, of unrecognized tax benefits of $114.5which BGE's portion was $1.6 million, as ofat December 31, 2007 were ultimately realized, our income tax expense would decrease by approximately $71 million. The $71 million includes the $52 million2009.
133
Table of disallowed refund claims discussed above.Contents
In 2007, the IRS proposed certain adjustments to our 2002-2004 deductions for repairs and casualty losses. We do not anticipate the adjustments, if any, would result in a material impact on our financial results. However, we anticipate that it is reasonably possible that we will make an additional payment in the range of $20 to $25 million by December 31, 2008, which will reduce our liabilities for unrecognized tax benefits.
11Leases
There are two types of leases—operating and capital. Capital leases qualify as sales or purchases of property and are reported in our Consolidated Balance Sheets. Our capital leases are not material in amount. All other leases are operating leases and are reported in our Consolidated Statements of Income.Income (Loss). We expense all lease payments associated with our regulated business. Lease expense and future minimum payments for long-term, noncancelable, operating leases are not material to BGE's financial results. We present information about our operating leases below.
Outgoing Lease Payments
We, as lessee, lease certain facilities and equipment. The lease agreements expire on various dates and have various renewal options. We also enter into certain power purchase agreements which are accounted for as operating leases. We classify power purchase agreements as leases if the agreement in substance provides us the ability to control the use of the underlying power generating facilities.
Under these agreements, we are required to make fixed capacity payments, as well as variable payments based on actual output of the plants. We record these payments as "Fuel and purchased energy expenses" in our Consolidated Statements of Income.Income (Loss). We exclude from our future minimum lease payments table the variable payments related to the output of the plant due to the contingency associated with these payments.
WeThrough June 2009, we also enterentered into time charter purchase agreements which entitleentitled us to the use of dry bulk freight vessels in the management of our global coal and logistics services. Certain of these contracts must be accounted for as leases. During 2007, we entered intoOur time charter leases withhave terms ranging in duration from 1 to 60 months. These arrangements do not include provisions for material rent increases and do not have provisions for rent holidays, contingent rentals or other incentives. In 2007,2010, 2009, and 2008, we recognized aggregate lease expense of approximately $535$11 million, $145 million and $477 million, respectively, related to 6512, 31 and 49 dry bulk freight vessels, respectively, hired under time charter arrangements. The average term of these arrangements is approximately 42-3 months. We record the payments as "Fuel and purchased energy expenses" in our Consolidated Statements of Income.Income (Loss).
We recognized expense related to our operating leases as follows:
| Fuel and purchased energy expenses | Operating expenses | Total | ||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
2007 | $ | 758.7 | $ | 28.2 | $ | 786.9 | |||
2006 | 162.6 | 24.7 | 187.3 | ||||||
2005 | 103.2 | 24.8 | 128.0 |
| Fuel and purchased energy expenses | Operating expenses | Total | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
2010 | $ | 227.9 | $ | 30.2 | $ | 258.1 | ||||
2009 | 385.6 | 37.2 | 422.8 | |||||||
2008 | 664.8 | 38.0 | 702.8 |
At December 31, 2007,2010, we owed future minimum payments for long-term, noncancelable, operating leases as follows:
Year | Power Purchase Agreements | Other | Total | ||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
2008 | $ | 479.3 | $ | 26.3 | $ | 505.6 | |||
2009 | 235.8 | 24.6 | 260.4 | ||||||
2010 | 171.1 | 23.1 | 194.2 | ||||||
2011 | 210.4 | 22.1 | 232.5 | ||||||
2012 | 219.0 | 19.2 | 238.2 | ||||||
Thereafter | 782.8 | 109.7 | 892.5 | ||||||
Total future minimum lease payments | $ | 2,098.4 | $ | 225.0 | $ | 2,323.4 | |||
Year | Power Purchase Agreements | Other | Total | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
2011 | $ | 171.3 | $ | 30.8 | $ | 202.1 | ||||
2012 | 145.6 | 26.8 | 172.4 | |||||||
2013 | 130.8 | 24.8 | 155.6 | |||||||
2014 | 126.0 | 22.5 | 148.5 | |||||||
2015 | 126.6 | 26.3 | 152.9 | |||||||
Thereafter | 72.6 | 35.7 | 108.3 | |||||||
Total future minimum lease payments | $ | 772.9 | $ | 166.9 | $ | 939.8 | ||||
Sub-Lease Arrangements
We provide time charters of dry bulk freight vessels as part of the logistical services provided to our global customers that qualify as sub-leases of our time charter purchase contracts. In 2007,2010, 2009, and 2008, we recorded sub-lease income of approximately $214$25 million, $114 million and $289 million, respectively, related to our time charter sub-leases. We did not have any material sub-lease income for 2006 or 2005. We record sub-lease income as part of "Nonregulated revenues" in our Consolidated Statements of Income.Income (Loss). As of December 31, 2007,2010, the future minimum rentals to be received for these time charters isare shown below:
Year | Time Charter Sub-Leases | ||
---|---|---|---|
| (In millions) | ||
2008 | $ | 109.2 | |
2009 | 30.7 | ||
2010 | — | ||
2011 | — | ||
2012 | — | ||
Thereafter | — | ||
Total future minimum lease rentals | $ | 139.9 | |
Year | Time Charter Sub-Leases | |||
---|---|---|---|---|
| (In millions) | |||
2011 | $ | 22.4 | ||
2012 | 24.2 | |||
2013 | 17.5 | |||
2014 | 9.8 | |||
2015 | 9.8 | |||
Thereafter | 28.6 | |||
Total future minimum lease rentals | $ | 112.3 | ||
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12Commitments, Guarantees, and Contingencies
Commitments
We have made substantial commitments in connection with our merchant energy,Generation, NewEnergy, and regulated electric and gas, and other nonregulated businesses. These commitments relate to:
Our merchant energy business entersGeneration and NewEnergy businesses enter into various long-term contracts for the procurement and delivery of fuels to supply our generating plant requirements. In most cases, our contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. These contracts expire in various years between 20082011 and 2020.2018. In addition, our merchant energyNewEnergy business enters into long-term contracts for the capacity and transmission rights for the delivery of energy to meet our physical obligations to our customers. These contracts expire in various years between 20082011 and 2019.2030.
Our merchant energy businessGeneration and NewEnergy businesses also hashave committed to long-term service agreements and other purchase commitments for our plants.
Our regulated electric business enters into various long-term contracts with differing terms for the procurement of electricity. TheseAs of December 31, 2010, these contracts representing approximately 66% of ourexpire between 2011 and 2013 and represent BGE's estimated requirements expire between 2008to serve residential and 2010. As discussed inNote 1, thesmall commercial customers as follows:
Contract Duration | Percentage of Estimated Requirements | |||
---|---|---|---|---|
From January 1, 2011 to September 2011 | 100 | % | ||
From October 2011 to May 2012 | 75 | |||
From June 2012 to September 2012 | 50 | |||
From October 2012 to May 2013 | 25 |
The cost of power under these contracts is fully recoverable and therefore is excluded fromunder the table later in this Note.Provider of Last Resort agreement reached with the Maryland PSC.
Our regulated gas business enters into various long-term contracts for the procurement, transportation, and storage of gas. Our regulated gas business has gas procurement contracts that expire in 2011, and transportation and storage contracts that expire between 20082012 and 2028. These2027. The cost of gas under these contracts areis recoverable under BGE's gas cost adjustment clause discussed inNote 1, and therefore are excluded from the table later in this Note.
Our other nonregulated businesses have committed to gas purchases and to contributions of 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 December 31, 2007,2010, we estimate our future obligations to be as follows:
| Payments | | ||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2008 | 2009- 2010 | 2011- 2012 | Thereafter | Total | |||||||||||
| (In millions) | | ||||||||||||||
Merchant Energy: | ||||||||||||||||
Purchased capacity and energy | $ | 425.2 | $ | 489.6 | $ | 213.8 | $ | 276.4 | $ | 1,405.0 | ||||||
Fuel and transportation | 1,825.1 | 1,503.5 | 649.7 | 918.9 | 4,897.2 | |||||||||||
Long-term service agreements, capital, and other | 146.8 | 12.6 | 6.8 | 17.8 | 184.0 | |||||||||||
Total merchant energy | 2,397.1 | 2,005.7 | 870.3 | 1,213.1 | 6,486.2 | |||||||||||
Corporate and Other: | ||||||||||||||||
Long-term service agreements, capital, and other | 50.5 | 5.7 | 0.7 | — | 56.9 | |||||||||||
Regulated: | ||||||||||||||||
Purchase obligations and other | 61.8 | 23.5 | 12.8 | 1.5 | 99.6 | |||||||||||
Total future obligations | $ | 2,509.4 | $ | 2,034.9 | $ | 883.8 | $ | 1,214.6 | $ | 6,642.7 | ||||||
| Payments | | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2011 | 2012- 2013 | 2014- 2015 | Thereafter | Total | ||||||||||||
| (In millions) | | |||||||||||||||
Competitive Businesses: | |||||||||||||||||
Purchased capacity and energy | $ | 430.6 | $ | 503.0 | $ | 164.3 | $ | 263.6 | $ | 1,361.5 | |||||||
Purchased energy from CENG (1) | 488.4 | 1,761.2 | 1,735.5 | 3,985.1 | |||||||||||||
Fuel and transportation | 535.7 | 449.9 | 250.2 | 176.0 | 1,411.8 | ||||||||||||
Long-term service agreements, capital, and other | 6.6 | 11.5 | 7.4 | 5.4 | 30.9 | ||||||||||||
Total competitive businesses | 1,461.3 | 2,725.6 | 2,157.4 | 445.0 | 6,789.3 | ||||||||||||
Corporate and Other: | |||||||||||||||||
Long-term service agreements, capital, and other | 22.5 | 11.6 | 0.1 | — | 34.2 | ||||||||||||
Regulated: | |||||||||||||||||
Purchase obligations and other | 23.9 | 6.9 | — | — | 30.8 | ||||||||||||
Total future obligations | $ | 1,507.7 | $ | 2,744.1 | $ | 2,157.5 | $ | 445.0 | $ | 6,854.3 | |||||||
Long-Term Power Sales Contracts
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 2019 and provide for the sale of energy to electricityelectric distribution utilities and certain retail customers. Our power sales contracts associated with our power plants extend for terms into 20142016 and provide for the sale of all or a portion of the actual output of certain of our power plants. AllSubstantially all long-term contracts were executed at pricing that approximated market rates, including profit margin, at the time of execution.
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Guarantees
Our guarantees do not represent incremental Constellation Energy Group obligations; rather they primarily represent parental guarantees of subsidiary obligations. The following table summarizes the maximum exposure by guarantor based on the stated limit of our outstanding guarantees at December 31, 2007:guarantees:
At December 31, 2007 | Stated Limit | ||
---|---|---|---|
| (In millions) | ||
Competitive supply guarantees | $ | 13,538.0 | |
Nuclear guarantees | 807.8 | ||
BGE guarantees | 263.3 | ||
Other non-regulated guarantees | 105.3 | ||
Power project guarantees | 47.2 | ||
Total guarantees | $ | 14,761.6 | |
At December 31, 2010 | Stated Limit | |||
---|---|---|---|---|
| (In billions) | |||
Constellation Energy guarantees | $ | 9.1 | ||
BGE guarantees | 0.3 | |||
Total guarantees | $ | 9.4 | ||
At December 31, 2007,2010, Constellation Energy had a total of $14,761.6 million$9.4 billion in guarantees in outstanding related to loans, credit facilities, and contractual performance of certain of its subsidiaries as described below.
Contingencies
Litigation
In the normal course of business, we are involved in various legal proceedings. We discuss the significant matters below.
Note 9Securities Class Action.
Three federal securities class action lawsuits have been filed in the United States District Courts for the Southern District of certain debtNew York and the District of Safe Harbor Water Power Corporation, an unconsolidated investment. At December 31, 2007, Safe Harbor Water Power Corporation had outstanding debt of $20.0 million.Maryland between September 2008 and November 2008. The maximum amount of BGE's guarantee is $13.3 million.
The Southern District of New York granted the defendants' motion to transfer the two securities class actions filed there to the District of Maryland, and the actions have since been transferred for coordination with the securities class action filed there. On June 18, 2009, the court appointed a lead plaintiff, who filed a consolidated amended complaint on September 17, 2009. On November 17, 2009, the defendants moved to dismiss the consolidated amended complaint in its entirety. On August 13, 2010, the District Court of Maryland issued a ruling on the motion to dismiss, holding that the plaintiffs failed to state a claim with respect to the claims of the common shareholders under the Securities Act of 1934 and restricting the suit to those persons who purchased debentures in the June 2008 offering. We are unable at this time to determine the ultimate outcome of the securities class actions or their possible effect on our, or BGE's financial results.
Mercury
Since September 2002, BGE, Constellation Energy, and several other nonregulated businesses primarilydefendants have been involved in numerous actions filed in the Circuit Court for loansBaltimore 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 performance bondsConstellation Energy, approximately 11 other defendants, consisting of pharmaceutical companies, manufacturers of vaccines, and manufacturers of Thimerosal have been sued. Approximately 70 cases, involving claims related to approximately 132 children, have been filed to date, with each claimant seeking $20 million in compensatory damages, plus punitive damages, from us.
The claims against BGE and Constellation Energy have been dismissed in all of the cases either with prejudice based on rulings by the Court or without prejudice based on voluntary dismissals by the plaintiffs' counsel. 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.
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Asbestos
Since 1993, BGE and certain Constellation Energy subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE and Constellation Energy knew of and exposed individuals to an asbestos hazard. In addition to BGE and Constellation Energy, numerous other parties are defendants in these cases.
Approximately 485 individuals who were never employees of BGE or Constellation Energy have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third party claims brought by other defendants may also be filed against BGE and Constellation Energy in these actions. To date, most asbestos claims which $25.0 million was recorded inhave been resolved have been dismissed or resolved without any payment and a small minority have been resolved for amounts that were not material to our Consolidated Balance Sheetsfinancial results.
BGE and Constellation Energy do not know the specific facts necessary to estimate their potential liability for these claims. The specific facts we do not know include:
We believe it is unlikely thatUntil the relevant facts are determined, we wouldare 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 required to perform or incur any losses associated with guarantees of our subsidiaries' obligations.material.
Contingencies
Revenue Sufficiency Guarantee Costs
During 2006, the FERC issued orders finding that the Midwest Independent System Operator (MISO) violated its tariff by incorrectly allocating revenue sufficiency guarantee (RSG) charges among market participants. In March 2007, after rejecting a methodology proposal from MISO, FERC ordered MISO to reallocate RSG costs based on its existing tariff back to the date of FERC's original order (April 2006). Based on this FERC order, we recorded an immaterial liability during 2007 in our Consolidated Balance Sheets for our share of the RSG charges. This liability was subsequently settled with MISO later in 2007.
Environmental Matters
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 current estimated costs for, and current status of, each site is described in more detail below.
68th Street Dump
In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, 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 and entered into consent order negotiations with the EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the EPA and 19 of the potentially responsible parties, including BGE, with respect to investigation of the site became effective. The settlement requires the potentially responsible parties, over the course of several years, to identify contamination at the site and recommend clean-up options. BGE is fully indemnified by a wholly-ownedwholly owned subsidiary of Constellation Energy for most of the costs related to this settlement as well as anyand clean-up costs.of the site. The potential range of clean-up costs will not be known until the investigation is closer to completion. However, those costs could havecompletion, which is expected in early 2011. The completed investigation will provide a material effect on our financial results.
Kanerange of remediation alternatives to the EPA, and Lombard
Thethe EPA issued its record of decision for the Kane and Lombard Drum site located in Baltimore, Maryland on September 30, 2003, which specified the clean-up plan for the site, consisting of enhanced reductive dechlorination, a soil management plan, and institutional controls. An EPA order requiring cleanupis expected to select one of the sitealternatives by 18the end of 2011. In addition, the allocation of the costs among the potentially responsible parties including Constellation Energy, became effective in November 2006.is not yet known. The EPA estimates that total clean-up costs will be approximately $7 million. Our share of site-related costs will be 11.1% of the total. We recorded a liability in our Consolidated Balance Sheets for our share of the clean-up costs that we believe is probable.
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 remedial action plans and cost modeling performed in late 2006, BGE estimates its probable clean-up costs will total $43 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 costsincur could exceed the amount BGE has recognized by approximately $3 million. Through December 31, 2007, BGE has spent approximately $41 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.
Air Quality
In late July 2005, we received two NoticesJanuary 2009, the EPA issued a notice of Violation (NOVs) fromviolation (NOV) to a subsidiary of Constellation Energy, as well as the Placer County Air Pollution Control District, Placer County California (District) alleging thatother owners and the Rio Bravo Rocklin facility locatedoperator of the Keystone coal-fired power plant in Lincoln, California had violated certain District air emission regulations.Shelocta, Pennsylvania. We havehold a combined 50% ownership20.99% interest in the partnership which ownsKeystone plant. The NOV alleges that the Rio Bravo Rocklin facility.plant performed various capital projects beginning in 1984 without complying with the new source review permitting requirements of the Clean Air Act. The NOVs allege a total of 38EPA also contends that the alleged failure to comply with those requirements are continuing violations between January 2003 and March 2005 of eitherunder the facility'splant's air permit or federal, state, and county air emission standards related to nitrogen oxide, carbon monoxide, and particulate emissions, as well as violations of certain monitoring and reporting requirements during that time period.permits. The maximumEPA could seek civil penalties under the Clean Air Act for the alleged violations range from $10,000 to $40,000 per violation. Managementviolations.
The owners and operator of the Rio Bravo Rocklin facility is currently discussingKeystone plant are investigating the allegations and have entered into discussions with the EPA. We believe there are meritorious defenses to the allegations contained in the NOVs with District representatives. ItNOV. However, we cannot predict the outcome of this proceeding and it is not possible to determine theour actual liability, if any, of the partnership that owns the Rio Bravo Rocklin facility.
In May 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Environment to resolve alleged violations of air quality opacity standards at three fossil fuel plants in Maryland. The consent decree requires the subsidiary to pay a $100,000 penalty, provide $100,000 to a supplemental environmental project, and install technology to control emissions from those plants.this time.
Water Quality
In October 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Environment relating to groundwater contamination at a third party facility that was licensed to accept fly ash, a byproduct generated by our coal-fired plants. The consent decree requires the payment of a $1.0 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. We recorded a liability in our Consolidated Balance Sheets of approximately $5$10.6 million, which includes the $1 million penalty and our estimate of probable costs to remediate contamination, replace drinking water supplies, and monitor groundwater conditions.conditions, and otherwise comply with the consent decree. We have paid approximately $6.6 million of these costs as of December 31, 2010, resulting in a remaining liability at December 31, 2010 of $4.0 million. We estimate that it is reasonably possible that we could incur additional costs of up to approximately $10 million more than the liability that we accrued.
InInvestment in CENG
On November 2007,6, 2009, we completed the sale of a class action complaint was filed49.99% membership interest in Baltimore City Circuit Court alleging thatCENG to EDF. As a result of the subsidiary's ash placement operations at the third party site damaged surrounding properties. The complaint seeks injunctive and remedial relief relating to the alleged contamination and unspecified damages. We cannot predict the timing, or outcome, of this proceeding.
