UNITED STATES |
SECURITIES AND EXCHANGE COMMISSION |
Washington, D.C. 20549 |
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FORM 10-K |
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(Mark One) |
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[ü] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the fiscal year ended December 31, 20042005 |
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OR |
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[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the transition period from to |
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Commission File Number 1-14174 |
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AGL RESOURCES INC. |
(Exact name of registrant as specified in its charter) |
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Georgia | 58-2210952 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
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Ten Peachtree Place NE, | 404-584-4000 |
Atlanta, Georgia 30309 | |
(Address and zip code of principal executive offices) | (Registrant’s telephone number, including area code) |
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Securities registered pursuant to Section 12(b) of the Act: |
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Title of Class | Name of each exchange on which registered |
Common Stock, $5 Par Value | New York Stock Exchange |
Preferred Share Purchase Rights | New York Stock Exchange |
8% Trust Preferred Securities | New York Stock Exchange |
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Securities registered pursuant to Section 12(g) of the Act:None |
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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 under the Securities Act. Yes [ü] No [ ] |
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Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Act. Yes [ ] No [ü ] |
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Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes [ü] No [ ] |
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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 registrant’s 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. [ ] |
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 under the Exchange Act. Large accelerated filer [ ü] Accelerated filer [ ] Non-accelerated filer [ ] |
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Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes [ ] No [ü] No [ ] |
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The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates of the registrant, computed by reference to the price at which the registrant’s common equitystock was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter, was $1,879,590,369$2,989,393,874 |
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The number of shares of Common Stockthe registrant’s common stock outstanding as of February 11, 2005January 31, 2006 was 76,953,218.77,849,574. |
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DOCUMENTS INCORPORATED BY REFERENCE: |
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Portions of the Proxy Statement for the 20052006 Annual Meeting of Shareholders (“Proxy Statement”) to be held April 27, 2005,May 3, 2006, are incorporated by reference in Part III. |
| | Page(s) |
| 4 |
& Referenced Accounting Standards | 54 |
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Part I | | |
Item 1. | | 5 |
Item 1A. | | 5 |
Item 1B. | | 5 |
Item 2. | | 5-6 |
Item 3. | | 6 |
Item 2. | Properties | 7 |
Item 3. | Legal Proceedings | 8 |
Item 4. | | 96 |
Item 4A. | | 97 |
Part II | | |
Item 5. | | 8-9 |
Item 6. | | 10 |
Item 6. | Selected Financial Data | 11 |
Item 7. | | 1211-51 |
| | 1211 |
| | 1311-14 |
| | 15-34 |
| | 1915-19 |
| | 2520-25 |
| Wholesale Services | 3325-27 |
| Energy Investments | 3927-31 |
| Corporate | 4231-33 |
| | 33-34 |
| | 4335-40 |
| | 4940-45 |
| | 5445 |
| | 5545-51 |
Item 7A. | | 6451-54 |
Item 8. | | 55-94 |
| | 6855-56 |
| | 7057 |
| | 7158 |
| | 7259 |
| | 7360-65 |
| | 7865 |
| | 7966-67 |
| | 8167-68 |
| | 8468-71 |
| | 8872-78 |
| | 9478-81 |
| | 9881-82 |
| | 10183-85 |
| | 10286-87 |
| | 10487 |
| | 10487-88 |
| | 10688 |
| | 10689-91 |
| | 10992 |
| | 11093-94 |
Item 9. | | 11494 |
Item 9A. | | 11495 |
Item 9B. | | 11695 |
TABLE OF CONTENTS - continued
Part III | | |
Item 10. | | 11795-96 |
Item 11. | | 11796 |
Item 12. | | 11796 |
Item 13. | | 11796 |
Item 14. | | 11796 |
Part IV | | |
Item 15. | | 11896-101 |
| 124102 |
| 137103 |
Atlanta Gas Light | Atlanta Gas Light Company |
AGL Capital | AGL Capital Corporation |
AGL Networks | AGL Networks, LLC |
Chattanooga Gas | Chattanooga Gas Company |
Credit Facility | Credit agreement supporting our commercial paper program |
EBIT | Earnings before interest and taxes, a non-GAAP measure that includes operating income, other income, equity in SouthStar’s income, minority interest in SouthStar's earnings, donations and gain on sales of assets and excludes interest and tax expense; as an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, operating income or net income as determined in accordance with GAAP |
Elizabethtown Gas | Elizabethtown Gas Company |
ERC | Environmental responseremediation costs |
FASB | Financial Accounting Standards Board |
Florida Commission | Florida Public Service Commission |
Florida Gas | Florida City Gas Company |
GAAP | Accounting principles generally accepted in the United States of America |
Georgia Commission | Georgia Public Service Commission |
HeritageHenry Hub | Heritage Propane Partners, L.P.The Henry Hub, located in Louisiana, is the largest centralized point for natural gas spot and futures trading in the United States. NYMEX uses the Henry Hub as the point of delivery for its natural gas futures contracts. Many natural gas marketers also use the Henry Hub as their physical contract delivery point or their price benchmark for spot trades of natural gas. |
LNG | Liquefied natural gas |
Marketers | Georgia Public Service Commission-certificated marketersMarketers selling retail natural gas in Georgia and certificated by the Georgia Public Service Commission |
Medium-TermMedium-term notes | Notes issued by Atlanta Gas Light with scheduled maturities between 2012 and 2027 bearing interest rates ranging from 6.6% to 9.1% |
NJBPU | New Jersey Board of Public Utilities |
NYMEX | New York Mercantile Exchange, Inc. |
OCI | Other comprehensive income |
Operating margin | A non-GAAP measure of income, calculated as revenues minus cost of gas, that excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain on the sale of our Caroline Street campus; these items are included in our calculation of operating income as reflected in our statements of consolidated income; operatingincome. Operating margin should not be considered an alternative to, or more meaningful than, operating income or net income as determined in accordance with GAAP |
Pivotal Jefferson Island | Pivotal Jefferson Island Storage & Hub, LLC. |
Pivotal Propane | Pivotal Propane of Virginia, Inc. |
Pivotal Utility | Pivotal Utility Holding, Inc., parent company of Elizabethtown Gas, Elkton Gas and Florida City Gas |
PGA | Purchased gas adjustment |
PRP | Pipeline replacement program |
PUHCA | Public Utility Holding Company Act of 1935, as amended |
Sequent | Sequent Energy Management, L.P. |
SFAS | Statement of Financial Accounting Standards |
SouthStar | SouthStar Energy Services LLC |
US Propane | US Propane LP |
Virginia Natural Gas | Virginia Natural Gas, Inc. |
Virginia Commission | Virginia State Corporation Commission |
APB 2520 | Accounting Principles Board (APB) Opinion No. 20, “Accounting Changes” |
APB 25 | APB Opinion No. 25, “Accounting for Stock Issued to Employees” |
EITF 98-10 | Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” |
EITF 99-02 | Emerging Issues Task ForceEITF Issue No. 99-02, “Accounting for Weather Derivatives” |
EITF 02-03 | Emerging Issues Task ForceEITF Issue No. 02-03, “Issues Involved in Accounting for Contracts under EITF Issue No. 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities’” |
FIN 46 & FIN 46R | FASB Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities” |
FSP 106-1FIN 47 | FIN 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Staff Position (FSP)Statement No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” 143” |
SFAS 5 | SFASStatement of Financial Accounting Standards (SFAS) No. 5, “Accounting for Contingencies” |
SFAS 13 | SFAS No. 13, “Accounting for Leases” |
SFAS 66 | SFAS No. 66, “Accounting for Sales of Real Estate” |
SFAS 71 | SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” |