Litigation
In the normal course of business,sale, we now hold a 50.01% interest in CENG. As a 50.01% owner in CENG, we are involved in various legal proceedings. We discusssubject to certain capital contribution requirements, which may be greater than the significant matters below.
Challenges to the Illinois Auction
In March 2007, the Illinois Attorney General filed a complaint at FERC against the wholesale suppliers, including our wholesale marketing, risk managementamount planned and, trading operation, that were successful bidders in the recent Illinois auction. The complaint alleged that the rates resulting from the auction were not "just and reasonable" and requested that FERC commence a proceeding to determine if the rates were just and reasonable and to investigate evidence of price manipulation. In July 2007, the Illinois legislature approved comprehensive legislation to address several energy issues in the state. This legislation has been signed into law by the Governor of Illinois, and the Attorney General's claims have been dismissed.
In addition, two class action complaints were filed in Illinois state court against these wholesale suppliers alleging that they engaged in deceptive practices, including colluding in setting prices and actual price fixing. The complaints requested unspecified damages in an amount to be proven at trial. These complaints were moved to federal court and on December 21, 2007 the federal court dismissed the actions without prejudice to the right of the plaintiffs to pursue claims at the FERC or at the Illinois Commerce Commission.
We believe we have meritorious defenses to any claims challenging our conduct in the auction and intend to defend against any such claims vigorously. However, we cannot predict the timing, or outcome, of any such claims, or their possible effect on our financial results.
Mercury
Since 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, involving claims related to
approximately 132 children, have been filed to date, with each claimant seeking $20 million in compensatory damages, plus punitive damages, from us.
In rulings applicable to all but three of the cases, involving claims related to approximately 47 children, the Circuit Court for Baltimore City dismissed with prejudice all claims against BGE and Constellation Energy. 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 remaining actions vigorously. However, we cannot predict the timing, or outcome, of these cases, or their possible effect on our, or BGE's, financial results.
Asbestos
Since 1993, BGE and certain Constellation Energy subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE and Constellation Energy knew of and exposed individuals to an asbestos hazard. In addition to BGE and Constellation Energy, numerous other parties are defendants in these cases.
Approximately 538 individuals who were never employees of BGE or Constellation Energy have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and Constellation Energy in these actions. To date, most asbestos claims against us have been dismissed or resolved without any payment and a small minority have been resolved for amounts that were not material to our financial results. The remaining claims are currently pending in state courts in Maryland and Pennsylvania.
BGE and Constellation Energy do 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 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.
Storage of Spent Nuclear Fuel
The Nuclear Waste Policy Act of 1982 (NWPA) required the federal government through the Department of Energy (DOE), to develop a repository for, and disposal of, spent nuclear fuel and high-level radioactive waste. The NWPA and our contracts with the DOE required the DOE to begin taking possession of spent nuclear fuel generated by nuclear generating units no later than January 31, 1998. The DOE has stated that it will not meet that obligation until 2017 at the earliest.
This delay has required that we undertake additional actions related to on-site fuel storage at Calvert Cliffs and Nine Mile Point, including the installation of on-site dry fuel storage capacity at Calvert Cliffs. In January 2004, we filed a complaint against the federal government in the United States Court of Federal Claims seeking to recover damages caused by the DOE's failure to meet its contractual obligation to begin disposing of spent nuclear fuel by January 31, 1998. The case is currently stayed, pending litigation in other related cases.
In connection with our purchase of Ginna, all of Rochester Gas & Electric Corporation's (RG&E) rights and obligations related to recovery of damages for DOE's failure to meet its contractual obligations were assigned to us. However, we have an obligation to reimburse RG&E for up to $10 million in recovered damages for such claims.
Nuclear Insurance
We maintain nuclear insurance coverage for Calvert Cliffs, Nine Mile Point, and Ginna in four program areas: liability, worker radiation, property, and accidental outage. These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear, and war.
In November 2002, the President signed into law the Terrorism Risk Insurance Act ("TRIA") of 2002, which was extended by the Terrorism Risk Insurance Extension Act of 2005 and the Terrorism Risk Insurance Program Reauthorization Act of 2007. Under the TRIA, property and casualty insurance companies are required to offer insurance for losses resulting from Certified acts of terrorism. Certified acts of terrorism are determined by the Secretary of the Treasury, in concurrence with the Secretary of State and Attorney General, and primarily are based upon the occurrence of significant acts of terrorism that intimidate the civilian population of the United States or attempt to influence policy or affect the conduct of the United States Government. Our nuclear liability, nuclear property and accidental outage insurance programs, as discussed later in this section, provide coverage for Certified acts of terrorism.
If there were an accident or an extended outage at any unit of Calvert Cliffs, Nine Mile Point or Ginna, ittherefore, could have a substantialan adverse impact on our financial results.
In addition, if the fair value of our investment in CENG declines to a level below our carrying value and the decline is considered other-than-temporary, we may write down the
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investment to fair value, which would adversely affect our financial results. During 2010, we recorded an impairment on our investment in CENG. We discuss this impairment charge in more detail inNote 2.
We are also exposed to the same risks to which CENG is exposed. CENG owns and operates three nuclear generating facilities and is exposed to risks associated with operating these facilities and the risks of a nuclear accident.
Operating Risks
The operation of nuclear generating facilities involve routine risks, including,
Nuclear Liability InsuranceAccidents
Pursuant to the Price-Anderson Act, we areCENG is required to insure itself against public liability claims resulting from nuclear incidents to the full limit of public liability. This limit of liability consists of the maximum available commercial insurance of $300$375 million and mandatory participation in an industry-wide retrospective premium assessment program. The retrospective premium assessment is $100.6$117.5 million per reactor, per incident, increasing the total amount of insurance for public liability to approximately $10.8$12.6 billion. Under the retrospective assessment program, weCENG can be assessed up to $503$587.5 million per incident at any commercial reactor in the country, payable at no more than $75$87.5 million per incident per year. This assessment also appliesIn the event of a nuclear accident, the cost of property damage and other expenses incurred may exceed CENG's insurance coverage. As a result, uninsured losses or the payment of retrospective insurance premiums could each have a significant adverse impact to CENG's, and therefore, our financial results as a 50.01% owner in
excess CENG. Each of our worker radiation claims insuranceConstellation Energy and is subject to inflation and state premium taxes. In addition,EDF has guaranteed the U.S. Congress could impose additional revenue-raising measures to pay claims.
Worker Radiation Claims Insurance
We participate in the American Nuclear Insurers Master Worker Program that provides coverage for worker tort claims filed for radiation injuries. Effective January 1, 1998, this program was modified to provide coverage to all workers whose nuclear-related employment began on or after the commencement dateobligations of reactor operations. Waiving the right to make additional claims under the old policy was a condition for coverage under the new policy. We describe the old and new policies below:
The sellers of Nine Mile Point retain the liabilities for existing and potential claims that occurred prior to November 7, 2001. In addition, the Long Island Power Authority, which continues to own 18% of Unit 2 at Nine Mile Point, is obligated to assume its pro rata share of any liabilities for retrospective premiums and other premium assessments. RG&E, the seller of Ginna, retains the liabilities for existing and potential claims that occurred prior to June 10, 2004. If claims under these policies exceed the coverage limits, the provisions of the Price-Anderson Act would apply.their respective membership interests.
Nuclear Property and Accidental Outage Insurance
Our policies provide $500 millionCENG's plants are provided property and accidental outage insurance through Nuclear Electric Insurance Limited (NEIL). Prior to July 1, 2010, CENG was the member-insured of NEIL. Effective July 1, 2010, Constellation Energy and EDF became the members-insured through their ownership interest in primary coverage at each nuclear plant—Calvert Cliffs, Nine Mile Point,CENG. As the members-insured, Constellation Energy and Ginna. In addition, we maintain $1.77 billion of excess coverage at Ginna and $2.25 billion in excess coverageEDF have assigned the loss benefits under a blanket excess program offered by the industry mutual insurer at both Calvert Cliffs and Nine Mile Point. Under the blanket excess policy, Calvert Cliffs and Nine Mile Point share $1.0 billion of the total $2.25 billion of excess property coverage. Therefore, in the unlikely event of two full limit property damage losses at Calvert Cliffs and Nine Mile Point, we would recover $4.5 billion instead of $5.5 billion. This coverage currently is purchased through the industry mutual insurance company. If accidents atto CENG's plants, with CENG named as an additional insured by the mutual insurance company cause a shortfall of funds, all policyholders could be assessed, with our share being up to $97.4 million.
Losses resulting from non-certified acts of terrorism are covered as a common occurrence, meaning that if non-certified terrorist acts occur against one or more commercial nuclear power plants insured by our nuclear property insurance company within a 12-month period, they would be treated as one event and the owners of the plants where the acts occurred would share one full limit of liability (currently $3.24 billion).party.
Accidental Nuclear Outage Insurance
Our policies provide indemnification on a weekly basis for losses resulting from an accidental outage of a nuclear unit. Coverage begins after a 12-week deductible period and continues at 100% of the weekly indemnity limit for 52 weeks and then 80% of the weekly indemnity limit for the next 110 weeks. Our coverage is up to $490.0 million per unit at Calvert Cliffs and Ginna, $420.0 million for Unit 1 of Nine Mile Point, and $401.8 million for Unit 2 of Nine Mile Point. This amount can be reduced by up to $98.0 million per unit at Calvert Cliffs and $84.0 million for Nine Mile Point if an outage of more than one unit is caused by a single insured physical damage loss.
Non-Nuclear Property Insurance
Our conventional property insurance provides coverage of $1.0 billion per occurrence for Certified acts of terrorism as defined under TRIA,the Terrorism Risk Insurance Extension Act of 2005 and the Terrorism Risk Insurance Program Reauthorization Act of 2007. Our conventional property insurance program also provides coverage for non-certified acts of terrorism up to an annual aggregate limit of $1.0 billion. If a terrorist act occurs at any of our facilities, it could have a significant adverse impact on our financial results.
13Hedging ActivitiesDerivatives and Fair Value of Financial InstrumentsMeasurements
SFAS No. 133 Hedging ActivitiesUse of Derivative Instruments
WeNature of Our Business and Associated Risks
Our business activities primarily include our Generation, NewEnergy, regulated electric and gas businesses. Our Generation and NewEnergy businesses include:
Our regulated electric and gas businesses engage in electricity and gas transmission and distribution activities in Central Maryland at prices set by the Maryland PSC that are exposedgenerally designed to recover our costs, including purchased fuel and energy. Substantially all of our risk management activities involving derivatives occur outside our regulated businesses.
In carrying out our competitive business activities, we purchase and sell power, fuel, and other energy-related commodities in competitive markets. These activities expose us to significant risks, including market risk includingfrom price volatility for energy commodities and the credit risks of counterparties with which we enter into contracts. The sources of these risks include, but are not limited to, the following:
Objectives and Strategies for Using Derivatives
Risk Management Activities
To lower our exposure to the risk of unfavorable fluctuations in commodity prices, interest rates, and the impact of market fluctuationsforeign currency rates, we routinely enter into derivative contracts, such as fixed-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the price and transportation costs of electricity, natural gas, and other commodities.
Commodity Prices
Merchant Energy Business
Our merchant energy business uses a variety of derivative and non-derivative instruments to manage the commodity price risk of our competitive supply activities and our electric generation facilities, including power sales, fuel and energy purchases, gas purchasedover-the-counter markets or on exchanges, for resale, emission credits, weather risk, freight and the market risk of outages. In order to manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and purchases of fuel and energy.hedging purposes. The objectives for entering into such hedgeshedging transactions primarily include:
Non-Risk Management Activities
In addition to the use of derivatives for risk management purposes, we also enter into derivative contracts for trading purposes primarily for:
Accounting for Derivative Instruments
The accounting requirements for derivatives require recognition of all qualifying derivative instruments on the balance sheet at fair value as either assets or liabilities.
Accounting Designation
We must evaluate new and existing transactions and agreements to determine whether they are derivatives, for which there are several possible accounting treatments. Mark-to-market is required as the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria, both at the time of designation and on an ongoing basis. The permissible accounting treatments include:
We discuss our accounting policies for derivatives and hedging activities and their impacts on our financial statements inNote 1.
NPNS
We elect NPNS accounting for derivative contracts that provide for the purchase or sale of a physical commodity that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Once we elect NPNS classification for a portiongiven contract, we cannot subsequently change the election and treat the contract as a derivative using mark-to-market or hedge accounting.
Cash Flow Hedging
We generally elect cash flow hedge accounting for most of anticipated salesthe derivatives that we use to hedge market price risk for our physical energy delivery activities because hedge accounting more closely aligns the timing of earnings recognition and cash flows for the underlying business activities. Management monitors the
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potential impacts of commodity price changes and, where appropriate, may enter into or purchases of freight and coal.
The portion of forecastedclose out (via offsetting transactions) derivative transactions hedged may vary based upon management's assessment of market, weather, operational, and other factors.designated as cash flow hedges.
Our merchant energy businessCommodity Cash Flow Hedges
We have designated certain fixed-price forward contracts as cash-flow hedges of forecasted sales of energy and forecasted purchases of fuel and energy for the years 20072011 through 2016 under SFAS No. 133. Our merchant energy business2016. We had net unrealized pre-tax losses on these cash-flow hedges recorded in "Accumulated other comprehensive income"loss" of $1,498.7$388.0 million at December 31, 20072010 and $2,227.1$951.3 million at December 31, 2006.2009.
We expect to reclassify $760.4$236.6 million of net pre-tax losses on cash-flow hedges from "Accumulated other comprehensive income"loss" into earnings during the next twelve months based on the market prices at December 31, 2007.2010. However, the actual amount reclassified into earnings could vary from the amounts recorded at December 31, 2007,2010, due to future changes in market prices. Additionally, for cash-flow hedges settled by physical delivery of the underlying commodity, "Reclassification of net gains on hedging instruments from OCI to net income" represents the fair value of those derivatives, which is realized through gross settlement at the contract price.
In addition, during 2007,When we de-designated contracts previously designated as cash-flow hedges for which thedetermine that a forecasted transactionstransaction originally hedged arehas become probable of not occurring, and as a result we recognized a pre-tax loss of $24.4 million. The majority of the pre-tax lossreclassify net unrealized gains or losses associated with de-designated contracts in 2007 resultedthose hedges from the deconsolidation of CEP. During 2006, we de-designated contracts previously designated as cash-flow hedges for which the forecasted transactions originally hedged are probable of not occurring, and as a result we"Accumulated other comprehensive loss" to earnings. We recognized a pre-tax loss of $35.3 million. The majority of the pre-tax loss associated with de-designated contracts in 2006 resulted from the initial public offering of CEP and the sale of our gas-fired plants. During 2005, we terminated a contract previously designated as a cash-flow hedge. The forecasted transaction originally hedged was probable of not occurring 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. We record changes in fair value of these hedges related to our retail competitive supply operations as a component of "Fuel and purchased energy expenses" in our Consolidated Statements of Income. We record changes in fair value of these hedges related to our wholesale competitive supply operations as a component of "Nonregulated revenues" in our Consolidated Statements of Income.
We recorded in earnings the following pre-tax gains (losses) related to hedge ineffectiveness:
Year ended December 31, | 2007 | 2006 | 2005 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Cash-flow hedges | $ | (31.4 | ) | $ | 13.4 | $ | (19.4 | ) | ||
Fair value hedges | 24.4 | 27.7 | (2.2 | ) | ||||||
Total | $ | (7.0 | ) | $ | 41.1 | $ | (21.6 | ) | ||
The ineffectiveness amounts in the table above exclude $7.3 million of pre-tax losses that we recognizedon such contracts:
Year ended December 31, | 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Pre-tax losses | $ | (0.3 | ) | $ | (241.0 | ) | $ | (31.7 | ) | |
Interest Rate Swaps Designated as a result of market price changes for the year ended December 31, 2007. These losses represent the change in fair value of derivatives that no longer qualify for cash-flow hedge accounting due to reduced price correlation between the hedge and the risk being hedged, but remain designated as hedges prospectively. In addition, we recognized a $3.8 million pre-tax loss in 2007 and a $8.9 million pre-tax gain in 2006 related to the change in value for the portion of our fair value hedges excluded from ineffectiveness testing.
Regulated Gas BusinessCash Flow Hedges
BGE uses basis swaps in the winter months (November through March) to hedge its price risk associated with natural gas purchases under its market-based rates incentive mechanism and
under its off-system gas sales program. BGE also uses fixed-to-floating and floating-to-fixed swaps to hedge its price risk associated with its off-system gas sales. The fixed portion represents a specific dollar amount that BGE will pay or receive, and the floating portion represents a fluctuating amount based on a published index that BGE will receive or pay. BGE's regulated gas business internal guidelines do not permit the use of swap agreements for any purpose other than to hedge price risk. The impact of these swaps on our, and BGE's, financial results is immaterial.
Regulated Electric Business
BGE uses basis swaps to hedge its price risk associated with electricity purchases. BGE's regulated electric business internal guidelines do not permit the use of swap agreements for any purpose other than to hedge price risk. The impact of these swaps on our, and BGE's, financial results is immaterial.
Interest Rates
We use interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances and to manage our exposure to fluctuations in interest rates on variable rate debt, 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 and to manage the exposure to fluctuations in interest rates on variable rate debt are designated as cash-flow hedges under SFAS No. 133, with the effective portion of gains and losses on these interest rate cash flow hedges, net of associated deferred income tax effects, is recorded in "Accumulated other comprehensive income"loss" in our Consolidated Statements of Common Shareholders' Equity and Comprehensive Income and Consolidated Statements of Capitalization, in anticipation of planned financing transactions.(Loss). We reclassify gains and losses on the hedges from "Accumulated other comprehensive income"loss" into "Interest expense" in our Consolidated Statements of Income (Loss) during the periods in which the interest payments being hedged occur.
Accumulated other comprehensive loss includes net unrealized pre-tax gains on interest rate cash-flow hedges of prior debt issuances totaling $10.1 million at December 31, 2010 and $11.3 million at December 31, 2009. We expect to reclassify $0.9 million of pre-tax net gains on these cash-flow hedges from "Accumulated other comprehensive loss" into "Interest expense" during the next twelve months. We had no hedge ineffectiveness on these swaps.
Fair Value Hedging
We elect fair value hedge accounting for a limited portion of our derivative contracts including certain interest rate swaps. The objectives for electing fair value hedging in these situations are to manage our exposure and to optimize the mix of our fixed and floating-rate debt.
Interest Rate Swaps Designated as Fair Value Hedges
We use interest rate swaps useddesignated as fair value hedges to optimize the mix of fixed and floating-rate debt are designated as fair value hedges under SFAS No. 133.debt. 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,expense." and weWe record any changes in fair value of the swaps and the debt in "Derivative assets and liabilities" and changes in the fair value of the debt in "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.
"Accumulated other comprehensive income" includes net unrealized pre-tax gains on interest rate cash-flow hedges terminated upon debt issuance totaling $11.9 million atAs of December 31, 2007 and $12.5 million at December 31, 2006. We expect to reclassify $0.1 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.
During 2004, to optimize the mix of fixed and floating-rate debt,2010, we entered intohave interest rate swaps qualifying as fair value hedges relating to $450$400 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 an unrealized gain of $11.8$35.7 million at December 31, 20072010 and $35.8 million at December 31, 2009 and was recorded as an increase in our "Derivative assets" and an increase in our "Long-term debt." The fair value of these hedges was an unrealized loss of $7.1 million at December 31, 2006 and was recorded as an increase in our "Derivative liabilities" and a decrease in our "Long-term debt." We had no hedge ineffectiveness on these interest rate swaps.
In January 2011, we terminated $200 million of these interest rate swaps as a result of retiring all of our fixed-rate debt maturing in 2012 and received $13.8 million in cash.
During February 2011, we entered into interest rate swaps qualifying as fair value hedges related to $350 million of our fixed rate debt maturing in 2015, and converted this notional amount of debt to floating rate. We also entered into $150 million of interest rate swaps related to our fixed rate debt maturing in 2020 that do not qualify as fair value hedges, which are discussed underMark-to-Market below.
Hedge Ineffectiveness
For all categories of commodity contract derivative instruments designated in hedging relationships, we recorded in earnings the following pre-tax gains (losses) related to hedge ineffectiveness:
Year ended December 31, | 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Cash-flow hedges | $ | (91.3 | ) | $ | 11.3 | $ | (121.0 | ) | ||
Fair value hedges | — | 23.9 | 20.6 | |||||||
Total | $ | (91.3 | ) | $ | 35.2 | $ | (100.4 | ) | ||
We did not have any fair value hedges for which we have excluded a portion of the change in fair value from our effectiveness assessment.
Mark-to-Market
We generally apply mark-to-market accounting for risk management and trading activities for which changes in fair value more closely reflect the economic performance of the underlying business activity. However, we also use
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mark-to-market accounting for derivatives related to the following activities:
Origination Gains
We may record origination gains associated with commodity derivatives subject to mark-to-market accounting. Origination gains represent the initial fair value of certain structured transactions that our wholesale marketing, risk management, and trading operation executes to meet the risk management needs of our customers. Historically, transactions that result in origination gains have been unique and resulted in individually significant gains from a single transaction. We generally recognize origination gains when we are able to obtain observable market data to validate that the initial fair value of the contract differs from the contract price. Origination gains recognized in the past three years include:
Termination or Restructuring of Commodity Derivative Contracts
We may terminate or restructure in-the-money contracts in exchange for upfront cash payments and a reduction or cancellation of future performance obligations. The termination or restructuring of contracts allows us to lower our exposure to performance risk under these contracts. We had no such transactions for commodity derivative contracts in 2010, 2009 and 2008.
Quantitative Information About Derivatives and Hedging Activities
Background
Effective January 1, 2009, we adopted an accounting standard that addresses disclosures about derivative instruments and hedging activities. This standard does not change the accounting for derivatives; rather, it requires expanded disclosure about derivative instruments and hedging activities regarding:
Balance Sheet Tables
We present our derivative assets and liabilities in our Consolidated Balance Sheets on a net basis, including cash collateral, whenever we have a legally enforceable master netting agreement with a counterparty to a derivative contract. We use master netting agreements whenever possible to manage and substantially reduce our potential counterparty credit risk. The net presentation in our Consolidated Balance Sheets reflects our actual credit exposure after giving effect to the beneficial effects of these agreements and cash collateral, and our credit risk is reduced further by other forms of collateral.
The following table provides information about the types of market risks we manage using derivatives. This table only includes derivatives and does not reflect the price risks we are hedging that arise from physical assets or nonderivative accrual contracts within our Generation and NewEnergy businesses.
As discussed more fully following the table, we present this information by disaggregating our net derivative assets and liabilities into gross components on a contract-by-contract basis before giving effect to the risk-reducing benefits of master netting arrangements and collateral. As a result, we must present each individual contract as an "asset value" if it is in the money or a "liability value" if it is out of the money, regardless of whether the individual contracts offset market or credit risks of other contracts in full or in part. Therefore, the gross amounts in this table do not reflect our actual economic or credit risk associated with derivatives. This gross presentation is intended only to show separately the various derivative contract types we use, such as commodities, interest rate, and foreign exchange.
In order to identify how our derivatives impact our financial position, at the bottom of the table we provide a reconciliation of the gross fair value components to the net fair value amounts as presented in theFair Value Measurements section of this note and our Consolidated Balance Sheets.
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The gross asset and liability values in the tables below are segregated between those derivatives designated in qualifying hedge accounting relationships and those not designated in hedge accounting relationships. Derivatives not designated in hedging relationships include our NewEnergy retail power and gas customer supply operation, economic hedges of accrual activities, the total return swaps entered into to effect the sale of the international commodities and Houston-based gas trading operations in 2009, and risk management and trading activities which we have substantially curtailed as part of our effort to reduce risk in our business. We use the end of period accounting designation to determine the classification for each derivative position.
As of December 31, 2010 | Derivatives Designated as Hedging Instruments for Accounting Purposes | Derivatives Not Designated As Hedging Instruments for Accounting Purposes | All Derivatives Combined | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Contract type | Asset Values (3) | Liability Values (4) | Asset Values (3) | Liability Values (4) | Asset Values (3) | Liability Values (4) | ||||||||||||||
| (In millions) | |||||||||||||||||||
Power contracts | $ | 1,167.9 | $ | (1,362.8 | ) | $ | 6,795.0 | $ | (7,166.5 | ) | $ | 7,962.9 | $ | (8,529.3 | ) | |||||
Gas contracts | 1,902.3 | (1,832.8 | ) | 3,390.1 | (3,155.3 | ) | 5,292.4 | (4,988.1 | ) | |||||||||||
Coal contracts | 97.0 | (48.6 | ) | 266.0 | (259.7 | ) | 363.0 | (308.3 | ) | |||||||||||
Other commodity contracts (1) | — | — | 61.4 | (61.6 | ) | 61.4 | (61.6 | ) | ||||||||||||
Interest rate contracts | 35.7 | — | 34.4 | (35.7 | ) | 70.1 | (35.7 | ) | ||||||||||||
Foreign exchange contracts | — | — | 11.0 | (8.4 | ) | 11.0 | (8.4 | ) | ||||||||||||
Total gross fair values | $ | 3,202.9 | $ | (3,244.2 | ) | $ | 10,557.9 | $ | (10,687.2 | ) | $ | 13,760.8 | $ | (13,931.4 | ) | |||||
Netting arrangements (5) | (12,955.5 | ) | 12,955.5 | |||||||||||||||||
Cash collateral | (28.4 | ) | 0.6 | |||||||||||||||||
Net fair values | $ | 776.9 | $ | (975.3 | ) | |||||||||||||||
Net fair value by balance sheet line item: | ||||||||||||||||||||
Accounts receivable (2) | $ | (16.4 | ) | |||||||||||||||||
Derivative assets—current | 534.4 | |||||||||||||||||||
Derivative assets—noncurrent | 258.9 | |||||||||||||||||||
Derivative liabilities—current | (622.3 | ) | ||||||||||||||||||
Derivative liabilities—noncurrent | (353.0 | ) | ||||||||||||||||||
Total Derivatives | $ | 776.9 | $ | (975.3 | ) | |||||||||||||||
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As of December 31, 2009 | Derivatives Designated as Hedging Instruments for Accounting Purposes | Derivatives Not Designated As Hedging Instruments for Accounting Purposes | All Derivatives Combined | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Contract type | Asset Values (3) | Liability Values (4) | Asset Values (3) | Liability Values (4) | Asset Values (3) | Liability Values (4) | ||||||||||||||
| (In millions) | |||||||||||||||||||
Power contracts | $ | 1,737.3 | $ | (2,292.1 | ) | $ | 11,729.3 | $ | (12,414.3 | ) | $ | 13,466.6 | $ | (14,706.4 | ) | |||||
Gas contracts | 1,860.6 | (1,380.0 | ) | 4,159.1 | (3,857.1 | ) | 6,019.7 | (5,237.1 | ) | |||||||||||
Coal contracts | 20.1 | (40.8 | ) | 609.5 | (627.2 | ) | 629.6 | (668.0 | ) | |||||||||||
Other commodity contracts (1) | 1.4 | (0.8 | ) | 83.1 | (32.1 | ) | 84.5 | (32.9 | ) | |||||||||||
Interest rate contracts | 35.8 | — | 28.5 | (39.9 | ) | 64.3 | (39.9 | ) | ||||||||||||
Foreign exchange contracts | — | — | 13.2 | (9.0 | ) | 13.2 | (9.0 | ) | ||||||||||||
Total gross fair values | $ | 3,655.2 | $ | (3,713.7 | ) | $ | 16,622.7 | $ | (16,979.6 | ) | $ | 20,277.9 | $ | (20,693.3 | ) | |||||
Netting arrangements (5) | (19,261.0 | ) | 19,261.0 | |||||||||||||||||
Cash collateral | (92.6 | ) | 125.6 | |||||||||||||||||
Net fair values | $ | 924.3 | $ | (1,306.7 | ) | |||||||||||||||
Net fair value by balance sheet line item: | ||||||||||||||||||||
Accounts receivable (2) | $ | (348.7 | ) | |||||||||||||||||
Derivative assets—current | 639.1 | |||||||||||||||||||
Derivative assets—noncurrent | 633.9 | |||||||||||||||||||
Derivative liabilities—current | (632.6 | ) | ||||||||||||||||||
Derivative liabilities—noncurrent | (674.1 | ) | ||||||||||||||||||
Total Derivatives | $ | 924.3 | $ | (1,306.7 | ) | |||||||||||||||
The magnitude of and changes in the gross derivatives components in these tables do not indicate changes in the level of derivative activities, the level of market risk, or the level of credit risk. The primary factors affecting the magnitude of the gross amounts in the table are changes in commodity prices and the total number of contracts. If commodity prices change, the gross amounts could increase, even if the level of contracts stays the same, because separate presentation is required for contracts that are in the money from those that are out of the money. As a result, the gross amounts of even fully hedged positions could increase if prices change. Additionally, if the number of contracts increases, the gross amounts also could increase. Thus, the execution of new contracts to reduce economic risk could actually increase the gross amounts in the table because of the requirement to present the gross value of each individual contract separately.
The primary purpose of these tables is to disaggregate the risks being managed using derivatives. In order to achieve this objective, we prepare this table by separating each individual derivative contract that is in the money from each contract that is out of the money and present such amounts on a gross basis, even for offsetting contracts that have identical quantities for the same commodity, location, and delivery period. We must also present these components excluding the substantive credit-risk reducing effects of master netting agreements and collateral. As a result, the gross "asset" and "liability" amounts for each contract type far exceed our actual economic exposure to commodity price risk and credit risk. Our actual economic exposure consists of the net derivative position combined with our nonderivative accrual contracts, such as those for load-serving, and our physical assets, such as our power plants. Our actual derivative credit risk exposure after master netting agreements and cash collateral is reflected in the net fair value amounts shown at the bottom of the table above. Our total economic and credit exposures, including derivatives, are managed in a comprehensive risk framework that includes risk measures such as economic value at risk, stress testing, and maximum potential credit exposure.
Gain and (Loss) Tables
The tables below summarize the gain and loss impacts of our derivative instruments segregated into the following categories:
The tables only include this information for derivatives and do not reflect the related gains or losses that arise from generation and generation-related assets, nonderivative accrual contracts, or NPNS contracts within our Generation and NewEnergy businesses, other than fair value hedges, for which
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we separately show the gain or loss on the hedged asset or liability. As a result, for mark-to-market and cash-flow hedge derivatives, these tables only reflect the impact of derivatives themselves and therefore do not necessarily include all of the income statement impacts of the transactions for which derivatives are used to manage risk. For a more complete discussion of how derivatives affect our financial performance, see our accounting policy for Revenues, Fuel and Purchased Energy Expenses, and Derivatives and Hedging Activities inNote 1.
The following tables present gains and losses on derivatives designated as cash flow hedges. As discussed more fully in our accounting policy, we record the effective portion of unrealized gains and losses on cash flow hedges in Accumulated Other Comprehensive Loss until the hedged forecasted transaction affects earnings. We record the ineffective portion of gains and losses on cash flow hedges in earnings as they occur. When the hedged forecasted transaction settles and is recorded in earnings, we reclassify the related amounts from Accumulated Other Comprehensive Loss into earnings, with the result that the combination of revenue or expense from the forecasted transaction and gain or loss from the hedge are recognized in earnings at a total amount equal to the hedged price. Accordingly, the amount of derivative gains and losses recorded in Accumulated Other Comprehensive Loss and reclassified from Accumulated Other Comprehensive Loss into earnings does not reflect the total economics of the hedged forecasted transactions. The total impact of our forecasted transactions and related hedges is reflected in our Consolidated Statements of Income (Loss).
Cash Flow Hedges | | | | Year Ended December 31, | ||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Gain (Loss) Recorded in AOCI | | Gain (Loss) Reclassified from AOCI into Earnings | Ineffectiveness Gain (Loss) Recorded in Earnings | ||||||||||||||||||
| Statement of Income (Loss) Line Item | |||||||||||||||||||||
Contract type: | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | ||||||||||||||||
| (In millions) | | ||||||||||||||||||||
Hedges of forecasted sales: | Nonregulated revenues | |||||||||||||||||||||
Power contracts | $ | 144.5 | $ | 362.5 | $ | (165.8 | ) | $ | (180.6 | ) | $ | 8.9 | $ | 77.5 | ||||||||
Gas contracts | (59.1 | ) | (65.1 | ) | 90.8 | (67.3 | ) | (0.3 | ) | 6.3 | ||||||||||||
Coal contracts | — | 10.0 | — | (229.9 | ) | — | — | |||||||||||||||
Other commodity contracts (1) | — | 6.8 | (0.7 | ) | (0.4 | ) | — | (6.2 | ) | |||||||||||||
Interest rate contracts | — | (0.3 | ) | — | (0.3 | ) | — | — | ||||||||||||||
Foreign exchange contracts | — | 2.5 | (1.0 | ) | (1.1 | ) | — | — | ||||||||||||||
Total gains (losses) | $ | 85.4 | $ | 316.4 | Total included in nonregulated revenues | $ | (76.7 | ) | $ | (479.6 | ) | $ | 8.6 | $ | 77.6 | |||||||
Hedges of forecasted purchases: | Fuel and purchased energy expense | |||||||||||||||||||||
Power contracts | $ | (377.4 | ) | $ | (1,056.0 | ) | $ | (1,036.1 | ) | $ | (1,905.3 | ) | $ | (40.7 | ) | $ | (42.2 | ) | ||||
Gas contracts | (141.5 | ) | 103.7 | 216.5 | 165.8 | (64.3 | ) | (15.2 | ) | |||||||||||||
Coal contracts | 65.9 | (77.7 | ) | (34.6 | ) | (187.6 | ) | 4.9 | (8.9 | ) | ||||||||||||
Other commodity contracts (2) | (0.2 | ) | (12.3 | ) | (0.3 | ) | 8.2 | 0.2 | — | |||||||||||||
Foreign exchange contracts | — | — | — | — | — | — | ||||||||||||||||
Total losses | $ | (453.2 | ) | $ | (1,042.3 | ) | Total included in fuel and purchased energy expense | $ | (854.5 | ) | $ | (1,918.9 | ) | $ | (99.9 | ) | $ | (66.3 | ) | |||
Hedges of interest rates: | Interest expense | |||||||||||||||||||||
Interest rate contracts | — | — | 4.3 | 0.6 | — | — | ||||||||||||||||
Total gains | $ | — | $ | — | Total included in interest expense | $ | 4.3 | $ | 0.6 | $ | — | $ | — | |||||||||
Grand total (losses) gains | $ | (367.8 | ) | $ | (725.9 | ) | $ | (926.9 | ) | $ | (2,397.9 | ) | $ | (91.3 | ) | $ | 11.3 | |||||
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The following table presents gains and losses on derivatives designated as fair value hedges and, separately, the gains and losses on the hedged item. As discussed earlier, we record the unrealized gains and losses on fair value hedges as well as changes in the fair value of the hedged asset or liability in earnings as they occur. The difference between these amounts represents hedge ineffectiveness. Due to the sale of our Houston-based gas trading operation, we do not have any activity for fair value hedges related to gas contracts since the second quarter of 2009.
Fair Value Hedges | Year Ended December 31, | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Amount of Gain (Loss) Recognized in Income on Derivative | Amount of Gain (Loss) Recognized in Income on Hedged Item | |||||||||||||
| Statement of Income (Loss) Line Item | |||||||||||||||
Contract type: | 2010 | 2009 | 2010 | 2009 | ||||||||||||
| | (In millions) | ||||||||||||||
Commodity contracts: | ||||||||||||||||
Gas contracts | Nonregulated revenues | $ | — | $ | 40.6 | $ | — | $ | (16.7 | ) | ||||||
Interest rate contracts | Interest expense | 18.0 | (0.1 | ) | (15.6 | ) | 0.7 | |||||||||
Total gains (losses) | $ | 18.0 | $ | 40.5 | $ | (15.6 | ) | $ | (16.0 | ) | ||||||
The following table presents gains and losses on mark-to-market derivatives, contracts that have not been designated as hedges for accounting purposes. As discussed more fully inNote 1, we record the unrealized gains and losses on mark-to-market derivatives in earnings as they occur. While we use mark-to-market accounting for risk management and trading activities because changes in fair value more closely reflect the economic performance of the activity, we also use mark-to-market accounting for certain derivatives related to portions of our physical energy delivery activities. Accordingly, the total amount of gains and losses from mark-to-market derivatives does not necessarily reflect the total economics of related transactions.
Mark-to-Market Derivatives | Year Ended December 31, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
| | Amount of Gain (Loss) Recorded in Income on Derivative | ||||||||
| Statement of Income (Loss) Line Item | |||||||||
Contract type: | 2010 | 2009 | ||||||||
| | (In millions) | ||||||||
Commodity contracts: | ||||||||||
Power contracts | Nonregulated revenues | $ | (26.2 | ) | $ | 250.9 | ||||
Gas contracts | Nonregulated revenues | 41.4 | (360.0 | ) | ||||||
Coal contracts | Nonregulated revenues | 13.3 | 14.0 | |||||||
Other commodity contracts (1) | Nonregulated revenues | (15.4 | ) | (11.7 | ) | |||||
Coal contracts | Fuel and purchased energy expense | — | (109.8 | ) | ||||||
Interest rate contracts | Nonregulated revenues | (2.3 | ) | (27.2 | ) | |||||
Foreign exchange contracts | Nonregulated revenues | (1.2 | ) | 7.6 | ||||||
Total gains (losses) | $ | 9.6 | $ | (236.2 | ) | |||||
In computing the amounts of derivative gains and losses in the above tables, we include the changes in fair values of derivative contracts up to the date of maturity or settlement of each contract. This approach facilitates a comparable presentation for both financial and physical derivative contracts. In addition, for cash flow hedges we include the impact of intra-quarter transactions (i.e., those that arise and settle within the same quarter) in both gains and losses recognized in Accumulated Other Comprehensive Loss and amounts reclassified from Accumulated Other Comprehensive Loss into earnings.