SFAS 106 | SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” |
SFAS 109 | SFAS No. 109, “Accounting for Income Taxes” |
SFAS 121 | SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of” |
SFAS 123 & SFAS 123R | SFAS No. 123, “Accounting for Stock-Based Compensation” |
SFAS 132131 | SFAS No. 132, “Employers’ Disclosures131, “Disclosures about PensionsSegments of an Enterprise and Other Postretirement Benefits-an amendment of FASB Statements No. 87, 88 and 106”Related Information”
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SFAS 133 | SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” |
SFAS 141 | SFAS No. 141, “Business Combinations” |
SFAS 142 | SFAS No. 142, “Goodwill and Other Intangible Assets” |
SFAS 143 | SFAS No. 143, “Accounting for Asset Retirement Obligations” |
SFAS 144 | SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” |
SFAS 148 | SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure-an
amendment of FASB Statement No. 123”
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SFAS 149 | SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” |
SFAS 154 | SFAS No. 154, “Accounting Changes and Error Corrections” |
PART I
Nature of Our Business
Employees
On December 31, 2004,2005, we had approximately 2,9702,385 employees, compared with approximately 2,150 at December 31, 2003. The increased from 2003 includes approximately 890 employees as a result of our acquisition of NUI. We have not experienced any work stoppages in recent years and we believe that our employee relations are good. Approximately 32%
On April 7, 2005, approximately 53 of our77 Florida City Gas employees are covered under collective bargaining agreements.agreements with Teamster’s Local Nos. 769 and 385 began a work stoppage. The strike lasted for 39 days, ending on May 16, 2005, when a new three-year agreement was reached. The following table provides information on thoseour collective bargaining agreements and the dates they expire:
| Affiliated subsidiary | Approximate # of Employeesemployees | Date of Contract Expirationcontract expiration |
Teamsters (Local 769 and 385) | Florida Gas | 82 | March 2005 |
International Brotherhood of Electrical Workers (Local 50) | Virginia Natural Gas | 147 | May 2005 |
Utility Workers Union of America (Local 424) | Elizabethtown Gas | 246 | November 2005 |
Teamsters (LocalNo. 528) | Atlanta Gas Light | 322302 | March 2006 |
Communications Workers of America (Local No. 1023) | Elizabethtown Gas | 5510 | April 2006 |
International Brotherhood of Electrical Workers (Local No. 50) | Virginia Natural Gas | 146 | May 2006 |
Utility Workers Union of America (Local No. 461) | Chattanooga Gas | 3120 | April 2007 |
International Union of Operating Engineers (Local No. 474) | Atlanta Gas Light | 3524 | August 2007 |
Teamsters (Local Nos. 769 and 385) | Florida City Gas | 53 | March 2008 |
Utility Workers Union of America (Local No. 424) | Elizabethtown Gas | 166 | November 2009 |
Total | | 918721 | |
Available Information
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports, and amendments to those reports, that we file with or furnish to the Securities and Exchange Commission (SEC) are available free of charge at our website,www.aglresources.com, as soon as reasonably practicable after we electronically file such reports with or furnish such reports to the SEC. The posting of these reports on our website does not constitute incorporationincorporate by reference of the other information contained on the website, and such other information on our website should not be considered part of such reports unless we expressly incorporate such other information by reference. We will also furnish copies of such reports free of charge upon written request to our Investor Relations department.
Additionally, our corporate governance guidelines, code of ethics, code of business conduct and the charters of each of our Board Committees, including the Audit, Compensation and Management Development, Corporate Development, Environmental and Corporate Responsibility, Executive, Finance and Risk Management, and Nominating and Corporate Governance Committees,committees are available on our website. We will also furnish copies of such information free of charge upon written request to our Investor Relations department. You can contact our Investor Relations department at:
AGL Resources Inc.
Investor Relations - Dept. 1071
Ten Peachtree Place, NE
Atlanta, GA 30309
404-584-3801
Risk Factors related to our business, our corporate and financial structure, our industry and the investment in our common stock are set forth in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Risk Factors.”
We do not have any unresolved comments from the SEC staff regarding our periodic or current reports under the Securities Exchange Act of 1934, as amended.
In 2005, we added an additional segment, retail energy operations. Information on the addition of this segment is contained in Note 14 to our consolidated financial statements set forth in Item 8, “Financial Statements and Supplementary Data.” The principal properties of our four operating segments are described below:
Distribution OperationsAs of December 31, 2004,2005, the properties of our distribution operations segment represented approximately 91% of the net property, plant and equipment onin our consolidated balance sheets.sheet. This property primarily includes assets used for the distribution of natural gas to our customers in our service areas, including approximately 41,600more than 45,000 miles of distribution mains, 993 miles of transportation mains and approximately 2.1 million pipeline connections to our customers.pipeline. We have approximately 7.35 billion cubic feet (Bcf) of liquefied natural gas (LNG) storage capacity in 5five LNG plants located in Georgia, New Jersey and Tennessee. In addition, we own three propane storage facilities in Virginia and Georgia that have a combined storage capacity of approximately 4.5 million gallons. These LNG plants and propane facilities supplement the gas supply during peak usage periods. The following map shows the service areas of our distribution operations segment as well as our LNG and propane facilities:
Energy InvestmentsThe properties in our energy investments segment includeare investments that are complementary to our distribution operations or provide services consistent with our core enterprises, including a natural gas storage and hub facility in Louisiana located approximately eight miles from the Henry Hub. The Henry Hub is the largest centralized point for natural gas spot and futures trading in the United States. NYMEX uses the Henry Hub as the point of delivery for its natural gas futures contracts. Many natural gas marketers also use the Henry Hub as their physical contract delivery point or their price benchmark for spot trades of natural gas. Our natural gas storage and hub facility consists of two salt dome gas storage caverns with 9.4approximately 10 million Dekatherms (Dth)(MMDth) of total capacity and about 6.9 million Dth7.2 MMDth of working gas capacity. By increasing the maximum operating pressure, we can periodically increase the working gas capacity to approximately 7.4 million Dth. The facility has approximately 720,000 Dth/day withdrawal capacity and 240,000360,000 Dth/day injection capacity. We are currently expandingcompleted a project during the year to expand compression capability, enabling us to enhanceincrease the number of times a customer can inject and withdraw gas. We expectgas on an annual basis from 10 to complete this upgrade in the third quarter of 2005.12 times.
We also own and operate a 72-mile intrastate pipeline and operate two storage facilities - - a high-deliverability salt cavern facility in Saltville, Virginia and a depleted reservoir facility in Early Grove, Virginia. Combined, the storage facilities have approximately 2.6 Bcf of working gas capacity. The storage facility in Saltville, Virginia currently has approximately 1.8 Bcf of storage capacity, and we are working with our partner, Duke Energy, to evaluate future expansion opportunities. The current expansion is expected to be completed in 2008. Saltville Storage connects to Duke Energy’s East Tennessee Natural Gas interstate system and its Patriot pipeline
In 2005, our subsidiary, Pivotal Propane of Virginia Inc., intends to complete the construction of a propane facility in Virginia Natural Gas Inc.’s (Virginia Natural Gas) service territory.Virginia. The propane facility will provideprovides our utility in Virginia Natural Gas with 28,800 Dth of propane air per day on a 10-day-per-year basis to serve Virginia Natural Gas’ peaking needs.10 day per year basis.