Volume of Derivative Activity
The volume of our derivatives activity is directly related to the fundamental nature and scope of our business and the risks we manage. We own or control electric generating facilities, which exposes us to both power and fuel price risk; we serve electric and gas wholesale and retail customers within our NewEnergy business, which exposes us to electricity and natural gas price risk; and we provide risk management services and engage in trading activities, which can expose us to a variety of commodity price risks. We conduct our business activities throughout the United States and internationally. In order to manage the risks associated with these activities, we are required to be an active participant in the energy markets, and we routinely employ derivative instruments to conduct our business.
Derivative instruments provide an efficient and effective way to conduct our business and to manage the associated risks. We manage our generating resources and customer supply activities based upon established policies and limits, and we use
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derivatives to establish a portion of our hedges and to adjust the level of our hedges from time to time. Additionally, we engage in trading activities which enable us to execute hedging transactions in a cost-effective manner. We manage those activities based upon various risk measures, including position limits, economic value at risk (EVaR) and value at risk (VaR), and we use derivatives to establish and maintain those activities within the prescribed limits. We are also using derivatives to execute, control, and reduce the overall level of our trading positions and risk as well as to manage a portion of our interest rate risk associated with debt and our foreign currency risk from non-dollar denominated transactions. Accordingly, the use of derivative instruments is integral to the conduct of our business, and derivative instruments are an important tool through which we are able to manage and mitigate the risks that are inherent in our activities.
The following table presents information designed to provide insight into the overall volume of our derivatives usage. However, the volumes presented in this table are subject to a number of limitations and should only be used as an indication of the extent of our derivatives usage and the risks they are intended to manage.
First, the volume information is not a complete representation of our market price risk because it only includes derivative contracts. Accordingly, this table does not present a complete picture of our overall net economic exposure, and should not be interpreted as an indication of open or unhedged commodity positions, because the use of derivatives is only one of the means by which we engage in and manage the risks of our business. For example, the table does not include power or fuel quantities and risks arising from our physical assets, non-derivative contracts, and forecasted transactions that we manage using derivatives; a portion of these volumes reduces those risks. It also does not include volumes of commodities under nonderivative contracts that we use to serve customers or manage our risks. Our actual net economic exposure from our generating facilities and customer supply activities is reduced by derivatives, and the exposure from our trading activities is managed and controlled through the risk measures discussed above. Therefore, the information in the table below is only an indication of that portion of our business that we manage through derivatives and serves primarily to identify the extent of our derivatives activities and the types of risks that they are intended to manage.
Additionally, the disclosure of derivative quantities potentially could reveal commercially valuable or otherwise competitively sensitive information that could limit the effectiveness and profitability of our business activities. Therefore, in the table below, we have computed the derivative volumes for commodities by aggregating the absolute value of net positions within commodities for each year. This provides an indication of the level of derivatives activity, but it does not indicate either the direction of our position (long or short), or the overall size of our position. We believe this presentation gives an appropriate indication of the level of derivatives activity without unnecessarily revealing the size and direction of our derivatives positions.
Finally, the volume information for commodity derivatives represents "delta equivalent" quantities, not gross notional amounts. We make use of different types of commodity derivative instruments such as forwards, futures, options, and swaps, and we believe that the delta equivalent quantity is the most relevant measure of the volume associated with these commodity derivatives. The delta-equivalent quantity represents a risk-adjusted notional quantity for each contract that takes into account the probability that an option will be exercised. Therefore, the volume information for commodity derivatives represents the delta equivalent quantity of those contracts, computed on the basis described above. For interest rate contracts and foreign currency contracts we have presented the notional amounts of such contracts in the table below.
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The following tables present the volume of our derivative activities as of December 31, 2010 and 2009, shown by contractual settlement year.
Quantities (1) Under Derivative Contracts | | | As of December 31, 2010 | |||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Contract Type (Unit) | 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | |||||||||||||||
| (In millions) | |||||||||||||||||||||
Power (MWH) | 21.2 | — | 3.8 | 4.2 | 2.3 | 0.2 | 31.7 | |||||||||||||||
Gas (mmBTU) | 175.3 | 90.1 | 80.2 | 64.7 | 24.1 | — | 434.4 | |||||||||||||||
Coal (Tons) | 4.4 | 2.5 | 0.1 | — | — | — | 7.0 | |||||||||||||||
Oil (BBL) | 0.2 | 0.1 | 0.1 | — | — | — | 0.4 | |||||||||||||||
Emission Allowances (Tons) | 1.5 | — | — | — | — | — | 1.5 | |||||||||||||||
Renewable Energy Credits (Number of credits) | 0.4 | 0.3 | 0.3 | 0.3 | 0.3 | 0.7 | 2.3 | |||||||||||||||
Interest Rate Contracts | $ | 639.4 | $ | 490.7 | $ | 941.8 | $ | 405.0 | $ | 460.0 | $ | 175.0 | $ | 3,111.9 | ||||||||
Foreign Exchange Rate Contracts | $ | 48.7 | $ | 8.7 | $ | 16.8 | $ | 16.8 | $ | 15.5 | $ | — | $ | 106.5 | ||||||||
Quantities (1) Under Derivative Contracts | | | As of December 31, 2009 | |||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Contract Type (Unit) | 2010 | 2011 | 2012 | 2013 | 2014 | Thereafter | Total | |||||||||||||||
| (In millions) | |||||||||||||||||||||
Power (MWH) | 32.7 | 1.6 | 3.2 | 3.2 | 0.1 | 0.9 | 41.7 | |||||||||||||||
Gas (mmBTU) | 37.3 | 37.4 | 22.1 | 21.0 | 22.7 | 21.3 | 161.8 | |||||||||||||||
Coal (Tons) | 3.9 | 3.9 | 0.2 | — | — | — | 8.0 | |||||||||||||||
Oil (BBL) | 0.3 | — | — | — | — | — | 0.3 | |||||||||||||||
Emission Allowances (Tons) | 7.2 | — | — | — | — | — | 7.2 | |||||||||||||||
Interest Rate Contracts | $ | 972.3 | $ | 140.6 | $ | 440.5 | $ | 58.2 | $ | 255.0 | $ | 200.0 | $ | 2,066.6 | ||||||||
Foreign Exchange Rate Contracts | $ | 27.9 | $ | 72.4 | $ | 16.7 | $ | 16.7 | $ | 16.8 | $ | 15.5 | $ | 166.0 | ||||||||
In addition to the commodities in the tables above, we also hold derivative instruments related to weather that are insignificant relative to the overall level of our derivative activity.
Credit-Risk Related Contingent Features
Certain of our derivative instruments contain provisions that would require additional collateral upon a credit-related event such as an adequate assurance provision or a credit rating decrease in the senior unsecured debt of Constellation Energy. The amount of collateral we could be required to post would be determined by the fair value of contracts containing such provisions that represent a net liability, after offset for the fair value of any asset contracts with the same counterparty under master netting agreements and any other collateral already posted. This collateral amount is a component of, and is not in addition to, the total collateral we could be required to post for all contracts upon a credit rating decrease.
The following tables present information related to these derivatives at December 31, 2010 and 2009. Based on contractual provisions, we estimate that if Constellation Energy's senior unsecured debt were downgraded, our total contingent collateral obligation for derivatives in a net liability position was $0.1 billion at December 31, 2010 and $0.2 billion as of December 31, 2009, which represents the additional collateral that we could be required to post with counterparties, including both cash collateral and letters of credit, in the event of a credit downgrade to below investment grade. These amounts are associated with net derivative liabilities totaling $0.9 billion at December 31, 2010 and $1.0 billion at December 31, 2009 after reflecting legally binding master netting agreements and collateral already posted.
We present the gross fair value of derivatives in a net liability position that have credit-risk-related contingent features in the first column in the table below. This gross fair value amount represents only the out-of-the-money contracts containing such features that are not fully collateralized by cash on a stand-alone basis. Thus, this amount does not reflect the offsetting fair value of in-the-money contracts under legally-binding master netting agreements with the same counterparty, as shown in the second column in the table. These in-the-money contracts would offset the amount of any gross liability that could be required to be collateralized, and as a result, the actual potential collateral requirements would be based upon the net fair value of derivatives containing such features, not the gross amount. The amount of any possible contingent collateral for such contracts in the event of a downgrade would be further reduced to the extent that we have already posted collateral related to the net liability.
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Because the amount of any contingent collateral obligation would be based on the net fair value of all derivative contracts under each master netting agreement, we believe that the "net fair value of derivative contracts containing this feature" as shown in the tables below is the most relevant measure of derivatives in a net liability position with credit-risk-related contingent features. This amount reflects the actual net liability upon which existing collateral postings are computed and upon which any additional contingent collateral obligation would be based.
Credit-Risk Related Contingent Feature | As of December 31, 2010 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Gross Fair Value of Derivative Contracts Containing This Feature (1) | Offsetting Fair Value of In-the-Money Contracts Under Master Netting Agreements (2) | Net Fair Value of Derivative Contracts Containing This Feature (3) | Amount of Posted Collateral (4) | Contingent Collateral Obligation (5) | |||||||||
| | (In billions) | | | |||||||||
$4.6 | $ | (3.7 | ) | $ | 0.9 | $ | 0.7 | $ | 0.1 | ||||
Credit-Risk Related Contingent Feature | As of December 31, 2009 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Gross Fair Value of Derivative Contracts Containing This Feature (1) | Offsetting Fair Value of In-the-Money Contracts Under Master Netting Agreements (2) | Net Fair Value of Derivative Contracts Containing This Feature (3) | Amount of Posted Collateral (4) | Contingent Collateral Obligation (5) | |||||||||
| | (In billions) | | | |||||||||
$8.6 | $ | (7.6 | ) | $ | 1.0 | $ | 0.7 | $ | 0.2 | ||||
Concentrations of Derivative-Related Credit Risk
We discuss our concentrations of credit risk, including derivative-related positions, inNote 1. At December 31, 2010, two counterparties, a large power cooperative and CENG, comprise total exposure concentrations of 25%.
Fair Value Measurements
Effective January 1, 2008, we adopted guidance related to fair value measurements. This guidance defines fair value, establishes a framework for measuring fair value, and requires certain disclosures about fair value measurements. We discuss our fair value measurements below.
We determine the fair value of our assets and liabilities using unadjusted quoted prices in active markets (Level 1) or pricing inputs that are observable (Level 2) whenever that information is available. We use unobservable inputs (Level 3) to estimate fair value only when relevant observable inputs are not available.
We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. We determine fair value for assets and liabilities classified as Level 1 by multiplying the market price by the quantity of the asset or liability. We primarily determine fair value measurements classified as Level 2 or Level 3 using the income valuation approach, which involves discounting estimated cash flows using assumptions that market participants would use in pricing the asset or liability.
We present all derivatives recorded at fair value net with the associated fair value cash collateral. This presentation of the net position reflects our credit exposure for our on-balance sheet positions but excludes the impact of any off-balance sheet positions and collateral. Examples of off-balance sheet positions and collateral include in-the-money accrual contracts for which the right of offset exists in the event of default and letters of credit. We discuss our letters of credit in more detail inNote 8.
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Recurring Measurements
Our assets and liabilities measured at fair value on a recurring basis consist of the following (BGE's assets and liabilities measured at fair value on a recurring basis are immaterial):
| As of December 31, 2010 | ||||||||
---|---|---|---|---|---|---|---|---|---|
| Assets | Liabilities | |||||||
| (In millions) | ||||||||
Cash equivalents | $ | 1,545.4 | $ | — | |||||
Equity securities | 43.7 | — | |||||||
Derivative instruments: | |||||||||
Classified as derivative assets and liabilities: | |||||||||
Current | 534.4 | (622.3 | ) | ||||||
Noncurrent | 258.9 | (353.0 | ) | ||||||
Total classified as derivative assets and liabilities | 793.3 | (975.3 | ) | ||||||
Classified as accounts receivable (1) | (16.4 | ) | — | ||||||
Total derivative instruments | 776.9 | (975.3 | ) | ||||||
Total recurring fair value measurements | $ | 2,366.0 | $ | (975.3 | ) | ||||
| As of December 31, 2009 | ||||||||
---|---|---|---|---|---|---|---|---|---|
| Assets | Liabilities | |||||||
| (In millions) | ||||||||
Cash equivalents | $ | 3,065.4 | $ | — | |||||
Equity securities | 46.2 | — | |||||||
Derivative instruments: | |||||||||
Classified as derivative assets and liabilities: | |||||||||
Current | 639.1 | (632.6 | ) | ||||||
Noncurrent | 633.9 | (674.1 | ) | ||||||
Total classified as derivative assets and liabilities | 1,273.0 | (1,306.7 | ) | ||||||
Classified as accounts receivable (1) | (348.7 | ) | — | ||||||
Total derivative instruments | 924.3 | (1,306.7 | ) | ||||||
Total recurring fair value measurements | $ | 4,035.9 | $ | (1,306.7 | ) | ||||
Cash equivalents represent money market funds which are included in "Cash and cash equivalents" in the Consolidated Balance Sheets. Equity securities primarily represent mutual fund investments which are included in "Other assets" in the Consolidated Balance Sheets. Derivative instruments represent unrealized amounts related to all derivative positions, including futures, forwards, swaps, and options. We classify exchange-listed contracts as part of "Accounts Receivable" in our Consolidated Balance Sheets. We classify the remainder of our derivative contracts as "Derivative assets" or "Derivative liabilities" in our Consolidated Balance Sheets.
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The tables below set forth by level within the fair value hierarchy the gross components of the Company's assets and liabilities that were measured at fair value on a recurring basis as of December 31, 2010 and 2009. For December 31, 2010, our net derivative assets and liabilities are disaggregated on a gross contract-by-contract basis. These gross balances are intended solely to provide information on sources of inputs to fair value and proportions of fair value involving objective versus subjective valuations and do not represent either our actual credit exposure or net economic exposure. Therefore, the objective of this table is to provide information about how each individual derivative contract is valued within the fair value hierarchy, regardless of whether a particular contract is eligible for netting against other contracts or whether it has been collateralized.
At December 31, 2010 | Level 1 | Level 2 | Level 3 | Netting and Cash Collateral (1) | Total Net Fair Value | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||||||||
Cash equivalents | $ | 1,545.4 | $ | — | $ | — | $ | — | $ | 1,545.4 | |||||||
Equity securities | 43.7 | — | — | — | 43.7 | ||||||||||||
Derivative assets: | |||||||||||||||||
Power contracts | — | 7,509.6 | 453.3 | ||||||||||||||
Gas contracts | 63.9 | 5,113.3 | 115.2 | ||||||||||||||
Coal contracts | — | 355.6 | 7.4 | ||||||||||||||
Other commodity contracts | 6.6 | 54.8 | — | ||||||||||||||
Interest rate contracts | 33.1 | 37.0 | — | ||||||||||||||
Foreign exchange contracts | — | 11.0 | — | ||||||||||||||
Total derivative assets | 103.6 | 13,081.3 | 575.9 | (12,983.9 | ) | 776.9 | |||||||||||
Derivative liabilities: | |||||||||||||||||
Power contracts | — | (7,758.2 | ) | (771.1 | ) | ||||||||||||
Gas contracts | (72.7 | ) | (4,910.3 | ) | (5.1 | ) | |||||||||||
Coal contracts | — | (307.4 | ) | (0.9 | ) | ||||||||||||
Other commodity contracts | (7.1 | ) | (54.5 | ) | — | ||||||||||||
Interest rate contracts | (35.7 | ) | — | — | |||||||||||||
Foreign exchange contracts | — | (8.4 | ) | — | |||||||||||||
Total derivative liabilities | (115.5 | ) | (13,038.8 | ) | (777.1 | ) | 12,956.1 | (975.3 | ) | ||||||||
Net derivative position | (11.9 | ) | 42.5 | (201.2 | ) | (27.8 | ) | (198.4 | ) | ||||||||
Total | $ | 1,577.2 | $ | 42.5 | $ | (201.2 | ) | $ | (27.8 | ) | $ | 1,390.7 | |||||
At December 31, 2009 | Level 1 | Level 2 | Level 3 | Netting and Cash Collateral (1) | Total Net Fair Value | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||||||||
Cash equivalents | $ | 3,065.4 | $ | — | $ | — | $ | — | $ | 3,065.4 | |||||||
Equity securities—mutual funds | 46.2 | — | — | — | 46.2 | ||||||||||||
Derivative assets | 80.7 | 19,393.9 | 803.3 | (19,353.6 | ) | 924.3 | |||||||||||
Derivative liabilities | (79.0 | ) | (19,519.5 | ) | (1,094.8 | ) | 19,386.6 | (1,306.7 | ) | ||||||||
Net derivative position | 1.7 | (125.6 | ) | (291.5 | ) | 33.0 | (382.4 | ) | |||||||||
Total | $ | 3,113.3 | $ | (125.6 | ) | $ | (291.5 | ) | $ | 33.0 | $ | 2,729.2 | |||||
The factors that cause changes in the gross components of the derivative amounts in the tables above are unrelated to the existence or level of actual market or credit risk from our operations. We describe the primary factors that change the gross components below.
We prepared this table by separating each individual derivative contract that is in the money from each contract that
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is out of the money. We also did not reflect master netting agreements and collateral for our derivatives. As a result, the gross "asset" and "liability" amounts in each of the three fair value levels far exceed our actual economic exposure to commodity price risk and credit risk. Our actual economic exposure consists of the net derivative position combined with our nonderivative accrual contracts, such as those for load-serving, and our physical assets, such as our power plants. Our actual credit risk exposure is reflected in the net derivative asset and derivative liability amounts shown in the Total Net Fair Value column.
Increases and decreases in the gross components presented in each of the levels in this table also do not indicate changes in the level of derivative activities. Rather, the primary factors affecting the gross amounts are commodity prices and the total number of contracts. If commodity prices change, the gross amounts could increase, even if the level of contracts stays the same, because separate presentation is required for contracts that are in the money from those that are out of the money. As a result, even fully hedged positions could exhibit increases in the gross amounts if prices change. Additionally, if the number of contracts increases, the gross amounts also could increase. Thus, the execution of new contracts to reduce economic risk could actually increase the gross amounts in the table because of the required separation of contracts discussed above.
Cash equivalents consist of exchange-traded money market funds, which are valued by multiplying unadjusted quoted prices in active markets by the quantity of the asset and are classified within Level 1.
Equity securities consist of mutual funds, which are valued by multiplying unadjusted quoted prices in active markets by the quantity of the asset and are classified within Level 1.
Derivative instruments include exchange-traded and bilateral contracts. Exchange-traded derivative contracts include futures and options. Bilateral derivative contracts include swaps, forwards, options and structured transactions. We have classified derivative contracts within the fair value hierarchy as follows:
During 2010, there were no significant transfers of derivatives between Level 1 and Level 2 of the fair value hierarchy.
We utilize models based upon the income approach to measure the fair value of derivative contracts classified as Level 2 or 3. Generally, we use similar models to value similar instruments. In order to determine fair value, we utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include:
The primary input to our valuation models is the forward commodity curve for the respective instrument. Forward commodity curves are derived from published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of our derivatives will depend on a number of factors including commodity type, location, and expected delivery period. Price volatility would vary by commodity and location. When appropriate, we discount future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and our own credit quality for liabilities.
We also record valuation adjustments to reflect uncertainty associated with certain estimates inherent in the determination of the fair value of derivative assets and liabilities. The effect of these uncertainties is not incorporated in market price information of other market-based estimates used to determine fair value of our mark-to-market energy contracts.
We describe below the main types of valuation adjustments we record and the process for establishing each. Generally, increases in valuation adjustments reduce our earnings, and decreases in valuation adjustments increase our earnings. However, all or a portion of the effect on earnings of changes in valuation adjustments may be offset by changes in the value of the underlying positions.
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spreads increase, or market information is not available, and it decreases as we reduce our unhedged positions, bid-offer spreads decrease, or market information becomes available.
We regularly evaluate and validate the inputs we use to estimate fair value by a number of methods, consisting of various market price verification procedures, including the use of pricing services and multiple broker quotes to support the market price of the various commodities in which we transact, as well as review and verification of models and changes to those models. These activities are undertaken by individuals that are independent of those responsible for estimating fair value.
The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy. Because of the long-term nature of certain assets and liabilities measured at fair value as well as differences in the availability of market prices and market liquidity over their terms, inputs for some assets and liabilities may fall into any one of the three levels in the fair value hierarchy or some combination thereof. Thus, even though we are required to classify these assets and liabilities in the lowest level in the hierarchy for which inputs are significant to the fair value measurement, a portion of that measurement may be determined using inputs from a higher level in the hierarchy.
The following table sets forth a reconciliation of changes in Level 3 fair value measurements, which predominantly relate to power contracts:
| Year Ended December 31, | |||||||
---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | ||||||
| (In millions) | |||||||
Balance at beginning of period | $ | (291.5 | ) | $ | 37.0 | |||
Realized and unrealized (losses) gains: | ||||||||
Recorded in income | 157.0 | (297.0 | ) | |||||
Recorded in other comprehensive income | 95.2 | 201.6 | ||||||
Purchases, sales, issuances, and settlements | (69.6 | ) | (140.8 | ) | ||||
Transfers into Level 3 (1) | 73.6 | |||||||
Transfers out of Level 3 (1) | (165.9 | ) | ||||||
Net transfers into and out of Level 3 | (92.3 | ) | (92.3 | ) | ||||
Balance at end of year | $ | (201.2 | ) | $ | (291.5 | ) | ||
Change in unrealized gains recorded in income relating to derivatives still held at end of period | $ | 189.5 | $ | (27.8 | ) | |||
Realized and unrealized gains (losses) are included primarily in "Nonregulated revenues" for our derivative contracts that are marked-to-market in our Consolidated Statements of Income (Loss) and are included in "Accumulated other comprehensive loss" for our derivative contracts designated as cash-flow hedges in our Consolidated Balance Sheets. We discuss the income statement classification for realized gains and losses related to cash-flow hedges for our various hedging relationships inNote 1.
Realized and unrealized gains (losses) include the realization of derivative contracts through maturity. This includes the fair value, as of the beginning of each quarterly reporting period, of contracts that matured during each quarterly reporting period. Purchases, sales, issuances, and settlements represent cash paid or
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received for option premiums, and the acquisition or termination of derivative contracts prior to maturity. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the inputs to the model became unobservable. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable based on the criteria discussed previously for classification in either Level 1 or Level 2. Because the depth and liquidity of the power markets varies substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of our bilateral derivative contracts changes frequently. As a result, we also expect derivatives balances to transfer into and out of Level 3 frequently based on changes in the observable data available as of the end of the period.
Nonrecurring Measurements
The table below sets forth by level within the fair value hierarchy our assets and liabilities that were measured at fair value on a nonrecurring basis during the year ended December 31, 2010:
| Fair Value at September 30, 2010 | Fair Value at December 31, 2010 | Level 3 | Losses for the year ended December 31, 2010 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||||||
Investment in CENG | $ | 2,970.4 | $ | N/A | $ | 2,970.4 | $ | 2,275.0 | ||||||
Other investments: | ||||||||||||||
UNE | — | N/A | — | 143.4 | ||||||||||
Qualifying facilities—coal | 36.7 | N/A | 36.7 | 50.0 | ||||||||||
Qualifying facilities—hydroelectric | N/A | 14.8 | 14.8 | 8.4 | ||||||||||
Total other investments | 36.7 | 14.8 | 51.5 | 201.8 | ||||||||||
Total | $ | 3,007.1 | $ | 14.8 | $ | 3,021.9 | $ | 2,476.8 | ||||||
During the quarter ended September 30, 2010, we recorded other-than-temporary impairment charges of $2,468.4 million on our equity method investments including CENG, UNE, and three coal-fired generating facilities located in California. Additionally, during the quarter ended December 31, 2010, we recorded an other-than-temporary impairment charge of $8.4 million on one of our equity investments that own a hydroelectric generating facility in California. These fair value measurements included significant unobservable inputs, and, as such, the entire amounts of the measurements were classified as Level 3. We discuss these impairment charges, including the inputs and valuation techniques used to estimate the fair value of these equity method investments, in more detail inNote 2.
There were no nonrecurring measurements in 2009.
Fair Value of Financial Instruments
TheWe show the carrying amounts and fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Significant differences can occur between the fair value and carrying amountvalues of financial instruments that are recorded at historical amounts.included in our Consolidated Balance Sheets in the following table:
At December 31, | 2010 | 2009 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||
| (In millions) | |||||||||||||
Investments and other assets—Constellation Energy | $ | 248.7 | $ | 249.2 | $ | 167.6 | $ | 166.0 | ||||||
Fixed-rate long-term debt: | ||||||||||||||
Constellation Energy (including BGE) | 4,229.3 | 4,518.4 | 4,225.0 | 4,433.1 | ||||||||||
BGE | 2,143.6 | 2,301.8 | 2,200.1 | 2,280.5 | ||||||||||
Variable-rate long-term debt: | ||||||||||||||
Constellation Energy (including BGE) | 528.7 | 528.7 | 649.9 | 649.9 | ||||||||||
BGE | — | — | — | — | ||||||||||
We use the following methods and assumptions for estimating fair value disclosures for financial instruments:
We show the carrying amounts and fair values
153
Table of financial instruments included in our Consolidated Balance Sheets in the following table:Contents
At December 31, | 2007 | 2006 | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||
| (In millions) | ||||||||||||
Investments and other assets—Constellation Energy | $ | 1,634.2 | $ | 1,634.5 | $ | 1,468.8 | $ | 1,469.3 | |||||
Fixed-rate long-term debt: | |||||||||||||
Constellation Energy | 4,244.3 | 4,307.5 | 4,383.8 | 4,513.8 | |||||||||
BGE | 2,215.1 | 2,178.6 | 1,716.7 | 1,712.6 | |||||||||
Variable-rate long-term debt: | |||||||||||||
Constellation Energy | 801.6 | 801.6 | 723.2 | 723.2 | |||||||||
BGE | — | — | — | — |
14Stock-Based Compensation
Under our long-term incentive plans, we grant stock options, performance and service-based restricted stock, performance- and service-based units, stock units, deferred cash and equity to officers, key employees, and members of the Board of Directors. In May 2007,2010, shareholders approved Constellation Energy's Amended and Restated 2007 Long-Term Incentive Plan, under which we can grant up to a totalincluding an increase in the number of 9,000,000 shares.shares available for issuance by 9,000,000. Any shares covered by an outstanding award under any of our long-term incentive plans that are forfeited or cancelled, expire or are settled in cash will become available for issuance under the Amended and Restated 2007 Long-Term Incentive Plan. At December 31, 2007,2010, there were 9,244,96912,818,160 shares available for issuance under the 2007 Long-Term Incentive Plan. At December 31, 2007,2010, we had stock options, restricted stock, performance unitunits and equity grants outstanding as discussed below. We may issue new shares, reuse forfeited shares, or buy shares in the market in order to deliver shares to employees for our equity grants. BGE officers and key employees participate in our stock-based compensation plans. The expense recognized by BGE in 2007, 2006,2010, 2009, and 20052008 was not material to BGE's financial results.
Non-Qualified Stock Options
Options are granted with an exercise price equal to the market value of the common stock at the date of grant, become vested over a period up to three years (expense recognized in tranches), and expire ten years from the date of grant.
The fair value of our stock-based awards was estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted- average assumptions:
| 2007 | 2006 | 2005 | ||||
---|---|---|---|---|---|---|---|
Risk-free interest rate | 4.69 | % | — | 4.10 | % | ||
Expected life (in years) | 4.0 | — | 2.9* | ||||
Expected market price volatility factor | 20.3 | % | — | 21.3 | % | ||
Expected dividend yield | 2.5 | % | — | 3.0 | % |
* Includes 2.0 million fully vested options granted in December 2005, which would have been cancelled upon a change in control if our proposed merger with FPL Group would have been consummated and for which an expected life of one year was used to value the grant. Excluding this grant, we used a weighted-average expected life assumption of 5 years for 2005 grants.
| 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Risk-free interest rate | 1.87 | % | 1.95 | % | 2.57 | % | ||||
Expected life (in years) | 4.0 | 4.0 | 4.0 | |||||||
Expected market price volatility factor | 32.5 | % | 37.8 | % | 25.8 | % | ||||
Expected dividend yield | 2.74 | % | 4.83 | % | 1.85 | % |
During 2006, no stock options were granted to employees in anticipation of the proposed merger with FPL Group, which was terminated in October 2006. We discuss the termination of the merger in more detail inNote 15.
We use the historical data related to stock option exercises in order to estimate the expected life of our stock options. We also use historical data in order to estimate the volatility factor (measured on a daily basis) for a period equal to the duration of the expected life of option awards.awards, information on the volatility of an identified group of peer companies, and implied volatilities for certain publicly traded options in Constellation Energy common stock in order to estimate the volatility factor. We believe that the use of historicalthis data to estimate these factors provides a reasonable basis for our assumptions. The risk-free interest rate for the periods within the expected life of the option is based on the U.S Treasury yield curve in effect and the expected dividend yield is based on our current estimate for dividend payout at the time of grant. We disclose the pro-forma effect on net income and earnings per share for the periods prior to adoption of SFAS No. 123R inNote 1.
Summarized information for our stock option grants is as follows:
| 2007 | 2006 | 2005 | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| ||||||||||||||||
| Shares | Weighted- Average Exercise Price | Shares | �� | Weighted- Average Exercise Price | Shares | Weighted- Average Exercise Price | |||||||||
| (Shares in thousands) | |||||||||||||||
Outstanding, beginning of year | 6,051 | $ | 47.23 | 7,172 | $ | 45.24 | 7,365 | $ | 31.62 | |||||||
Granted with exercise prices at fair market value | 1,759 | 76.22 | — | — | 3,840 | 54.94 | ||||||||||
Exercised | (1,411 | ) | 41.91 | (1,050 | ) | 33.77 | (3,935 | ) | 29.32 | |||||||
Forfeited/expired | (254 | ) | 67.85 | (71 | ) | 45.22 | (98 | ) | 42.19 | |||||||
Outstanding, end of year | 6,145 | $ | 55.90 | 6,051 | $ | 47.23 | 7,172 | $ | 45.24 | |||||||
Exercisable, end of year | 4,043 | $ | 48.51 | 4,401 | $ | 46.94 | 4,022 | $ | 45.31 | |||||||
Weighted- average fair value per share of options granted with exercise prices at fair market value | $ | 13.76 | $ | — | $ | 7.13 | ||||||||||
| 2010 | 2009 | 2008 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| ||||||||||||||||||||
| Shares | Weighted- Average Exercise Price | Shares | Weighted- Average Exercise Price | Shares | Weighted- Average Exercise Price | ||||||||||||||
| (Shares in thousands) | |||||||||||||||||||
Outstanding, beginning of year | 8,146 | $ | 44.36 | 6,058 | $ | 59.99 | 6,145 | $ | 55.90 | |||||||||||
Granted with exercise prices at fair market value | 1,468 | 35.07 | 3,511 | 20.14 | 1,434 | 93.79 | ||||||||||||||
Exercised | (235 | ) | 23.53 | (83 | ) | 31.07 | (375 | ) | 47.02 | |||||||||||
Forfeited/expired | (309 | ) | 43.41 | (1,340 | ) | 52.41 | (1,146 | ) | 84.59 | |||||||||||
Outstanding, end of year | 9,070 | $ | 43.43 | 8,146 | $ | 44.36 | 6,058 | $ | 59.99 | |||||||||||
Exercisable, end of year | 5,316 | $ | 52.65 | 4,114 | $ | 55.81 | 4,665 | $ | 52.13 | |||||||||||
Weighted-average fair value per share of options granted with exercise prices at fair market value | $ | 7.60 | $ | 4.24 | $ | 18.75 | ||||||||||||||
154
The following table summarizes additional information about stock options during 2007, 20062010, 2009 and 2005:2008:
| 2007 | 2006 | 2005 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Stock Option Expense Recognized | $ | 15.1 | $ | 6.7 | $ | 14.4 | ||||
Stock Options Exercised: | ||||||||||
Cash Received for Exercise Price | 43.4 | 35.5 | 35.3 | |||||||
Intrinsic Value Realized by Employee | 67.6 | 27.6 | 109.8 | |||||||
Realized Tax Benefit | 26.7 | 10.9 | 43.4 | |||||||
Fair Value of Shares that Vested | 82.7 | 82.6 | 232.0 |
| 2010 | 2009 | 2008 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||||
Stock Option Expense Recognized | $ | 9.9 | $ | 14.2 | $ | 11.0 | |||||
Stock Options Exercised: | |||||||||||
Cash Received for Exercise Price | 5.5 | 2.6 | 20.2 | ||||||||
Intrinsic Value Realized by Employee | 2.7 | 0.2 | 14.1 | ||||||||
Realized Tax Benefit | 1.1 | 0.1 | 5.7 | ||||||||
Fair Value of Options that Vested | 54.4 | 11.0 | 98.3 |
As of December 31, 2007,2010, we had $11.5$3.8 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards, of which $8.1$2.8 million is expected to be recognized during 2008.2011.
The following table summarizes additional information about stock options outstanding at December 31, 20072010 (stock options in thousands):
| Outstanding | Exercisable | | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Weighted- Average Remaining Contractual Life | ||||||||||||
Range of Exercise Prices | Stock Options | Aggregate Intrinsic Value | Stock Options | Aggregate Intrinsic Value | |||||||||
| | (In millions) | | (In millions) | (In years) | ||||||||
$ | 20.00 – $40.00 | 1,435 | $ | 97.7 | 1,435 | $ | 97.7 | 5.2 | |||||
$ | 40.00 – $60.00 | 3,128 | 149.9 | 2,608 | 123.0 | 5.6 | |||||||
$ | 60.00 – $80.00 | 1,537 | 41.9 | — | — | 9.1 | |||||||
$ | 80.00 – $100.00 | 45 | 0.6 | — | — | 9.5 | |||||||
6,145 | $ | 290.1 | 4,043 | $ | 220.7 | ||||||||
| Outstanding | Exercisable | | ||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Weighted- Average Remaining Contractual Life | ||||||||||||||||
Range of Exercise Prices | Stock Options | Aggregate Intrinsic Value | Stock Options | Aggregate Intrinsic Value | |||||||||||||
| | (In millions) | | (In millions) | (In years) | ||||||||||||
$ 0 – $ 20 | 2,896 | $ | 31.9 | 871 | $ | 9.6 | 8.2 | ||||||||||
$20 – $ 40 | 2,422 | — | 930 | — | 6.8 | ||||||||||||
$40 – $ 60 | 2,245 | — | 2,245 | — | 4.7 | ||||||||||||
$60 – $ 80 | 762 | — | 762 | — | 6.2 | ||||||||||||
$80 – $100 | 745 | — | 508 | — | 7.1 | ||||||||||||
9,070 | $ | 31.9 | 5,316 | $ | 9.6 | ||||||||||||
Restricted Stock Awards
In addition to stock options, we issue service-based common stock based on meeting certain service goals. This stockthat vests to participants at various timesover periods ranging from one to five years if the service goals are met. In accordanceand fully vested common stock units with SFAS No. 123R, wesales restrictions ranging from approximately 10 months to 5 years. We account for our service-basedthese awards as equity awards, whereby we recognize the value of the market price of the underlying stock on the date of grant toas compensation expense immediately for fully vested common stock units with sales restrictions or over the service period either ratably or in tranches (depending if the award has cliff or graded vesting). for service-based common stock.
We recorded compensation expense related to our restricted stock awards of $35.8$9.5 million in 2007, $24.52010, $16.7 million in 2006,2009, and $28.2$35.3 million in 2005.2008. The tax benefits received associated with our restricted awards were $17.6$10.0 million in 2007, $10.92010, $6.7 million in 2006,2009, and $7.5$20.1 million in 2005.2008.
Summarized share information for our restricted stock awards is as follows:
| 2007 | 2006 | 2005 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (Shares in thousands) | ||||||||||
Outstanding, beginning of year | 1,207 | 1,272 | 1,223 | ||||||||
Granted | 710 | 511 | 485 | ||||||||
Released to participants | (552 | ) | (502 | ) | (359 | ) | |||||
Cancelled | (43 | ) | (74 | ) | (77 | ) | |||||
Outstanding, end of year | 1,322 | 1,207 | 1,272 | ||||||||
Weighted-average fair value of restricted stock granted (per share) | $ | 75.29 | $ | 58.68 | $ | 51.23 | |||||
Total fair value of shares for which restriction has lapsed (in millions) | $ | 44.5 | $ | 27.6 | $ | 19.0 | |||||
| 2010 | 2009 | 2008 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| (Shares in thousands) | ||||||||||
Outstanding, beginning of year | 1,017 | 1,033 | 1,322 | ||||||||
Granted | 832 | 866 | 365 | ||||||||
Released to participants | (713 | ) | (701 | ) | (536 | ) | |||||
Canceled | (56 | ) | (181 | ) | (118 | ) | |||||
Outstanding, end of year | 1,080 | 1,017 | 1,033 | ||||||||
Weighted-average fair value of restricted stock granted (per share) | $ | 34.83 | $ | 19.83 | $ | 94.62 | |||||
Total fair value of shares for which restriction has lapsed (in millions) | $ | 24.9 | $ | 16.5 | $ | 49.7 | |||||
As of December 31, 2007,2010, we had $26.8$8.6 million of unrecognized compensation cost related to the unvested portion of outstanding restricted stock awards expected to be recognized within a 26-month43-month period. At December 31, 2007,2010, we have recorded in "Common shareholders' equity" approximately $42.3$18.6 million and approximately $31.7$37.4 million at December 31, 20062009 for the unvested portion of service-based restricted stock granted from 20032008 until 20072010 to officers and other employees that is contingently redeemable in cash upon a change in control.