The properties used at SouthStar Energy Services, LLC consist primarily of leased and owned office space in Atlanta and its contents, including furniture and fixtures. In addition, energy investments’ properties include telecommunications conduit and fiber existing in public rights of way that is leased to our customers in Atlanta and Phoenix. This includes approximately 65,10072,000 fiber miles and 310 conduit miles, of which approximately 15%17% of our dark fiber in Atlanta and 21%22% of our dark fiber in Phoenix has been leased or sold.leased.
Retail Energy Operations, Wholesale Services and Corporate ThepropertiesThe properties used at our retail energy operations, wholesale services and corporate segments consist primarily of leased and owned office space in Atlanta and Houston and their contents, including furniture and fixtures. The majority of our Atlanta-based employees are located at our corporate headquarters, Ten Peachtree Place. Ten Peachtree Place is a 20-storyleased building with approximately 250,000 square feet of office space. We currently lease and occupy over 90% of the building. Our employeesIn addition, our retail energy operations leases approximately 26,600 square feet in Houston are located at 1200 Smith St. where wea different office building in Atlanta. We lease approximately 27,80032,000 square feet of office space.space for our employees in Houston.
ITEM 3. LEGAL PROCEEDINGS
No matters were submitted to a vote of our security holders during ourthe fourth quarter ended December 31, 2004.2005.
ITEM 4A.EXECUTIVE OFFICERS OF THE REGISTRANT
Set forth below in accordance with General Instruction G(3) of Form 10-K and Instruction 3 of Item 401(b) of Regulation S-K, are the names, ages and positions of our executive officers along with their business experience during the past five years. All officers serve at the discretion of our boardBoard of directors.Directors. All information is as of the date of the filing of this report.
Name, Ageage and Positionposition with the Company | Dates Elected or AppointedPeriods served |
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Paula Rosput Reynolds,D. Raymond Riddle, Age 4872
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Interim Chairman President and Chief Executive Officer | February 2002January 2006 - Present |
President and Chief Executive OfficerDirector | May 1978 - Present |
Chairman | August 2000 - February 2002 |
President and Chief Operating Officer of Atlanta Gas Light | September 1998 - November 2000 |
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Kevin P. Madden, Age 5253 (1) | |
Executive Vice President, External Affairs | November 2005 - Present |
Executive Vice President, Distribution and Pipeline Operations | April 2002 - November 2005 |
Executive Vice President, Legal, Regulatory and Governmental Strategy | September 2001 - April 2002 |
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Richard T. O’Brien,R. Eric Martinez, Age 50 (2)37
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Executive Vice President, Utility Operations | November 2005 - Present |
Senior Vice President, Business Process Initiatives | August 2005 - November 2005 |
Vice President and General Manager of Elizabethtown Gas | December 2004 - August 2005 |
Senior Vice President, Engineering & Construction of Pivotal Energy Development | August 2003 - December 2004 |
Chief Operating Officer of AGL Networks, LLC | December 2002 - August 2003 |
Executive Vice President and General Manager of AGL Networks, LLC | June 2002 - December 2002 |
Vice President, Business Development | October 2000 - June 2002 |
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Andrew W. Evans, Age 39 (2) | |
Senior Vice President and Chief Financial Officer | September 2005 - Present |
Vice President and Treasurer | April 20012002 - September 2005 |
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Melanie M. Platt,Age 5051 | |
Senior Vice President, Human Resources | September 2004 - Present |
Senior Vice President Business Supportand Chief Adminstrative Officer | October 2000 - September 2004 |
Vice President of Investor Relations | May 1998 - November 2002 |
Vice President and Corporate Secretary of Atlanta Gas Light | January 1995 - June 2002 |
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Paul R. Shlanta,Age 4748 | |
Executive Vice President, General Counsel and Chief Ethics and Compliance Officer | September 2005 - Present |
Senior Vice President, General Counsel and Chief Corporate Compliance Officer | September 2002 - September 2005 |
Senior Vice President, General Counsel and Corporate Secretary | July 2002 - September 2002 |
Senior Vice President and General Counsel | September 1998 - July 2002 |
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Bryan E. Seas, Age 45 (3) | |
Vice President, Controller and Chief Accounting Officer | September 2005 - Present |
Vice President and Controller | July 2003 - September 2005 |
(1) | Mr. Madden served as general counsel and chief legal advisor withto the Federal Energy Regulatory Commission (FERC) from January 2001 -to September 2001; as deputy director, Office of Markets, Tariffs and Rates, with the FERC from February 2000 - January 2001; and as director, Office of Pipeline Regulations, with the FERC from November 1998 - February 2000.2001. |
(2) | From March 1995 until joining the Company, Mr. O’BrienEvans was employed by Mirant Corporation (NYSE: MIR) (formerly Southern Energy, Inc.) where he served from June 2001 until April 2002 as a vice president of corporate development for the company’s Mirant Americas business unit. He previously served as vice president and treasurer for Mirant Americas from June 2000 until June 2001; director of finance for Mirant Americas Energy Marketing from March 1999 until June 2000; and project finance associate for Southern Electric International (Mirant’s predecessor) from March 1995 until March 1997. Prior to Mirant, Mr. Evans was employed by the Cambridge, MA office of National Economic Research Associates and by the Federal Reserve Bank of Boston. |
(3) | Mr. Seas spent almost 10 years with El Paso Corporation a power generation(NYSE: EP) and energy tradingone of its predecessor companies, Sonat Inc. Mr. Seas was vice president and marketing company,controller of El Paso’s Global Power Group from September 2002 until June 2003, responsible for accounting, financial reporting, financial systems, budgeting and forecasting. As El Paso’s director of corporate accounting from November 2000 until August 2002, Mr. Seas directed the general accounting and financial systems services of the company. Prior to 2001 andthat, Mr. Seas served as director of accounting for El Paso’s Southern Natural Gas Company subsidiary from October 1999 until October 2000. Mr. Seas began his career in various executive positions including Chief Financial Officer and President and Chief Operating Officer at PacifiCorp, an integrated electric utility and energy marketing company, from 1983 to 2000.public accounting with Ernst & Young, LLP in 1987. |
PART II
Holders of Common Stock, Stock Price and Dividend Information
Our common stock is listed on the New York Stock Exchange under the symbol ATG. At January 20, 2005,31, 2006, there were approximately 11,13510,979 record holders of our common stock. Quarterly information concerning our high and low stock prices and cash dividends that we paid in 2005 and 2004 and 2003 areis as follows:
2004 | | |
| Sales Price of Common Stock | Cash Dividend per Common Share |
Quarter ended: | High | Low |
March 31, 2004 | $30.63 | $27.87 | $0.28 |
June 30, 2004 | 29.41 | 26.50 | 0.29 |
September 30, 2004 | 31.27 | 28.60 | 0.29 |
December 31, 2004 | 33.65 | 30.11 | 0.29 |
2003 | | |
| Sales Price of Common Stock | Cash Dividend per Common Share |
Quarter ended: | High | Low |
March 31, 2003 | $25.41 | $21.90 | $0.27 |
June 30, 2003 | 26.98 | 23.30 | 0.28 |
September 30, 2003 | 28.49 | 25.35 | 0.28 |
December 31, 2003 | 29.35 | 27.24 | 0.28 |
| | | | | |
| | Sales price of common stock | | Cash Dividend Per Common | |
Quarter ended: | | High | | Low | | Share | |
2005 | | | | | | | |
March 31, 2005 | | $ | 36.09 | | $ | 32.00 | | $ | 0.31 | |
June 30, 2005 | | | 38.89 | | | 33.37 | | | 0.31 | |
September 30, 2005 | | | 39.32 | | | 35.29 | | | 0.31 | |
December 31, 2005 | | | 37.54 | | | 32.23 | | | 0.37 | |
2004 | | | | | | | | | | |
March 31, 2004 | | $ | 30.63 | | $ | 27.87 | | $ | 0.28 | |
June 30, 2004 | | | 29.41 | | | 26.50 | | | 0.29 | |
September 30, 2004 | | | 31.27 | | | 28.60 | | | 0.29 | |
December 31, 2004 | | | 33.65 | | | 30.11 | | | 0.29 | |
We pay dividends four times a year: March 1, June 1, September 1 and December 1. We have paid 229233 consecutive quarterly dividends beginning in 1948. Dividends areIn February 2005, we increased the quarterly dividend to $0.31 per common share, and in November 2005, we increased the quarterly dividend to $0.37 per common share.
Our common shareholders may receive dividends when declared at the discretion of our boardBoard of directors,Directors. Dividends may be paid in cash, stock or other form of payment, and payment of future dividends will depend on our future earnings, cash flow, financial requirements and other factors.factors, some of which are noted below. In February 2005, we increasedcertain cases, our ability to pay dividends to our common shareholders is limited by the quarterlyfollowing:
· | our ability to satisfy our obligations under certain financing agreements, including debt-to-capitalization and total shareholders’ equity covenants |
· | our ability to satisfy our obligations to any preferred shareholders |
· | restrictions under the Public Utility Holding Company Act of 1935, as amended (PUHCA), on our payment of dividends out of capital or unearned surplus without prior permission from the SEC. The PUHCA was repealed effective February 8, 2006. For more information about the repeal and its effect on us, see |
Additionally, under Georgia law, the payment of cash dividends to the holders of our common stock is limited to our legally available assets and subject to the prior payment of dividends on any outstanding shares of preferred stock and junior preferred stock. Our assets are not legally available for paying cash dividends if, after payment of the dividend to $0.31 per common share.
· | we could not pay our debts as they become due in the usual course of business, or |
· | our total assets would be less than our total liabilities plus, subject to some exceptions, any amounts necessary to satisfy (upon dissolution) the preferential rights of shareholders whose preferential rights are superior to those of the shareholders receiving the dividends |
Sales of Unregistered Securities
We sold noAll of our sales of securities in 2004 that2005 were not registered under the Securities Act of 1933, as amended.
Issuer Purchases of Equity Securities
The following table sets forth information regarding purchases of our common stock by us and any affiliated purchasers during the three months ended December 31, 2004.2005. All shares were purchased in open market transactions in connection with awards payable in common stock under the AGL Resources Inc. Officer Incentive Plan (OIP). In February 2006, our Board of Directors authorized a plan to repurchase up to 8 million shares of our outstanding common stock over a five-year period. These purchases are intended to principally offset share issuances under our employee incentive compensation plans, director plans, and dividend reinvestment and stock purchase plans. Stock repurchases under this program may be made in the open market or in private transactions at times and in amounts that we deem appropriate. However, there is no guarantee as to the exact number of additional shares that may be repurchased, and we may terminate or limit the stock repurchase program at any time. We will hold the repurchased shares as treasury shares.
Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1) | Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs |
October 2004 | - | - | - | 479,071 |
November 2004 | 45,000 | $32.97 | 45,000 | 434,071 |
December 2004 | 6,667 | $33.13 | 6,667 | 427,404 |
Total fourth quarter | 51,667 | $32.99 | 51,667 | 427,404 |
Period | | Total number of shares purchased (1) | | Average price paid per share | | Total number of shares purchased as part of publicly announced plans or programs (2) | | Maximum number of shares that may yet be purchased under the plans or programs | |
October 2005 | | | 220 | | $ | 36.01 | | | N/A | | | N/A | |
November 2005 | | | 108 | | $ | 33.96 | | | N/A | | | N/A | |
December 2005 | | | 4,892 | | $ | 35.39 | | | N/A | | | N/A | |
Total fourth quarter | | | 5,220 | | $ | 35.12 | | | | | | | |
(1) | The total number of shares purchased reflects an aggregate of 5,220 shares surrendered to us to satisfy tax withholding obligations in connection with the vesting of shares of restricted stock and/or the exercise of stock options. |
(2) | On June 30, 2004, we disclosedannounced that our Board of Directors had approved the repurchasepurchase of up to 600,000 shares of our common stock to be used for the issuances under the OIP awards.OIP. As of December 31, 2004 a total of 172,5962005, we had purchased 253,766 shares, have been repurchased, leaving a maximum of 427,404346,234 shares that can still be repurchasedavailable for purchase for use in the OIP. TheWe adopted the OIP was adoptedon March 20, 2001, and its repurchase authorityit will expire on March 20, 2011. |
Selected financial data about us is set forth in the table below. We derived the data in the tablestable from our audited financial statements. You should read the data in the table in conjunction with the consolidated financial statements and related notes set forth in Item 8, “Financial Statements and Supplementary Data.” On September 30, 2001, our Board of Directors elected to change our fiscal year end from September 30 to December 31, effective October 1, 2001. We refer to the three months ended December 31, 2001 as the “Transition Period” in the table below.
We acquired Jefferson Island Storage & Hub LLC (Jefferson Island) on October 1, 2004, and NUI Corporation (NUI) on November 30, 2004. As a result, our results of operations for 2004 include three months of the acquired operations of Jefferson Island and one month of the acquired operations of NUI. Pursuant to FIN 46R, which we adopted in January 2004, we consolidated all of SouthStar’s accounts with our subsidiaries’ accounts as of January 1, 2004.