Performance-Based Units
In accordance with SFAS No. 123R, weWe recognize compensation expense ratably for our performance-based awards, which are classified as liability awards, for which the fair value of the award is remeasured at each reporting period. Each unit is equivalent to $1 in value and cliff vests at the end of a three-year service and performance period. The level of payout is based on the achievement of certain performance goals at the end of the three-year period and will be settled in cash. We recordedrecognized compensation expense of $17.6$6.2 million in 2007, $24.02010, compensation expense of $1.5 million in 2006,2009, and $7.0a reduction of expense of $3.2 million in 20052008 for these awards. During the 12 months ended December 31, 2007,2010, no performance-based unit awards vested. During the 12 months ended December 31, 2009, no performance-based unit awards vested. During the 12 months ended December 31, 2008, our 20042005 performance-based unit award vested and we paid $19.7$24.2 million in cash to settle the award. As of December 31, 20072010, we had $17.2$11.8 million of unrecognized compensation cost related to the unvested portion of outstanding performance-based unit awards expected to be recognized within a 26-month period.
Equity-Based Grants
We recorded compensation expense of $0.8 million in 2010, $0.9 million in 2007, $0.62009, and $0.9 million in 2006, and $0.5 million in 20052008 related to equity-based grants to members of the Board of Directors.
15Merger and Acquisitions
Subsequent Event—Asset AcquisitionCPower
In February 2008,October 2010, we acquired 100% ownership of CPower, an energy management and demand response provider, for $77.8 million in cash, all of which was paid at closing. CPower designs and manages programs that allow its customers to reduce electricity demand at times of peak usage. We have included CPower's results of operations in our consolidated financial statements as part of our NewEnergy business segment since the Hillabeedate of acquisition.
We recorded the major classes of assets acquired and liabilities assumed as follows:
At October 11, 2010 | | |||
---|---|---|---|---|
| (In millions) | |||
Cash and cash equivalents | $ | 4.9 | ||
Other current assets | 10.8 | |||
Goodwill (1) | 51.5 | |||
Acquired intangible assets (2) | 13.4 | |||
Other assets | 12.0 | |||
Total assets acquired | 92.6 | |||
Total liabilities | (14.8 | ) | ||
Net assets acquired | $ | 77.8 | ||
The pro-forma impact of this acquisition would not have been material to our results of operations for the years ended December 31, 2010, 2009 and 2008.
Boston Generating
In January 2011, we completed the acquisition of Boston Generating's 2,950 MW fleet of generating plants for approximately $1.1 billion, subject to a working capital true-up adjustment. The fleet acquired includes the following four natural gas power plants and one fuel oil plant located in the Boston, Massachusetts area:
Upon signing an asset purchase agreement in August 2010, we deposited $50.0 million into an escrow account and recorded this amount as "Restricted cash—current" on our Consolidated Balance Sheets. This deposit plus interest was applied toward the purchase price at closing in January 2011.
We will account for this acquisition as a business combination, and, beginning in January 2011, we will include these assets and the related results of operations in our Generation business segment.
Texas Combined Cycle Generation Facilities
In May 2010, we acquired 100% ownership of the 550 MW Colorado Bend Energy Center a partially completed 774and the 550 MW Quail Run Energy Center natural gas fired combined-cycle powercombined cycle generation facility locatedfacilities in AlabamaTexas for $155.5 million.$372.9 million, all of which was paid in cash at closing. We plan to completeinclude these facilities as part of our Generation business and have included their results of operations in our consolidated financial statements since the constructiondate of acquisition.
We recorded the major classes of assets acquired and liabilities assumed as follows:
At May 17, 2010 | | |||
---|---|---|---|---|
| (In millions) | |||
Current assets | $ | 7.1 | ||
Property, plant and equipment | 368.6 | |||
Total assets acquired | 375.7 | |||
Current liabilities | (2.8 | ) | ||
Net assets acquired | $ | 372.9 | ||
The pro-forma impact of this facilityacquisition would not have been material to our results of operations for the years ended December 31, 2010, 2009 and expect it2008.
Criterion Wind Project
In April 2010, we acquired 100% ownership of a 70 MW Criterion wind project to be readyconstructed in Garrett County, Maryland. In December 2010, we placed this facility in commercial operation. This wind energy project was developed, constructed, and is owned by our Generation business.
The pro-forma impact of all of the 2010 acquisitions, collectively, would not have been material to our results of operations for commercial operation in early 2010.the years ended December 31, 2010, 2009 and 2008.
CornerstoneCLT Energy Services Group
On July 1, 2007,2009, we acquired Cornerstone100% ownership of CLT Energy Inc (CEI).Services Group, doing business as CLT Efficient Technologies Group (CLT) for $21.9 million, of which $20.8 million was paid in cash at closing. We include CEI,CLT as part of our retail competitive supply operation, in our merchant energyNewEnergy business segment and have included its results of operations in our consolidated financial statements since the date of acquisition. CEICLT is an energy services company that provides natural gas supplyenergy performance contracting and related services to commercial, industrial and institutional customers across the central United States. CEI is expected to add approximately 100 billion cubic feetenergy efficiency engineering services.
156
Table of natural gas to our annual volumes served.
We acquired 100% ownership for $108.3 million, which was paid in cash. As part of the purchase, we acquired $7.3 million in cash.
The total consideration for accounting purposes, consisting of cash and other noncash consideration, including the fair value of certain preexisting contracts with CEI, was equal to $137.6 million.Contents
Our final purchase price allocation for the net assets acquiredrelated to CLT is as follows:
At July 1, 2007 | | |||
---|---|---|---|---|
| (In millions) | |||
Cash | $ | 7.3 | ||
Other Current Assets | 89.6 | |||
Total Current Assets | 96.9 | |||
Goodwill (1) | 103.4 | |||
Net Property, Plant and Equipment | 0.5 | |||
Other Assets | 6.7 | |||
Total Assets Acquired | 207.5 | |||
Current Liabilities | (66.3 | ) | ||
Deferred Credits and Other Liabilities | (3.6 | ) | ||
Total Liabilities | (69.9 | ) | ||
Net Assets Acquired | $ | 137.6 | ||
At July 1, 2009 | | |||
---|---|---|---|---|
| (In millions) | |||
Current assets | $ | 5.7 | ||
Goodwill (1) | 18.6 | |||
Other assets | 2.3 | |||
Total assets acquired | 26.6 | |||
Current liabilities | (4.7 | ) | ||
Net assets acquired | $ | 21.9 | ||
The pro-forma impact of the CEICLT acquisition would not have been material to our results of operations for the years ended December 31, 2007, 20062009, 2008, and 2005.2007.
Acquisitions
157
Table of Working Interests in Gas Producing Fields
In 2007, we acquired working interests of 41% and 55% in two gas and oil producing properties in Oklahoma for $208.9 million, subject to closing adjustments. We purchased leases, producing wells, inventory, and related equipment. We have included the results of operations from these properties in our merchant energy business segment since the date of acquisition.
Our purchase price was allocated to the net assets acquired as follows:
At March 23, 2007 | | |||
---|---|---|---|---|
| (In millions) | |||
Property, Plant and Equipment | ||||
Inventory | $ | 0.2 | ||
Unproved property | 28.8 | |||
Proved property | 179.9 | |||
Net Assets Acquired | $ | 208.9 | ||
The pro-forma impact of the acquisition of these working interests would not have been material to our results of operations for the years ended December 31, 2007, 2006 and 2005.
In the first quarter of 2006, we acquired working interests in gas and oil producing properties for approximately $100 million in cash. We purchased leases, producing wells, and related equipment. We have included the results of operations in our merchant energy business segment since the date of acquisition.
Termination of Merger Agreement with FPL Group, Inc.Contents
On October 24, 2006, 16 Related Party Transactions
Constellation Energy
CENG
On November 6, 2009, upon the sale of a membership interest in CENG, our nuclear generation and FPL Group agreedoperation business, to terminateEDF, we deconsolidated CENG and began accounting for our 50.01% membership interest in CENG as an equity method investment. On November 3, 2010, we closed on a comprehensive agreement with EDF that restructures the Agreement and Plan of Merger the parties had entered into on December 18, 2005.relationship between our two companies.
In connection with the terminationclosing of the merger2009 transaction with EDF, we entered into a power purchase agreement (PPA) with CENG with an initial fair value of $0.8 billion under which we will purchase between 85-90% of the output of CENG's nuclear plants that is not sold to third parties under pre-existing PPAs over the five year term of the PPA. As part of the 2010 comprehensive agreement with EDF, the PPA was modified to be unit contingent for prospective trades beginning in November 2010 through the end of its term in 2014. In addition, beginning on January 1, 2015 and continuing to the end of the life of the respective plants, we will purchase 50.01% of the output of CENG's nuclear plants, and EDF will purchase 49.99% of that output.
In addition to the PPA, in 2009 we entered into a power services agency agreement (PSA) and an administrative service agreement (ASA). The PSA is a five-year agreement under which we will provide scheduling, asset management and billing services to CENG and recognize average annual revenue of approximately $16 million. The ASA was initially a one year agreement that was renewable annually. Under the ASA, we provided administrative support services to CENG for a fee of approximately $66 million for 2010. The fees for administrative support services are subject to change in future years based on the level of services provided. The fee for 2011 will be approximately $48 million. The charges under this agreement are intended to represent the actual cost of the services provided to CENG by us. As part of the 2010 comprehensive agreement with EDF, the ASA was extended through 2017 to include a consumption-based pricing structure in addition to the fixed-price structure.
The impact of transactions under these agreements is summarized below:
Agreement | Amount Recognized in Earnings for the Year Ended December 31, 2010 | Amount Recognized in Earnings for the Period from November 6, 2009 through December 31, 2009 | Income Statement Classification | Accounts Receivable/ (Accounts Payable) at December 31, 2010 | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
(In millions) | ||||||||||||
PPA | $ | 900.8 | $ | 122.5 | Fuel and purchased energy expenses | $ | (47.6 | ) | ||||
PSA | (16.1 | ) | (2.7 | ) | Nonregulated revenues | — | ||||||
ASA | (66.0 | ) | (10.0 | ) | Operating expenses | 5.5 |
UNE
We sold our interest in UNE during 2010. We discuss this transaction in more detail inNote 4.
CEP
On March 31, 2008, our NewEnergy business sold its working interest in 83 oil and natural gas producing wells in Oklahoma to CEP, an equity method investment of Constellation Energy, acquired certain development rights from FPL Group relating tofor total proceeds of approximately $53 million. Our NewEnergy business recognized a wind power project$14.3 million gain, net of the minority interest gain of $0.7 million on the sale and exclusive of our 28.5% ownership interest in Western Maryland. During 2007, we wrote-offCEP. This gain is recorded in "Gains on Sales of Assets" in our investment in these development rights. SeeNote 2 for further detail.
We incurred merger costs during the year ended December 31, 2006 totaling $18.3 million pre-tax. Our total pre-tax merger-related costs were $35.3 million.
16Related Party Transactions—BGEConsolidated Statements of Income (Loss).
BGE—Income Statement
BGE is obligated to provide market-based standard offer service to all of its electric customers for varying periods. Bidding to supply BGE's market-based standard offer service to electric customers will occur from time to time through a competitive bidding process approved by the Maryland PSC.
Our wholesale marketing, risk management, and trading operation supplied a substantial portion of BGE's market-based standard offer service obligation to residential electric customers through May 31, 2007, andNewEnergy business will supply a portion of BGE's market-based standard offer service obligations for allobligation to electric customers from June 1, 2007 through May 31, 2009.2013.
The cost of BGE's purchased energy from nonregulated subsidiaries of Constellation Energy to meet its standard offer service obligation was as follows:
Year Ended December 31, | 2007 | 2006 | 2005 | ||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Electricity purchased for resale expenses | $ | 1,139.6 | $ | 1,062.0 | $ | 805.9 |
Year Ended December 31, | 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Electricity purchased for resale expenses | $ | 428.0 | $ | 623.5 | $ | 802.0 | ||||
In addition, Constellation Energy charges BGE for the costs of certain corporate functions. CertainThese costs are directly assigned to BGE. We allocate other corporate functioncomprised of direct charges as well as costs that are allocated 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. Under the Maryland PSC's October 30, 2009 order approving the transaction with EDF, we are limited to allocating no more than 31% of these costs to BGE.
The following table presents all of the costs Constellation Energy charged to BGE in each period.period, both directly-charged and allocated.
Year ended December 31, | 2007 | 2006 | 2005 | ||||||
---|---|---|---|---|---|---|---|---|---|
| (In millions) | ||||||||
Charges to BGE | $ | 160.8 | $ | 148.8 | $ | 130.3 |
Year ended December 31, | 2010 | 2009 | 2008 | |||||||
---|---|---|---|---|---|---|---|---|---|---|
| (In millions) | |||||||||
Charges to BGE | $ | 184.8 | $ | 164.7 | $ | 153.6 | ||||
Other nonregulated affiliates of BGE also charge BGE for the costs of certain services provided.
158
BGE—Balance Sheet
Through January 7, 2010, BGE participatesparticipated 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. Under this arrangement, BGE had invested $78.4$314.7 million at December 31, 2007 and $60.6 million at December 31, 2006.2009.
As part of the ring-fencing measures required by the Maryland PSC in its order approving the transaction with EDF, BGE ceased participation in the cash pool on January 7, 2010.
BGE's Consolidated Balance Sheets include intercompany 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, Constellation Energy and its nonregulated affiliates' charges to BGE, and the participation of BGE's employees in the Constellation Energy defined benefit plans.
We believe our allocation methods are reasonable and approximate the costs that would be charged to unaffiliated entities.
159
17Quarterly Financial Data (Unaudited)
Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair statement. Our business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.
2007 Quarterly Data—Constellation Energy | | 2007 Quarterly Data—BGE | ||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenues | Income from Operations | Income from Continuing Operations | Earnings Applicable to Common Stock | Earnings Per Share from Continuing Operations- Diluted | Earnings Per Share of Common Stock- Diluted | | | Revenues | Income from Operations | Earnings Applicable to Common Stock | |||||||||||||||||||
| ||||||||||||||||||||||||||||||
| (In millions, except per share amounts) | | | (In millions) | ||||||||||||||||||||||||||
Quarter Ended | Quarter Ended | |||||||||||||||||||||||||||||
March 31 | $ | 5,111.1 | $ | 302.4 | $ | 197.3 | $ | 195.7 | $ | 1.08 | $ | 1.07 | March 31 | $ | 922.1 | $ | 136.0 | $ | 66.0 | |||||||||||
June 30 | 4,876.3 | 154.4 | 116.3 | 116.3 | 0.64 | 0.64 | June 30 | 707.1 | 50.5 | 13.6 | ||||||||||||||||||||
September 30 | 5,856.4 | 425.1 | 250.7 | 251.4 | 1.37 | 1.38 | September 30 | 896.9 | 66.5 | 24.4 | ||||||||||||||||||||
December 31 | 5,349.4 | 452.5 | 258.1 | 258.1 | 1.42 | 1.42 | December 31 | 892.4 | 81.3 | 22.6 | ||||||||||||||||||||
Year Ended | Year Ended | |||||||||||||||||||||||||||||
December 31 | $ | 21,193.2 | $ | 1,334.4 | $ | 822.4 | $ | 821.5 | $ | 4.51 | $ | 4.50 | December 31 | $ | 3,418.5 | $ | 334.3 | $ | 126.6 | |||||||||||
2010 Quarterly Data—Constellation Energy | | | | | | |||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | | | Net Income (Loss) Attributable to Common Stock | | | 2010 Quarterly Data—BGE | |||||||||||||||||||||||||||
| Revenues | Income (Loss) from Operations | Net Income (Loss) | Earnings (Loss) Per Share from Operations— Diluted | Earnings (Loss) Per Share of Common Stock— Diluted | | Revenues | Income from Operations | Net Income | Net Income Attributable to Common Stock | ||||||||||||||||||||||||
| (In millions, except per share amounts) | | (In millions) | |||||||||||||||||||||||||||||||
Quarter Ended | Quarter Ended | |||||||||||||||||||||||||||||||||
March 31 | $ | 3,586.6 | $ | 415.1 | $ | 191.3 | $ | 191.5 | $ | 0.95 | $ | 0.95 | March 31 | $ | 1,069.3 | $ | 136.9 | $ | 64.4 | $ | 61.1 | |||||||||||||
June 30 | 3,309.9 | 181.9 | 83.8 | 72.6 | 0.36 | 0.36 | June 30 | 751.5 | 55.9 | 17.0 | 13.7 | |||||||||||||||||||||||
September 30 | 3,968.9 | (2,246.7 | ) | (1,375.0 | ) | (1,406.5 | ) | (6.99 | ) | (6.99 | ) | September 30 | 856.1 | 75.6 | 31.8 | 28.5 | ||||||||||||||||||
December 31 | 3,474.6 | 406.7 | 168.1 | 159.8 | 0.79 | 0.79 | December 31 | 784.8 | 85.8 | 34.4 | 31.1 | |||||||||||||||||||||||
Year Ended | Year Ended | |||||||||||||||||||||||||||||||||
December 31 | $ | 14,340.0 | $ | (1,243.0 | ) | $ | (931.8 | ) | $ | (982.6 | ) | $ | (4.90 | ) | $ | (4.90 | ) | December 31 | $ | 3,461.7 | $ | 354.2 | $ | 147.6 | $ | 134.4 | ||||||||
The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and dilution as a result of issuing common shares during the year. Constellation Energy revenues for the quarter ended March 31, 2007 and June 30, 2007 have been reclassified to conform with the current presentation.dilution.
First quarter results include:
Second quarter results include:
Third quarter results include:
Fourth quarter results include:
We discuss these items inNote 2.