Dollars and shares in millions, except per share amounts | | 2004 | | 2003 | | 2002 | | Transition Period | | 2001 | | 2000 | | | 2005 | | 2004 | | 2003 | | 2002 | | Transition period | | 2001 | |
Income statement | | | | | | | | | | | | | | |
Income statement data | | | | | | | | | | | | | | |
Operating revenues | | $ | 1,832 | | $ | 983 | | $ | 877 | | $ | 204 | | $ | 946 | | $ | 608 | | | $ | 2,718 | | $ | 1,832 | | $ | 983 | | $ | 877 | | $ | 204 | | $ | 946 | |
Cost of gas | | | | 1,626 | | | 995 | | | 339 | | | 268 | | | 49 | | | 327 | |
Operating margin | | | | 1,092 | | | 837 | | | 644 | | | 609 | | | 155 | | | 619 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost of gas | | | 994 | | 339 | | 268 | | 49 | | 327 | | 112 | | |
Operation and maintenance | | | 377 | | 283 | | 274 | | 68 | | 267 | | 248 | | | | 477 | | 377 | | 283 | | 274 | | 68 | | 267 | |
Depreciation and amortization | | | 99 | | 91 | | 89 | | 23 | | 100 | | 83 | | | | 133 | | 99 | | 91 | | 89 | | 23 | | 100 | |
Taxes other than income taxes | | | 30 | | 28 | | 29 | | 6 | | 33 | | 27 | | | | 40 | | 29 | | 28 | | 29 | | 6 | | 33 | |
Total operating expenses | | | 1,500 | | | 741 | | | 660 | | | 146 | | | 727 | | | 470 | | | | 650 | | | 505 | | | 402 | | | 392 | | | 97 | | | 400 | |
Gain on sale of Caroline Street campus | | | - | | | 16 | | | - | | | - | | | - | | | - | | | | - | | | - | | | 16 | | | - | | | - | | | - | |
Operating income | | | 332 | | | 258 | | | 217 | | | 58 | | | 219 | | | 138 | | | | 442 | | | 332 | | | 258 | | | 217 | | | 58 | | | 219 | |
Equity in earnings of SouthStar | | | - | | 46 | | 27 | | 4 | | 14 | | 6 | | |
Gain on sale of Utilipro Inc. | | | - | | - | | - | | - | | 11 | | - | | |
Gain on propane transaction | | | - | | - | | - | | - | | - | | 13 | | |
Other income (loss) | | | - | | 2 | | 3 | | 1 | | (7 | ) | | 9 | | |
Donation to private foundation | | | - | | (8 | ) | | - | | - | | - | | - | | |
Equity in earnings of SouthStar Energy Services LLC | | | | - | | - | | 46 | | 27 | | 4 | | 14 | |
Other (loss) income | | | | (1 | ) | | - | | (6 | ) | | 3 | | 1 | | 4 | |
Minority interest | | | (18 | ) | | - | | - | | - | | - | | - | | | | (22 | ) | | (18 | ) | | - | | - | | - | | - | |
Interest expense | | | (71 | ) | | (75 | ) | | (86 | ) | | (24 | ) | | (98 | ) | | (58 | ) | | | (109 | ) | | (71 | ) | | (75 | ) | | (86 | ) | | (24 | ) | | (98 | ) |
Earnings before income taxes | | | 243 | | 223 | | 161 | | 39 | | 139 | | 108 | | | | 310 | | 243 | | 223 | | 161 | | 39 | | 139 | |
Income taxes | | | 90 | | | 87 | | | 58 | | | 14 | | | 50 | | | 37 | | | | 117 | | | 90 | | | 87 | | | 58 | | | 14 | | | 50 | |
Income before cumulative effect of change in accounting principle | | | 153 | | 136 | | 103 | | 25 | | 89 | | 71 | | | | 193 | | 153 | | 136 | | 103 | | 25 | | 89 | |
Cumulative effect of change in accounting principle, net of $5 in income taxes | | | - | | | (8 | ) | | - | | | - | | | - | | | - | | | | - | | | - | | | (8 | ) | | - | | | - | | | - | |
Net income | | $ | 153 | | $ | 128 | | $ | 103 | | $ | 25 | | $ | 89 | | $ | 71 | | | $ | 193 | | $ | 153 | | $ | 128 | | $ | 103 | | $ | 25 | | $ | 89 | |
Common stock data | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Weighted average shares outstanding-basic | | | 66.3 | | 63.1 | | 56.1 | | 55.3 | | 54.5 | | 55.2 | | | | 77.3 | | 66.3 | | 63.1 | | 56.1 | | 55.3 | | 54.5 | |
Weighted average shares outstanding-fully diluted | | | 67.0 | | | 63.7 | | | 56.6 | | | 55.6 | | | 54.9 | | | 55.2 | | | | 77.8 | | 67.0 | | 63.7 | | 56.6 | | 55.6 | | 54.9 | |
Total shares outstanding (1) | | | | 77.8 | | | 76.7 | | | 64.5 | | | 56.7 | | | 55.6 | | | 55.1 | |
Earnings per share-basic | | $ | 2.30 | | $ | 2.03 | | $ | 1.84 | | $ | 0.45 | | $ | 1.63 | | $ | 1.29 | | | $ | 2.50 | | $ | 2.30 | | $ | 2.03 | | $ | 1.84 | | $ | 0.45 | | $ | 1.63 | |
Earnings per share-fully diluted | | $ | 2.28 | | $ | 2.01 | | $ | 1.82 | | $ | 0.45 | | $ | 1.62 | | $ | 1.29 | | | $ | 2.48 | | $ | 2.28 | | $ | 2.01 | | $ | 1.82 | | $ | 0.45 | | $ | 1.62 | |
Dividends per share | | $ | 1.15 | | $ | 1.11 | | $ | 1.08 | | $ | 0.27 | | $ | 1.08 | | $ | 1.08 | | | $ | 1.30 | | $ | 1.15 | | $ | 1.11 | | $ | 1.08 | | $ | 0.27 | | $ | 1.08 | |
Dividend payout ratio | | | 50 | % | | 55 | % | | 59 | % | | 60 | % | | 66 | % | | 84 | % | | | 52 | % | | 50 | % | | 55 | % | | 59 | % | | 60 | % | | 66 | % |
Book value per share(1) (2) | | $ | 18.04 | | $ | 14.66 | | $ | 12.52 | | $ | 12.41 | | $ | 12.20 | | $ | 11.49 | | |
Market value per share(1) | | $ | 33.24 | | $ | 29.10 | | $ | 24.30 | | $ | 23.02 | | $ | 19.97 | | $ | 20.08 | | |
Book value per share (2) | | | $ | 19.27 | | $ | 18.04 | | $ | 14.66 | | $ | 12.52 | | $ | 12.41 | | $ | 12.20 | |
Market value per share (3) | | | $ | 34.81 | | $ | 33.24 | | $ | 29.10 | | $ | 24.30 | | $ | 23.02 | | $ | 19.97 | |
Balance sheet data(1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total assets | | $ | 5,640 | | $ | 3,972 | | $ | 3,742 | | $ | 3,454 | | $ | 3,368 | | $ | 2,588 | | | $ | 6,251 | | $ | 5,637 | | $ | 3,972 | | $ | 3,742 | | $ | 3,454 | | $ | 3,368 | |
Long-term liabilities and deferred credits | | | 682 | | 647 | | 702 | | 671 | | 711 | | 768 | | |
Long-term liabilities | | | | 737 | | 682 | | 647 | | 702 | | 671 | | 711 | |
Minority interest | | | | 38 | | 36 | | - | | - | | - | | - | |
Capitalization | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Long-term debt (excluding current portion) | | | 1,623 | | 956 | | 994 | | 1,015 | | 1,065 | | 664 | | | | 1,615 | | 1,623 | | 956 | | 994 | | 1,015 | | 1,065 | |
Common shareholders’ equity | | | 1,385 | | | 945 | | | 710 | | | 690 | | | 671 | | | 621 | | | | 1,499 | | | 1,385 | | | 945 | | | 710 | | | 690 | | | 671 | |
Total capitalization | | $ | 3,008 | | $ | 1,901 | | $ | 1,704 | | $ | 1,705 | | $ | 1,736 | | $ | 1,285 | | | $ | 3,114 | | $ | 3,008 | | $ | 1,901 | | $ | 1,704 | | $ | 1,705 | | $ | 1,736 | |
Financial ratios(1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Capitalization | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Long-term debt | | | 54 | % | | 50 | % | | 58 | % | | 60 | % | | 61 | % | | 52 | % | | | 52 | % | | 54 | % | | 50 | % | | 58 | % | | 60 | % | | 61 | % |
Common shareholders’ equity | | | 46 | | | 50 | | | 42 | | | 40 | | | 39 | | | 48 | | | | 48 | | | 46 | | | 50 | | | 42 | | | 40 | | | 39 | |
Total | | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
Return on average common shareholders’ equity | | | 13.1 | % | | 15.5 | % | | 14.7 | % | | 14.6 | % | | 13.8 | % | | 11.1 | % | | | 13.4 | % | | 13.1 | % | | 15.5 | % | | 14.7 | % | | 14.6 | % | | 13.8 | % |
(1) | As of the last day of the respective fiscal period. |
(2) | Common shareholders’ equity divided by total outstanding common shares.shares as of the last day of the fiscal period. |
(3) | Closing price of common stock on the New York Stock Exchange as of the last trading day of the fiscal period. |
Certain expectations and projections regarding our future performance referenced in this “Management’sManagement’s Discussion and Analysis of Financial Condition and Results of Operation”Operations section and elsewhere in this report, as well as in other reports and proxy statements we file with the Securities and Exchange Commission (SEC), are forward-looking statements. Officers and other employees may also make verbal statements to analysts, investors, regulators, the media and others that are forward-looking.
Forward-looking statements involve matters that are not historical facts, such as projections of our financial performance, management’s goals and strategies for our business and assumptions regarding the foregoing. Becausebecause these statements involve anticipated events or conditions, forward-looking statements often include words such as “anticipate,"anticipate," "assume," "can," "could," "estimate," "expect," "forecast," "future," "indicate," "intend," "may," “outlook,” “assume,"plan," "predict," "project,” “can,” “could,” “estimate,” “expect,” “forecast,” “indicate,” “intend,” “may,” “plan,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would”"seek," "should," "target," "will," "would," or similar expressions. For example, in this “Management’s Discussion and Analysis of Financial Condition and Results of Operation” section and elsewhere in this report, we have forward-looking statements regarding ourOur expectations for
· | operating income growth |
· | cash flows from operations |
· | operating expense growth |
· | our business strategies and goals |
· | our potential for growth and profitability |
· | our ability to integrate our recent and future acquisitions |
· | trends in our business and industries, and |
· | developments in accounting standards |
Do not unduly rely on forward-looking statements. They represent our expectations about the future and are not guarantees. Our expectationsguarantees and are based on currently available competitive, financial and economic data along with our operating plans. While we believe that our expectations are reasonable in view of the currently available information, our expectations are subject to future events, risks and uncertainties, and there are several factors - many beyond our control - - that could cause results to differ significantly from our expectations.
Such events, risks and uncertainties include, but are not limited to, changes in price, supply and demand for natural gas and related products; the impact of changes in state and federal legislation and regulation; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; the impact of acquisitions and divestitures; direct or indirect effects on AGL Resources' business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions and general economic conditions; uncertainties about environmental issues and the related impact of such issues; the impact of changes in weather on the temperature-sensitive portions of the business; the impact of natural disasters such as hurricanes on the supply and price of natural gas; acts of war or terrorism; and other factors that are described in detail in our filings with the SEC.
We caution readers that, in addition to the important factors described elsewhere in this report, the factors set forth in “Riskthe section Risk Factors in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” among others, could cause our business, results of operations or financial condition in 20052006 and thereafter to differ significantly from those expressed in any forward-looking statements. There also may be other factors that we cannot anticipate or that are not described in this report that could cause results to differ significantly from our expectations.
Forward-looking statements are only as of the date they are made, and we do not undertake any obligation to update these statements to reflect subsequent changes.circumstances or events.
Overview
We are ana Fortune 1000 energy services holding company whose principal business is the distribution of natural gas in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia. Our six utilities serve more than 2.2 million end-use customers, making us the largest distributor of natural gas in the easternsoutheastern and mid-Atlantic regions of the United States based on number of customers.customer count. We also are also involved in various related businesses, including retail natural gas marketing to end-use customers primarily in Georgia; natural gas asset management and related logistics activities for our own utilities as well as for other non-affiliatednonaffiliated companies; natural gas storage arbitrage and related activities; operation of high deliverabilityhigh-deliverability underground natural gas storage;storage assets; and construction and operation of telecommunications conduit and fiber infrastructure within selectselected metropolitan areas. We manage these businesses through threefour operating segments - distribution operations, retail energy operations, wholesale services and energy investments - and a non-operatingnonoperating corporate segment.
The distribution operations segment is the largest component of our business and is comprehensively regulated by regulatory agencies in six states. These agencies approve rates that are designed to provide us the opportunity to generate revenues;revenues to recover the cost of natural gas delivered to our customers and our fixed and variable costs such as depreciation, interest, maintenance and overhead costs;costs, and to earn a reasonable return for our shareholders. With the exception of Atlanta Gas Light Company (Atlanta Gas Light), our largest utility, franchise, the earnings of our regulated utilities are weather-sensitiveweather sensitive to varying degrees. Although various regulatory mechanisms provide us a reasonable opportunity to recover our fixed costs regardless of natural gas volumes sold, the effect of weather manifests itself in terms of higher earnings during periods of colder weather and lower earnings within warmer weather. Atlanta Gas Light charges rates to its customers primarily on monthly fixed charges. Our Georgia retail marketing business,energy operations segment, which consists of SouthStar Energy Services LLC (SouthStar), also is weather sensitive and uses a variety of hedging strategies to mitigate potential weather impacts. AllOur Sequent Energy Management, L.P. (Sequent) subsidiary within our wholesale services segment is weather sensitive, with typically increased earnings opportunities during periods of our utilities and SouthStar face competition in the residential and commercial customer markets based on customer preferences for natural gas compared with other energy products and the price of those products relative to that of natural gas.extreme weather conditions.
During the year ended December 31, 2005, we derived approximately 96%86% of our earnings before interest and taxes (EBIT) during the year ended December 31, 2004 from our regulated natural gas distribution business and from the sale of natural gas to end-use customers primarily in Georgia by SouthStar, which is part of our energy investments segment.through SouthStar. This statistic is significant because it represents the portion of our earnings that directly results directly from the underlying business of supplying natural gas to retail customers. Although SouthStar is not subject to the same regulatory framework as our utilities, it is an integral part of the retail framework for providing gas service to end-use customers in the state of Georgia. For more information regarding our measurement of EBIT, and the items it excludes from operating income and net income, see “ResultsResults of Operations - AGL Resources.”
The remaining 4%14% of our EBIT was principally derived from businesses that are complementary to our natural gas distribution business. We engage in natural gas asset management and the operation of high deliverabilityhigh-deliverability natural gas underground storage as adjunctancillary activities to our utility franchises. These businesses allow us to be opportunistic in capturing incremental value at the wholesale level, provide us with deepened business insight about natural gas market dynamics and facilitate our ability, in the case of asset management, to provide transparency to regulators as to how that value can be captured to benefit our utility customers through sharingprofit-sharing arrangements. Given the volatile and changing nature of the natural gas resource base in North America and globally, we believe that participation in these related businesses strengthens our business vitality.business.
Our Competitive Strengths
We believe our competitive strengths have enabled us to grow our business profitably and create significant shareholder value. These strengths include:
Regulated distribution assets located in growing geographic regionsOur operations are primarily concentrated along the east coast of the United States, from Florida to New Jersey. We operate primarily urban utility franchises in growing metropolitan areas where we can more effectively deploy technology to improve service delivery and manage costs. We believe the population growth and resulting expansion in business and construction activity in many of the areas we serve should result in increased demand for natural gas and related infrastructure for the foreseeable future.