2006 Quarterly Data—Constellation Energy | | | | | | |||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | | | | Earnings Per Share from Continuing Operations- Diluted | | | | | | | |||||||||||||||||||
| | | | Earnings Applicable to Common Stock | Earnings Per Share of Common Stock- Diluted | | 2006 Quarterly Data—BGE | |||||||||||||||||||||||
| Revenues | Income from Operations | Income from Continuing Operations | | | Revenues | Income from Operations | Earnings Applicable to Common Stock | ||||||||||||||||||||||
| ||||||||||||||||||||||||||||||
| (In millions, except per share amounts) | | | (In millions) | ||||||||||||||||||||||||||
Quarter Ended | Quarter Ended | |||||||||||||||||||||||||||||
March 31 | $ | 4,859.2 | $ | 204.0 | $ | 101.6 | $ | 113.9 | $ | 0.56 | $ | 0.63 | March 31 | $ | 924.2 | $ | 141.1 | $ | 68.4 | |||||||||||
June 30 | 4,378.8 | 178.3 | 74.0 | 93.1 | 0.41 | 0.52 | June 30 | 642.3 | 58.5 | 18.4 | ||||||||||||||||||||
September 30 | 5,393.4 | 530.9 | 306.4 | 324.4 | 1.69 | 1.79 | September 30 | 764.5 | 83.0 | 35.6 | ||||||||||||||||||||
December 31 | 4,653.5 | 420.3 | 266.6 | 405.0 | 1.46 | 2.22 | December 31 | 684.4 | 86.5 | 34.7 | ||||||||||||||||||||
Year Ended | Year Ended | |||||||||||||||||||||||||||||
December 31 | $ | 19,284.9 | $ | 1,333.5 | $ | 748.6 | $ | 936.4 | $ | 4.12 | $ | 5.16 | December 31 | $ | 3,015.4 | $ | 369.1 | $ | 157.1 | |||||||||||
160
2009 Quarterly Data—Constellation Energy | 2009 Quarterly Data—BGE | |||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenues | Income (Loss) from Operations | Net Income (Loss) | Net Income Attributable to Common Stock | Earnings (Loss) Per Share from Operations— Diluted | Earnings (Loss) Per Share of Common Stock— Diluted | | Revenues | Income (Loss) from Operations | Net Income | Net Income Attributable to Common Stock | |||||||||||||||||||||||
| (In millions, except per share amounts) | | (In millions) | |||||||||||||||||||||||||||||||
Quarter Ended | Quarter Ended | |||||||||||||||||||||||||||||||||
March 31 | $ | 4,303.4 | $ | (212.1 | ) | $ | (119.7 | ) | $ | (123.5 | ) | $ | (0.62 | ) | $ | (0.62 | ) | March 31 | $ | 1,193.7 | $ | 168.7 | $ | 85.0 | $ | 81.7 | ||||||||
June 30 | 3,864.1 | 230.6 | 28.3 | 8.1 | 0.04 | 0.04 | June 30 | 767.4 | 54.3 | 16.0 | 12.7 | |||||||||||||||||||||||
September 30 | 4,027.7 | 534.3 | 167.4 | 137.6 | 0.69 | 0.69 | September 30 | 866.5 | 78.7 | 32.3 | 28.6 | |||||||||||||||||||||||
December 31 | 3,403.6 | 7,428.2 | 4,427.4 | 4,421.2 | 21.96 | 21.96 | December 31 | 751.4 | (33.3 | ) | (42.6 | ) | (38.2 | ) | ||||||||||||||||||||
Year Ended | Year Ended | |||||||||||||||||||||||||||||||||
December 31 | $ | 15,598.8 | $ | 7,981.0 | $ | 4,503.4 | $ | 4,443.4 | $ | 22.19 | $ | 22.19 | December 31 | $ | 3,579.0 | $ | 268.4 | $ | 90.7 | $ | 84.8 | |||||||||||||
The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding and dilution as a result of issuing common shares during the year.dilution.
First quarter results include:
Second quarter results include:
Third quarter results include:
Fourth quarter results include:
161
We discuss these items inNote 2.
162
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Items 9A and 9A(T).Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The principal executive officersofficer and principal financial officer of both Constellation Energy and BGE have each 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 December 31, 20072010 (the "Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, Constellation Energy's disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in the reports that Constellation Energy files and submits under the Exchange Act is recorded, processed, summarized, and reported when required and is accumulated and communicated to management, as appropriate, to allow timely decisions regarding required disclosure.
The principal executive officer and principal financial officer of BGE have each evaluated the effectiveness of BGE's disclosure controls and procedures as of the Evaluation Date. Based on such evaluation, such officers have concluded that, as of the Evaluation Date, BGE's disclosure controls and procedures are effective.effective in providing reasonable assurance that information required to be disclosed in the reports that BGE files and submits under the Exchange Act is recorded, processed, summarized, and reported when required and is accumulated and communicated to management, as appropriate, to allow timely decisions regarding required disclosure.
Internal Control Over Financial Reporting
Each of Constellation Energy and BGE maintains a system of internal control over financial reporting as defined in Exchange Act Rule 13a-15(f). The Management's Reports on Internal Control Over Financial Reporting of each of Constellation Energy and BGE are included inItem 8. Financial Statements and Supplementary Data included in this report. As BGE is not an accelerated filer as defined in Exchange Act Rule 12b-2, its Management's Report on Internal Control Over Financial Reporting is not deemed to be filed for purposes of Section 18 of the Exchange Act as permitted by the rules and regulations of the Securities and Exchange Commission.
Changes in Internal Control
During the quarter ended December 31, 2007,2010, 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.
None.
BGE meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, all items in this section related to BGE are not presented.
Item 10. Directors, and Executive Officers of the Registrantand Corporate Governance
The information required by this item with respect to directors and corporate governance will be set forth underProposal No. 1: Election of Directors in the Proxy Statement and incorporated herein by reference.
The information required by this item with respect to executive officers of Constellation Energy, Group, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, is set forth followingItem 4 of Part I of this Form 10-K underExecutive Officers of the Registrant.
Item 11. Executive Compensation
The information required by this item will be set forth underExecutive and Director Compensation andReport of Compensation Committee in the Proxy Statement and incorporated herein by reference.
163
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
The additional information required by this item will be set forth underStock Ownership in the Proxy Statement and incorporated herein by reference.
Equity Compensation Plan Information
The following table reflects our equity compensation plan information as of December 31, 2007:2010:
| (a) | (b) | (c) | ||||
---|---|---|---|---|---|---|---|
Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants, and rights | Weighted-average exercise price of outstanding options, warrants, and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in item (a)) | ||||
| (In thousands) | | (In thousands) | ||||
Equity compensation plans approved by security holders | 5,097 | $ | 58.79 | 9,245 | |||
Equity compensation plans not approved by security holders | 1,048 | $ | 41.83 | — | |||
Total | 6,145 | $ | 55.90 | 9,245 | |||
| (a) | (b) | (c) | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants, and rights | Weighted-average exercise price of outstanding options, warrants, and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in item (a)) | |||||||
| (In thousands) | | (In thousands) | |||||||
Equity compensation plans approved by security holders | 8,451 | $ | 43.44 | 12,818 | ||||||
Equity compensation plans not approved by security holders | 619 | $ | 43.20 | — | ||||||
Total | 9,070 | $ | 43.43 | 12,818 | ||||||
The plans that do not require shareholder approval are the Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan (Designated as Exhibit No. 10(p)10(j)) and the Constellation Energy Group, Inc. Management Long-Term Incentive Plan (Designated as Exhibit No. 10(q)10(k)). A brief description of the material features of each of these plans is set forth below.
2002 Senior Management Long-Term Incentive Plan
The 2002 Senior Management Long-Term Incentive Plan became effective May 24, 2002 and authorized the issuance of up to 4,000,000 shares of Constellation Energy common stock in connection with the grant of equity awards. No further awards will be made under this plan. Any shares covered by an outstanding award that is forfeited or cancelled, expires or is settled in cash will become available for issuance under the shareholder-approved Amended and Restated 2007 Long-Term Incentive Plan. Shares delivered pursuant to awards under this plan may be authorized and unissued shares or shares purchased on the open market in accordance with the applicable securities laws. Restricted stock, restricted stock unit, and performance unit award payouts will be accelerated and stock options and stock appreciation rights gains will be paid in cash in the event of a change in control, as defined in the plan. The plan is administered by Constellation Energy's Chief Executive Officer.
Management Long-Term Incentive Plan
The Management Long-Term Incentive Plan became effective February 1, 1998 and authorized the issuance of up to 3,000,000 shares of Constellation Energy common stock in connection with the grant of equity awards. No further awards will be made under this plan. Any shares covered by an outstanding award that is forfeited or cancelled, expires or is settled in cash will become available for issuance under the shareholder-approved Amended and Restated 2007 Long-Term Incentive Plan. Shares delivered pursuant to awards under the plan may be authorized and unissued shares or shares purchased on the open market in accordance with applicable securities laws. Restricted stock, restricted stock units, and performance unit award payouts will be accelerated and stock options and stock appreciation rights will become fully exercisable in the event of a change in control, as defined by the plan. The plan is administered by Constellation Energy's Chief Executive Officer.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The additional information required by this item will be set forth underRelated Persons Transactions andDetermination of Independence in the Proxy Statement and incorporated herein by reference.
Item 14. Principal Accountant Fees and Services
The information required by this item will be set forth underRatification of PricewaterhouseCoopers LLP as Independent Registered Public Accounting Firm for 20082011 in the Proxy Statement and incorporated herein by reference.
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as a part of this Report: | |||
1. | Financial Statements: | ||
Reports of Independent Registered Public Accounting Firm dated | |||
Consolidated Statements of | |||
Consolidated Balance Sheets—Constellation Energy Group at December 31, | |||
Consolidated Statements of Cash Flows—Constellation Energy Group for three years ended December 31, | |||
Consolidated Statements of Common Shareholders' Equity and Comprehensive | |||
Consolidated Statements of Income—Baltimore Gas and Electric Company for three years ended December 31, | |||
Consolidated Balance Sheets—Baltimore Gas and Electric Company at December 31, | |||
Consolidated Statements of Cash Flows—Baltimore Gas and Electric Company for three years ended December 31, | |||
Notes to Consolidated Financial Statements | |||
2. | Financial Statement Schedules: | ||
Schedule II—Valuation and Qualifying Accounts | |||
Schedules other than Schedule II are omitted as not applicable or not required. | |||
3. | Exhibits Required by Item 601 of Regulation S-K. |
Exhibit Number | |||||
---|---|---|---|---|---|
*2 | (a) | — | Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.) | ||
*2 | (b) | — | Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.) | ||
*2 | (c) | — | Asset Purchase | ||
(d) | — | ||||
*2 | (e) | — | Put Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., Constellation Nuclear, LLC, and Constellation Energy Nuclear Group, LLC. (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated November 8, 2010, File No. 1-12869.) | ||
*3 | — | Articles Supplementary to the Charter of Constellation Energy Group, Inc. | |||
*3 | (b) | — | Correction to Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 25, 2008. (Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 2008, File Nos. 1-12869 and 1-1910.) | ||
*3 | (c) | — | Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of September 19, 2008. (Designated as Exhibit No. 3.1 to the Current Report on Form 8-K dated September 19, 2008, File No. 1-12869.) |
165
Exhibit Number | |||||
---|---|---|---|---|---|
*3 | (d) | — | Articles of Amendment to the Charter of Constellation Energy Group, Inc. as of July | ||
*3 | — | Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of April 10, 2007. (Designated as Exhibit 3(a) to the Current Report on Form 8-K dated April 10, 2007, File No. 1-12869.) | |||
*3 | (f) | — | Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001. (Designated as Exhibit No. 3(e) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.) | ||
*3 | (g) | — | Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999. (Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.) |
*3 | — | Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999. (Designated as Exhibit No. 99.1 to the Current Report on Form 8-K dated July 19, 1999, File Nos. 1-12869 and 1-1910.) | |||
*3 | (i) | — | Amended and Restated Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Appendix B to Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed March 3, 1999, File No. 33-64799.) | ||
*3 | (j) | — | Bylaws of Constellation Energy Group, Inc., as amended to July 18, 2008. (Designated as Exhibit No. 3 to the Current Report on Form 8-K dated July 18, 2008, File No. 1-12869.) | ||
*3 | (k) | — | Articles of Amendment to the Charter of BGE as of February 2, 2010. (Designated as Exhibit No. 3.1 to the Current Report on Form 8-K dated February 4, 2010, File No. 1-1910.) | ||
*3 | (l) | — | Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, File No. 1-1910.) | ||
*3 | — | Bylaws of BGE, as amended to | |||
*4 | (a) | — | Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 dated March 29, 1999, File No. 333-75217.) | ||
*4 | (b) | — | First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003, File No. 333-102723.) | ||
*4 | (c) | — | Indenture dated as of July 24, 2006 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 filed July 24, 2006, File No. 333-135991.) | ||
*4 | (d) | — | First Supplemental Indenture between | ||
*4 | (e) | — | Indenture dated June 19, 2008 between Constellation Energy Group, Inc. and | ||
*4 | — | Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and | |||
*4 | — | Form of Subordinated Indenture between |
166
Exhibit Number | |||||
---|---|---|---|---|---|
*4 | — | Form of Supplemental Indenture between | |||
*4 | — | Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.) | |||
*4 | — | Form of Junior Subordinated Debenture (Designated as Exhibit | |||
*4 | — | Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.) | |||
*4 | — | Indenture dated as of July 24, 2006 between | |||
*4 | — | First Supplemental Indenture between | |||
*4 | — | Indenture and Security Agreement dated as of July 9, 2009, between BGE and Deutsche Bank Trust Company Americas, as trustee (including form of BGE Officer's Certificate and form of Senior Secured Bond) (Designated as Exhibit Nos. 4(u) and 4(u)(1) to Post-Effective Amendment No. 1 to the Registration Statement on Form S-3 dated July 9, 2009, File Nos. 333-157637 and 333-157637-01.) | |||
*4 | (o) | — | Supplemental Indenture No. 1, dated as of October 1, 2009, to the Indenture and Security Agreement dated as of July 9, 2009, between BGE and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(c) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File Nos. 1-12869 and 1-1910.) | ||
*4 | (p) | — | BGE Deed of Easement and Right-of-Way Grant dated as of July 9, 2009 (Designated as Exhibit No. 4(u)(2) to Post-Effective Amendment No. 1 to the Registration Statement on Form S-3 dated July 9, 2009, File Nos. 333-157637 and 333-157637-01.) | ||
*4 | (q) | — | Indenture dated as of June 29, 2007, by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary. (Designated as Exhibit 4.1 to the Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.) | ||
*4 | — | Series Supplement to Indenture dated as of June 29, 2007 by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary (Designated as Exhibit | |||
*4 | (s) | — | Replacement Capital Covenant dated June 27, 2008. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated | ||
*4 | (t) | — | Officers' Certificate, dated December 14, 2010, establishing the 5.15% Notes due December 1, 2020 of Constellation Energy Group, Inc., with the form of Notes attached thereto. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated December 14, 2010, File No. 1-12869.) | ||
+*10 | (a) | — | Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated. (Designated as Exhibit No. 10(d) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File Nos. 1-12869 and 1-1910.) | ||
+*10 | (b) | — | Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 2008, File Nos. 1-12869 and 1-1910.) | ||
*10 | (c) | — | Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K for the year ended December 31, 2008, File Nos. 1-12869 and 1-1910.) |
167
Exhibit Number | |||||
---|---|---|---|---|---|
+*10 | (d) | — | Constellation Energy Group, Inc. Benefits Restoration Plan, amended and restated effective June 1, 2010. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File Nos. 1-12869 and 1-1910.) | ||
+*10 | (e) | — | Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated. (Designated as Exhibit No. 10(e) to the Annual Report on Form 10-K for the year ended December 31, 2008, File Nos. 1-12869 and 1-1910.) | ||
+*10 | (f) | — | Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated. (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended December 31, 2008, File Nos. 1-12869 and 1-1910.) | ||
+*10 | (g) | — | Constellation Energy Group, Inc. Executive Supplemental Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(a) to the Quarterly Report on Form 10-Q for the quarter ended | ||
+*10 | — | Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.) | |||
+*10 | (i) | ||||
— | Constellation Energy Group, Inc. Executive Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.) |
+*10 | |||||
— | Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(c) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.) | ||||
+*10 | — | Constellation Energy Group, Inc. Management Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(d) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.) | |||
+*10 | |||||
— | Constellation Energy Group, Inc. Amended and Restated 2007 Long-Term Incentive Plan. (Designated as Exhibit | ||||
+*10 | — | ||||
+*10 | — | ||||
+*10 | — | Consent of Henry B. Barron, Jr. to termination of change-in-control agreement. (Designated as Exhibit No. 10.3 to the Current Report on Form 8-K dated December 10, 2009, File No. 1-12869.) | |||
*10 | (p) | — | Rate Stabilization Property | ||
*10 | — | Administration Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as administrator (Designated as Exhibit 10.3 to the Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.) | |||
*10 | — | Second Amended and | |||
10 | (s) | — | Amendment No. 1 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. | ||
10 | (t) | — | Amendment No. 2 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. |
168
Exhibit Number | |||||
---|---|---|---|---|---|
*10 | (u) | — | Amendment No. 3 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated November 3, 2010, File No. 1-12869.) | ||
*10 | (v) | — | Credit Agreement, dated as of October 15, 2010, among Constellation Energy Group, Inc., Bank of America, N.A., as a letter of credit issuing bank, swingline lender and administrative agent, Banc of America Securities LLC, Citigroup Global Markets Inc., RBS Securities Inc., BNP Paribas Securities Corp., and The Bank of Nova Scotia, as joint lead arranger and book runners, Citibank, N.A. and The Royal Bank of Scotland plc, as co-syndication agents and The Bank of Nova Scotia and BNP Paribas, as co-documentation agents and the other lenders named therein. (Designated as Exhibit 10.1 to the Current Report on Form 8-K dated October 21, 2010, File No. 1-12869.) | ||
*10 | (w) | — | Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., and Constellation Energy Group, Inc. (Designated as Exhibit No. 10.2 to the Current Report on Form 8-K dated November 3, 2010, File No. 1-12869.) | ||
+10 | (x) | — | Form of Grant Agreement for Stock Units with Sales Restriction. | ||
12 | (a) | — | Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges. | ||
12 | (b) | — | Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. | ||
21 | — | Subsidiaries of the Registrant. | |||
23 | (a) | — | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm. | ||
23 | (b) | — | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm (for Constellation Energy Nuclear Group, LLC). | ||
31 | (a) | — | Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
31 | (b) | — | Certification of | ||
31 | (c) | — | Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31 | (d) | — | Certification of | ||
32 | (a) | — | Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
32 | (b) | — | Certification of | ||
32 | (c) | — | Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
32 | (d) | — | Certification of | ||
99 | (a) | — | Audited Financial Statements of Constellation Energy Nuclear Group, LLC. | ||
*99 | (b) | — | Operating Agreement, dated as of February 4, 2010, by and among RF HoldCo LLC, Constellation Energy Group, Inc. and GSS Holdings (BGE Utility), Inc. (Designated as Exhibit No. 99.1 to the Current Report on Form 8-K dated February 4, 2010, File Nos. 1-12869 and 1-1910.) |
169
Exhibit Number | |||||
---|---|---|---|---|---|
*99 | (c) | — | Contribution Agreement, dated as of February 4, 2010, by and among Constellation Energy Group, Inc., BGE and RF HoldCo LLC. (Designated as Exhibit No. 99.2 to the Current Report on Form 8-K dated February 4, 2010, File Nos. 1-12869 and 1-1910.) | ||
*99 | (d) | — | Purchase Agreement, dated as of February 4, 2010, by and between RF HoldCo LLC and GSS Holdings (BGE Utility), Inc. (Designated as Exhibit No. 99.3 to the Current Report on Form 8-K dated February 4, 2010, File Nos. 1-12869 and 1-1910.) | ||
101 | .INS | — | XBRL Instance Document | ||
101 | .SCH | — | XBRL Taxonomy Extension Schema Document | ||
101 | .PRE | — | XBRL Taxonomy Presentation Linkbase Document | ||
101 | .LAB | — | XBRL Taxonomy Label Linkbase Document | ||
101 | .CAL | — | XBRL Taxonomy Calculation Linkbase Document | ||
101 | .DEF | — | XBRL Taxonomy Definition Linkbase Document |
In accordance with Rule 402 of Regulation S-T, the XBRL related information in Exhibit 101 to this Annual Report on Form 10-K shall not be deemed to be "filed" for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
AND
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
Column A | Column B | Column C | Column D | Column E | ||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Additions | | | ||||||||||||||
Description | Balance at beginning of period | Charged to costs and expenses | Charged to Other Accounts— Describe | (Deductions)— Describe | Balance at end of period | |||||||||||||
| (In millions) | |||||||||||||||||
Reserves deducted in the Balance Sheet from the assets to which they apply: | ||||||||||||||||||
Constellation Energy | ||||||||||||||||||
Accumulated Provision for Uncollectibles | ||||||||||||||||||
2007 | $ | 48.9 | $ | 31.3 | $ | — | $ | (35.3) | (A) | $ | 44.9 | |||||||
2006 | 47.4 | 29.7 | — | (28.2) | (A) | 48.9 | ||||||||||||
2005 | 43.1 | 30.9 | — | (26.6) | (A) | 47.4 | ||||||||||||
Valuation Allowance | ||||||||||||||||||
Net unrealized (gain) loss on available for sale securities | ||||||||||||||||||
2007 | (18.5 | ) | — | 1.2 | (B) | — | (17.3 | ) | ||||||||||
2006 | 0.6 | — | (19.1) | (B) | — | (18.5 | ) | |||||||||||
2005 | 0.1 | — | 0.5 | (B) | — | 0.6 | ||||||||||||
Net unrealized (gain) loss on nuclear decommissioning trust funds | ||||||||||||||||||
2007 | (206.1 | ) | — | (50.6) | (B) | — | (256.7 | ) | ||||||||||
2006 | (110.3 | ) | — | (95.8) | (B) | — | (206.1 | ) | ||||||||||
2005 | (73.3 | ) | — | (37.0) | (B) | — | (110.3 | ) | ||||||||||
BGE | ||||||||||||||||||
Accumulated Provision for Uncollectibles | ||||||||||||||||||
2007 | 16.1 | 21.0 | — | (16.0) | (A) | 21.1 | ||||||||||||
2006 | 13.0 | 18.1 | — | (15.0) | (A) | 16.1 | ||||||||||||
2005 | 13.0 | 14.1 | — | (14.1) | (A) | 13.0 |
Column A | Column B | Column C | Column D | Column E | ||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Additions | | | ||||||||||||||
Description | Balance at beginning of period | Charged to costs and expenses | Charged to Other Accounts— Describe | (Deductions)— Describe | Balance at end of period | |||||||||||||
| (In millions) | |||||||||||||||||
Reserves deducted in the Balance Sheet from the assets to which they apply: | ||||||||||||||||||
Constellation Energy | ||||||||||||||||||
Accumulated Provision for Uncollectibles | ||||||||||||||||||
2010 | $ | 160.6 | $ | 76.2 | $ | 27.6 | (B) | $ | (91.5 | )(C) | $ | 172.9 | ||||||
2009 | 240.6 | 71.2 | (5.0 | )(A) | (146.2 | )(C) | 160.6 | |||||||||||
2008 | 44.9 | 127.1 | 102.3 | (B) | (33.7 | )(C) | 240.6 | |||||||||||
Valuation Allowance | ||||||||||||||||||
Net unrealized (gain) loss on available for sale securities | ||||||||||||||||||
2010 | (2.8 | ) | — | (0.1 | )(D) | — | (2.9 | ) | ||||||||||
2009 | 2.1 | (3.6 | ) | (1.3 | )(D) | — | (2.8 | ) | ||||||||||
2008 | (17.3 | ) | 7.0 | 0.3 | (D) | 12.1 | (E) | 2.1 | ||||||||||
Net unrealized (gain) loss on nuclear decommissioning trust funds | ||||||||||||||||||
2010 | — | — | — | — | — | |||||||||||||
2009 | (49.6 | ) | — | (201.0 | )(D) | 250.6 | (F) | — | ||||||||||
2008 | (256.7 | ) | — | 207.1 | (D) | — | (49.6 | ) | ||||||||||
BGE | ||||||||||||||||||
Accumulated Provision for Uncollectibles | ||||||||||||||||||
2010 | 47.2 | 45.6 | — | (56.9 | )(C) | 35.9 | ||||||||||||
2009 | 34.2 | 41.8 | — | (28.8 | )(C) | 47.2 | ||||||||||||
2008 | 21.1 | 34.5 | — | (21.4 | )(C) | 34.2 |
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Constellation Energy Group, Inc., the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC. (REGISTRANT) | ||||||||||
Date: | By | /s/ | MAYO A. SHATTUCK III | |||||||
Mayo A. Shattuck III Chairman of the Board, President and Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Constellation Energy Group, Inc., the Registrant, and in the capacities and on the dates indicated.
Signature | Title | Date | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Principal executive officer and director: | ||||||||||||
By | /s/ | M. A. Shattuck III | Chairman of the Board, President, Chief Executive Officer, and Director | |||||||||
| M. A. Shattuck III | | | |||||||||
Principal financial officer: | ||||||||||||
By | Senior Vice President and Chief Financial Officer | March 1, 2011 | ||||||||||
| J. | | | |||||||||
Principal accounting officer: | ||||||||||||
By | Vice President, Chief Accounting Officer, and Controller | March 1, 2011 | ||||||||||
| | | ||||||||||
Directors: | ||||||||||||
/s/ | ||||||||||||
Y. C. de Balmann | Director | March 1, 2011 | ||||||||||
Y. C. de Balmann | ||||||||||||
/s/ | A. | Director | ||||||||||
A. C. Berzin | ||||||||||||
/s/ | J. T. Brady | Director | ||||||||||
J. T. Brady | ||||||||||||
/s/ | J. R. Curtiss | Director | ||||||||||
/s/ | ||||||||||||
F. A. Hrabowski, III | Director | March 1, 2011 | ||||||
---|---|---|---|---|---|---|---|---|
F. A. Hrabowski, III |
172
Signature | Title | Date | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
/s/ | N. Lampton | Director | ||||||||||
N. Lampton | ||||||||||||
/s/ | R. J. Lawless | Director | ||||||||||
R. J. Lawless | ||||||||||||
/s/ | J. L. Skolds | Director | ||||||||||
J. L. Skolds | ||||||||||||
/s/ | M. D. Sullivan | Director | ||||||||||
M. D. Sullivan |
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY (REGISTRANT) | ||||||||||
By | /s/ | KENNETH W. DEFONTES, JR. | ||||||||
Kenneth W. DeFontes, Jr. President and Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.
Signature | Title | Date | ||||||||
---|---|---|---|---|---|---|---|---|---|---|
Principal executive officer and director: | ||||||||||
By | /s/ | K. W. DeFontes, Jr. | President, Chief Executive Officer, and Director | |||||||
| K. W. DeFontes, Jr. | | | |||||||
Principal financial and accounting officer: | ||||||||||
By | Chief Financial Officer and Treasurer | March 1, 2011 | ||||||||
| | | ||||||||
Directors: | ||||||||||
/s/ | M. D. Sullivan | Chairman of the Board of Directors | ||||||||
| | |||||||||
/s/ | T. F. Brady | Director | ||||||||
T. F. Brady | ||||||||||
/s/ | J. Haskins, Jr. | Director | March 1, 2011 | |||||||
J. Haskins, Jr. | ||||||||||
/s/ | C. D. Hayden | Director | March 1, 2011 | |||||||
C. D. Hayden | ||||||||||
/s/ | M. A. Shattuck III | Director | March 1, 2011 | |||||||
M. A. Shattuck III | ||||||||||
/s/ | M. J. Wallace | Director | March 1, 2011 | |||||||
M. J. Wallace |
174
Exhibit Number | | |
---|
*2 | (a) | — | Agreement and Plan of Reorganization and Corporate Separation (Nuclear). (Designated as Exhibit No. 2(a) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.) | ||
*2 | (b) | — | Agreement and Plan of Reorganization and Corporate Separation (Fossil). (Designated as Exhibit No. 2(b) to the Current Report on Form 8-K dated July 7, 2000, File Nos. 1-12869 and 1-1910.) | ||
*2 | (c) | — | Asset Purchase | ||
*2 | (d) | — | Master Agreement, dated as of October 26, 2010, by and between Electricite de France, S.A. and Constellation Energy Group, Inc. (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated November 1, 2010, File No. 1-12869.) | ||
*2 | (e) | — | Put Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., Constellation Nuclear, LLC, and Constellation Energy Nuclear Group, LLC. (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated November 8, 2010, File No. 1-12869.) | ||
*3 | (a) | — | Articles | ||
*3 | (b) | — | Correction to Articles Supplementary to the Charter of Constellation Energy Group, Inc. | ||
*3 | (c) | — | Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of September 19, 2008. (Designated as Exhibit No. 3.1 to the Current Report on Form 8-K dated September 19, 2008, File No. 1-12869.) | ||
*3 | (d) | — | Articles of Amendment to the Charter of Constellation Energy Group, Inc. as of July | ||
*3 | (e) | — | Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of April 10, 2007. (Designated as Exhibit 3(a) to the Current Report on Form 8-K dated April 10, 2007, File No. 1-12869.) | ||
*3 | (f) | — | Articles Supplementary to the Charter of Constellation Energy Group, Inc. as of November 20, 2001. (Designated as Exhibit No. 3(e) to the Annual Report on Form 10-K for the year ended December 31, 2001, File Nos. 1-12869 and 1-1910.) | ||
*3 | (g) | — | Certificate of Correction to the Charter of Constellation Energy Group, Inc. as of September 13, 1999. (Designated as Exhibit No. 3(c) to the Annual Report on Form 10-K for the year ended December 31, 1999, File Nos. 1-12869 and 1-1910.) | ||
*3 | (h) | — | Articles Supplementary to the Charter of Constellation Energy Group, Inc., as of July 19, 1999. (Designated as Exhibit No. 99.1 to the Current Report on Form 8-K dated July 19, 1999, File Nos. 1-12869 and 1-1910.) | ||
*3 | (i) | — | Amended and Restated Charter of Constellation Energy Group, Inc. as of April 30, 1999. (Designated as Appendix B to Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed March 3, 1999, File No. 33-64799.) | ||
*3 | (j) | — | Bylaws of Constellation Energy Group, Inc., as amended to July 18, 2008. (Designated as Exhibit No. 3 to the Current Report on Form 8-K dated July 18, 2008, File No. 1-12869.) | ||
*3 | (k) | — | Articles of Amendment to the Charter of BGE as of February 2, 2010. (Designated as Exhibit No. 3.1 to the Current Report on Form 8-K dated February 4, 2010, File No. 1-1910.) |
175
Exhibit Number | |||||
---|---|---|---|---|---|
*3 | — | Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, File No. 1-1910.) | |||
*3 | (m) | — | |||
Bylaws of BGE, as amended to | |||||
*4 | |||||
(a) | — | Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 dated March 29, 1999, File No. 333-75217.) | |||
*4 | (b) | — | First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003, File No. 333-102723.) | ||
*4 | (c) | — | Indenture dated as of July 24, 2006 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 filed July 24, 2006, File No. 333-135991.) | ||
*4 | (d) | — | First Supplemental Indenture between | ||
*4 | (e) | — | Indenture dated June 19, 2008 between Constellation Energy Group, Inc. and |
*4 | (f) | — | Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and | ||
*4 | (g) | — | Form of Subordinated Indenture between | ||
*4 | (h) | — | Form of Supplemental Indenture between | ||
*4 | (i) | — | Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.) | ||
*4 | (j) | — | Form of Junior Subordinated Debenture (Designated as Exhibit | ||
*4 | (k) | — | Form of Amended and Restated Declaration of Trust (including Form of Preferred Security) (Designated as Exhibit 4(c) to the Registration Statement on Form S-3 dated August 5, 2003, File No. 333-107681.) | ||
*4 | (l) | — | Indenture dated as of July 24, 2006 between | ||
*4 | (m) | — | First Supplemental Indenture between | ||
*4 | (n) | — | Indenture and Security Agreement dated as of July 9, 2009, between BGE and Deutsche Bank Trust Company Americas, as trustee (including form of BGE Officer's Certificate and form of Senior Secured Bond) (Designated as Exhibit Nos. 4(u) and 4(u)(1) to Post-Effective Amendment No. 1 to the Registration Statement on Form S-3 dated July 9, 2009, File Nos. 333-157637 and 333-157637-01.) |
176
Exhibit Number | |||||
---|---|---|---|---|---|
*4 | — | Supplemental Indenture No. 1, dated as of October 1, 2009, to the Indenture and Security Agreement dated as of July 9, 2009, between BGE and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(c) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File Nos. 1-12869 and 1-1910.) | |||
*4 | (p) | — | BGE Deed of Easement and Right-of-Way Grant dated as of July 9, 2009 (Designated as Exhibit No. 4(u)(2) to Post-Effective Amendment No. 1 to the Registration Statement on Form S-3 dated July 9, 2009, File Nos. 333-157637 and 333-157637-01.) | ||
*4 | (q) | — | Indenture dated as of June 29, 2007, by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary. (Designated as Exhibit 4.1 to the Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.) | ||
*4 | (r) | — | Series Supplement to Indenture dated as of June 29, 2007 by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary (Designated as Exhibit | ||
*4 | (s) | — | Replacement Capital Covenant dated June 27, 2008. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated | ||
*4 | (t) | — | Officers' Certificate, dated December 14, 2010, establishing the 5.15% Notes due December 1, 2020 of Constellation Energy Group, Inc., with the form of Notes attached thereto. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated December 14, 2010, File No. 1-12869.) | ||
+*10 | (a) | — | Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated. (Designated as Exhibit No. 10(d) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File Nos. 1-12869 and 1-1910.) | ||
+*10 | (b) | — | Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 2008, File Nos. 1-12869 and 1-1910.) | ||
*10 | (c) | — | Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K for the year ended December 31, 2008, File Nos. 1-12869 and 1-1910.) | ||
+*10 | (d) | — | Constellation Energy Group, Inc. Benefits Restoration Plan, amended and restated effective June 1, 2010. (Designated as Exhibit 10(b) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File Nos. 1-12869 and 1-1910.) | ||
+*10 | (e) | — | Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated. (Designated as Exhibit No. 10(e) to the Annual Report on Form 10-K for the year ended December 31, 2008, File Nos. 1-12869 and 1-1910.) | ||
+*10 | (f) | — | Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated. (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended December 31, 2008, File Nos. 1-12869 and 1-1910.) | ||
+*10 | (g) | — | Constellation Energy Group, Inc. Executive Supplemental Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(a) to the Quarterly Report on Form 10-Q for the quarter ended | ||
+*10 | (h) | — | Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit No. 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File Nos. 1-12869 and 1-1910.) | ||
+*10 | |||||
(i) | — | ||||
Constellation Energy Group, Inc. Executive Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.) | |||||
+*10 | (j) | — | |||
Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(c) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.) |
177
Exhibit Number | |||||
---|---|---|---|---|---|
+*10 | — | Constellation Energy Group, Inc. Management Long-Term Incentive Plan, as amended and restated. (Designated as Exhibit 10(d) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, File Nos. 1-12869 and 1-1910.) | |||
+*10 | (l) | — | Constellation Energy Group, Inc. | ||
+*10 | (m) | — | Consent of Mayo A. Shattuck III to termination of change-in-control agreement. (Designated as Exhibit | ||
+*10 | (n) | — | Consent of | ||
+*10 | (o) | — | Consent of Henry B. Barron, Jr. to termination of change-in-control agreement. (Designated as Exhibit No. 10.3 to the Current Report on Form 8-K dated December 10, 2009, File No. 1-12869.) | ||
*10 | (p) | — | Rate Stabilization Property | ||
*10 | (q) | — | Administration Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as administrator (Designated as Exhibit 10.3 to the Current Report on Form 8-K dated July 5, 2007, File No. 1-1910.) | ||
*10 | (r) | — | Second Amended and | ||
10 | (s) | — | Amendment No. 1 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. | ||
10 | (t) | — | Amendment No. 2 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. | ||
*10 | (u) | — | Amendment No. 3 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated November 3, 2010, File No. 1-12869.) | ||
*10 | (v) | — | Credit Agreement, dated as of October 15, 2010, among Constellation Energy Group, Inc., Bank of America, N.A., as a letter of credit issuing bank, swingline lender and administrative agent, Banc of America Securities LLC, Citigroup Global Markets Inc., RBS Securities Inc., BNP Paribas Securities Corp., and The Bank of Nova Scotia, as joint lead arranger and book runners, Citibank, N.A. and The Royal Bank of Scotland plc, as co-syndication agents and The Bank of Nova Scotia and BNP Paribas, as co-documentation agents and the other lenders named therein. (Designated as Exhibit 10.1 to the Current Report on Form 8-K dated October 21, 2010, File No. 1-12869.) | ||
*10 | (w) | — | Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., and Constellation Energy Group, Inc. (Designated as Exhibit No. 10.2 to the Current Report on Form 8-K dated November 3, 2010, File No. 1-12869.) | ||
+10 | (x) | — | Form of Grant Agreement for Stock Units with Sales Restriction. | ||
12 | (a) | — | Constellation Energy Group, Inc. and Subsidiaries Computation of Ratio of Earnings to Fixed Charges. |
12 | (b) | — | Baltimore Gas and Electric Company and Subsidiaries Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. | ||
21 | — | Subsidiaries of the Registrant. |
178
Exhibit Number | |||||
---|---|---|---|---|---|
23 | (a) | — | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm. | ||
23 | (b) | — | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm (for Constellation Energy Nuclear Group, LLC). | ||
31 | (a) | — | Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
31 | (b) | — | Certification of | ||
31 | (c) | — | Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
31 | (d) | — | Certification of | ||
32 | (a) | — | Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
32 | (b) | — | Certification of | ||
32 | (c) | — | Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
32 | (d) | — | Certification of | ||
99 | (a) | — | Audited Financial Statements of Constellation Energy Nuclear Group, LLC. | ||
*99 | (b) | — | Operating Agreement, dated as of February 4, 2010, by and among RF HoldCo LLC, Constellation Energy Group, Inc. and GSS Holdings (BGE Utility), Inc. (Designated as Exhibit No. 99-1 to the Current Report on Form 8-K dated February 4, 2010, File Nos. 1-12869 and 1-1910.) | ||
*99 | (c) | — | Contribution Agreement, dated as of February 4, 2010, by and among Constellation Energy Group, Inc., BGE and RF HoldCo LLC. (Designated as Exhibit No. 99-2 to the Current Report on Form 8-K dated February 4, 2010, File Nos. 1-12869 and 1-1910.) | ||
*99 | (d) | — | Purchase Agreement, dated as of February 4, 2010, by and between RF HoldCo LLC and GSS Holdings (BGE Utility), Inc. (Designated as Exhibit No. 99-3 to the Current Report on Form 8-K dated February 4, 2010, File Nos. 1-12869 and 1-1910.) | ||
101.INS | — | XBRL Instance Document | |||
101.SCH | — | XBRL Taxonomy Extension Schema Document | |||
101.PRE | — | XBRL Taxonomy Presentation Linkbase Document | |||
101.LAB | — | XBRL Taxonomy Label Linkbase Document | |||
101.CAL | — | XBRL Taxonomy Calculation Linkbase Document | |||
101.DEF | — | XBRL Taxonomy Definition Linkbase Document |
In accordance with Rule 402 of Regulation S-T, the XBRL related information in Exhibit 101 to this Annual Report on Form 10-K shall not be deemed to be "filed" for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.