Demonstrated track record of performance through superior execution We continue to focus our efforts on generating significant incremental earnings improvements from each of our businesses. We have been successful in achieving this goal in the past through a combination of business growth, opportunistic acquisitions and controlling or reducing our operating expenses. We achieved these improvements to our operations in part through the implementation of best practices in our businesses, including increased investments in enterprise technology, workforce automation and business process modernization. Our goal is a single operational platform that eliminates duplicate systems and disparate processes among our various companies.
ProvenDemonstrated ability to acquire and integrate natural gas assets that add significant incremental earnings We take a disciplined approach to identifying strategic natural gas assets that support our long-term business plan. For example, our November 2004 purchaseacquisition of NUI Corporation (NUI), a New Jersey-based energy holding company with natural gas distribution operations in New Jersey, Florida and Maryland and Virginia, providesprovided us an opportunity to leverage and strengthen one of our core competencies - the efficient, low-cost operation of urban natural gas franchises. The disparity between NUI’sthese utilities’ pre-acquisition utility operating metrics and cost structure and those of our other utilities providesprovided us an opportunity to achieve significant improvements in NUI’s businessthese businesses, which we have been able to do. We will continue to seek and implement better methods of operating in 2005order to improve our service delivery and beyond.reduce our costs. In addition, our acquisition in October 2004 of thea natural gas storage assets of Jefferson Island Storage & Hub LLC (Jefferson Island), as discussed below,facility in Louisiana in 2004 added immediate incremental earnings to our business and, given the possibilities for expansion, shouldhas the potential to provide a stableprospective earnings stream going forward.growth.
Business Accomplishments in 20042005
· | We increased net income 20% to $153 million and fully diluted earnings per share 13% to $2.28 from prior-year amounts. In addition to improvements in our base distribution business and energy investments businesses, we were able to capture additional incremental net income in the wholesale natural gas market through our Sequent Energy Management, L.P. (Sequent) asset management, producer services and storage arbitrage activities. |
We believe the results of our efforts are clear. We not only delivered solid results to our shareholders again in 2005 but also provided customers with improved service.· | We strengthened our position as a leading operator of natural gas utility assets in the eastern United States by acquiring NUI. |
· | We acquired Jefferson Island, a high-deliverability salt-dome gas storage facility in Louisiana, which allows us to migrate into the wholesale market and capitalize on the growing market of utility and large industrial customers, producers, financial intermediaries and marketers who compete to hold firm capacity rights to store natural gas. For more information on our acquisitions of NUI and Jefferson Island, see Note 2. |
· | We announced our plan to acquire 250 miles of intrastate pipeline in our Georgia service area from Southern Natural Gas, a subsidiary of El Paso Corporation, which should close in the second quarter of 2005. We expect this acquisition to allow us to, over time, undertake economical reconfiguration of our Georgia transmission grid, integrating gas flows from the Gulf Coast, imported liquefied natural gas (LNG) and our own market area LNG. |
12
· | We began construction of a propane air facility in Virginia that will provide needed peak-day demand protection for the customers of our Virginia Natural Gas, Inc (Virginia Natural Gas) utility. |
· | We continued to support a strong balance sheet by issuing 11.04 million shares of AGL Resources common stock in November 2004, raising net proceeds of $332 million primarily to fund the NUI and Jefferson Island acquisitions. |
· | We increased our dividend 7% for the third consecutive year. If the current amount per quarter of $0.31 per share is in effect for all of 2005, our indicated annual rate would be $1.24 per share. |
Table of Contents
In 2005, we increased net income 26% over the prior year to $193 million and increased fully diluted earnings per share 9% to $2.48 despite increased average outstanding debt of $549 million and 11 million additional shares outstanding in 2005 due to our public stock offering in November 2004, both of which were related to acquisitions in the fourth quarter of 2004. Our Board of Directors raised our annual dividend 19% in November 2005, to an annual rate of $1.48 per share. The increase marked the fourth time in three years our Board has raised the dividend, bringing our payout ratio more in line with other publicly traded energy holding companies and local distribution companies and ensuring a competitive dividend yield relative to alternative investments.
We have substantially completed the integration of our two recent acquisitions: NUI Corporation (NUI), which we acquired on November 30, 2004, and Jefferson Island Storage & Hub, LLC (Jefferson Island), which we acquired on October 1, 2004. Jefferson Island became a wholly owned subsidiary and was renamed Pivotal Jefferson Island Storage & Hub, LLC (Pivotal Jefferson Island). In 2005, we consolidated a number of NUI’s business technology platforms into our enterprise-wide systems, including the accounting, payroll, human resources and supply chain functions. We also consolidated the former NUI utility call center operations into our own centralized call center. The combination of systems integration and the application of our operational model to managing NUI has resulted in significant improvements in its operations, as measured by the various metrics we use to manage our business. As a result of these integration efforts, we believe that we have achieved our performance goal of successfully integrating these acquisitions and making them accretive to our consolidated earnings within one year of the acquisition closing date.
We continued business process improvement actions, including the deployment of substantial technology resources, in each of our business units. Additionally, through asset management, producer services and storage arbitrage activities at Sequent, we captured and recognized incremental net income from opportunities in the marketplace as we provided services during and after hurricanes Katrina and Rita. Our operational platform was tested when, during hurricane Rita, Sequent relocated its trading floor from Houston to Richardson, Texas with virtually no service interruptions, in order to keep our commitments to customers and provide continuity in a market where service disruptions were prevalent.
Lastly, we worked cooperatively with our regulators during the year. In Georgia, we negotiated a settlement in the Atlanta Gas Light rate case whereby rates billed to customers will not change for a five-year period but Atlanta Gas Light will recognize reduced operating revenues of $5 million per year for a total of $25 million over the five-year period.
Areas of Strategic Focus in 20052006 Goals
Our fundamental business strategy isgoals do not significantly change from one year to the next. However, we continue to refine our goals, taking into consideration our prior financial and operational performance and those external factors impacting not only us and the natural gas industry, but also the global marketplace. We are focused on delivering earnings and income growth by effectively managing our gas distribution operations, optimizing our return on our assets,operations; selectively growing our gas distribution businesses through acquisitionsacquisitions; and developing our portfolio of closely related unregulated businesses with an emphasis on risk management and earnings visibility. Key elements of our strategy include:businesses.
EnhanceImpact of Hurricanes on AGL Resources and Our Industry
The natural gas production, processing and pipeline infrastructure in the valueGulf of Mexico was significantly affected by hurricanes Katrina and growth potentialRita in August and September 2005. This resulted in higher prices and increased price volatility for natural gas, which we and the Energy Information Administration expected would significantly increase the cost to heat a home during the current heating season. Natural gas prices moderated by the end of 2005 and early 2006, and weather has been warmer than normal thus far in 2006, but we still expect home heating costs to be significantly higher in the first quarter of 2006 compared to prior years.
The impact of hurricanes Katrina and Rita on natural gas prices and transportation costs created diverse offsetting effects on our business. Increased energy and transportation prices are expected to consume a significantly larger portion of consumer household incomes during the remaining winter heating season (first quarter of 2006), raising the possibility that we will experience some additional bad debt expense, as well as some margin erosion from increased consumer conservation. These higher prices have thus far been mitigated in part by significantly warmer-than-normal temperatures in the eastern United States during the first half of the heating season. While we expect these factors to have some impact on our financial results, primarily in the first half of 2006, we expect the regulatory and operational mechanisms in place in most of our regulated utility operationsjurisdictions will help mitigate our exposures to high natural gas prices.
Natural gas price volatility during 2005 made it further evident that we and our customers need to diversify our sources of natural gas supply. We will seek to enhancereceive the value and growthmajority of our existing utility assets by managing our capital spending effectively; pursuing customer growth opportunitiesnatural gas supplies from a production region in eachand around the Gulf of Mexico and generally, demand for this natural gas is growing faster than supply. This increased demand can often lead to higher natural gas prices and greater price volatility. We believe a diversification of our service areas; establishing a national reputation for excellent customer service by investingsupply portfolio, in systems, processes and people; workingan effort to achieve authorized returnsmoderate prices, is in each jurisdiction and,our customers’ best interest. We may need, from time to time, to invest in those jurisdictions where we have performance-based rates, sharing the benefits with our customers; and maintaining earnings and rate stability through regulatory compacts that fairly balance the interests of customers and shareholders.
Rapidly integrate the NUI assets and achieve the resulting strategic benefitsWe are working to integrate NUI’s assets into our portfolio of businesses and to provide the associated benefits to our customers and shareholders. Our integration plan includes applying enterprise-wide technology solutions and business processes that are designednew projects to improve the key business metrics we trackviability of such portfolio diversification and would expect to earn regulated returns on a regular basis and bringing NUI’s operations to a level of operational and service efficiency comparable to that of our other utility businesses. As part of this process, we also will evaluate certain NUI businesses for possible divestiture, consistent with our philosophy of exiting businesses that do not support our long-term strategy.such investments.
Focus on maintaining strong investment-grade profile and high levelTable of liquidityWe will continue to maintain a disciplined approach to capital spending and improving operating margins to optimize cash flow generation. Additionally, we seek to reduce in the near term our ratio of total debt to total capitalization in order to strengthen our balance sheet and allow us to respond to the capital needs of our operating businesses. We understand the importance of maintaining strong, investment-grade credit ratings in order to support our operating and investment needs, and we intend to execute our strategy in a way that enhances our ability to maintain or improve those ratings.Contents
Achieve appropriate regulatory outcomes that support stable utility earningsWe currently are involved in regulatory proceedings in GeorgiaThe market dynamics brought on by the two hurricanes presented opportunities for Sequent, and Tennessee. In Georgia, Atlanta Gas Light’s rate case is in process and expected to be completed by April 30, 2005. In Tennessee, we anticipate receiving a final ruling onfor our appeal of a 2004 Chattanooga Gas Company (Chattanooga Gas) rate case in the first quarter. Achieving favorable outcomes in these cases, and any other formal or informal regulatory proceedings in which we may be involved, is integral to the achievement of our earnings targets.
Selectively evaluate the acquisition of natural gas assetsWe will selectively examine and evaluate the acquisition of natural gas distribution, gas pipeline or other gas-related assets. Our acquisition criteria include the ability to generate operational synergies, strategic fit relative to our core competencies, value from near-term earnings contributions and adequate returns on invested capital, while maintaining or improving our investment-grade credit ratings.
Selectively expand our other energy businessesWe intend to continue to expand our wholesale services and natural gas storage businesses to provide disciplined incremental earnings growth for shareholders. Sequent intends to continue providing credits to our utility customersutilities through effective management of our affiliated utility assets. In our asset management business, we intend to grow our business with non-affiliated third parties, as well as the services we provide to our affiliated utilities, by providing producers with markets for their gas commodity; providing end-users with gas supply, storage and asset management options; and arbitraging pipeline and storage assets across various gas markets and time horizons. However, we intend to continue protecting our earnings-at-risk by maintaining our commitment to limited open-position and credit risks and by providing transparency and visibility to regulators under ourSequent’s affiliate asset management agreements. As our portfolioSequent drew on its knowledge of assets and our ability to store more physical gas inventory grow, the volatility of reported earnings from this business may increase. In our high deliverability underground storage business, we will seek to expand the operating capabilities of our existing facilities to provide more flexible and valuable injection and withdrawal capabilities for our customers. Pivotal Jefferson Island, LLC is currently expanding its compression capabilities to increase the number of times a customer can inject and withdraw natural gas. We will complete and begin operation of our propane peaking facility, and look for additional opportunities to provide economical peaking services in the regions in which our utilities operate.
Acquire and retain natural gas customersWe continuegrid to focus significant efforts in our distribution operations business on improving our net customer growth trends, despitemove gas from supply sources and deliver it to its customers, which involved moving gas over less traditional routes due to Gulf Coast infrastructure limitations. For additional information regarding the industry-wide challengesimpacts of rising prices for natural gas and competition from alternative fuels, declining natural gas usage per customer and declining regional load factors. In each of our utility service areas, we will continue to implement programs aimed at emphasizing natural gas as the fuel of choice for customers and maximizing the use of natural gas through a variety of promotional opportunities. We also are focused on similar customer growth initiatives in our SouthStar retail marketing business in Georgia. In addition, we continue to improve the credit quality of our customers in the retail marketing business and will use those techniques to improve credit and collections activities within our regulated utilities.
Continue to improve revenue and cash flow stability We have taken a number of actions in recent years to promote more stable and predictable revenues and cash flows in each of our business segments, as well as to moderate the effects of variable factors, such as weather and natural gas pricesthese hurricanes on our business, results. Somesee Results of the improvements we have initiated include performance-based ratemaking treatment in Georgia; weather normalization adjustment programs in VirginiaOperations - Distribution Operations and Tennessee; more efficient cost management and cash recovery from our environmental response cost (ERC) program in Georgia and reduced credit losses from our retail marketing business. We estimate that in 2005 our spending for property, plant and equipment will be $276 million compared to $264 million in 2004. Our capital expenditures should decrease in successive years by reduced spending related to the pipeline replacement program (PRP), a mandated regulatory program that has required significant expenditures. We expect to improve our net cash flow, which should provide enhanced financial flexibility around business investment opportunities and potentially a returnResults of capital to investors to provide additional shareholder value.
Operations - Wholesale Services.
Regulatory Environment
We continue to manage the ongoing challenge of operating in a regulatory environment that generally does not measure or reward innovation and operational efficiency. In particular, traditional "cost of service" regulation, which was originally designed to simulate the actions of a competitive market, has not kept pace with the vast changes taking place in the natural gas industry, in technology utilization and in the global economy. These are factors that to various degrees affect our company. The staffs of various state rate setting agencies have argued for significantly lower rates of return on regulated investments without adequate attention to the effects those lower returns might have on capital reinvestment in the company’s regulated asset base; the “opportunity cost” to customers of not providing better and more efficient services; and the disincentive for excellence in management and operations that such returns create.
Much of the rate setting is done in adversarial proceedings where rules of evidence and due process can vary greatly among the states. As a result of these ongoing regulatory challenges, we will continue to work cooperatively with our regulators, legislators and others as we seek, through rate freezes and performance-based rates, to create a framework in each jurisdiction that is conducive to our business goals. Furthermore, we will continue to make strategic investments in energy-related businesses that either are not subject to traditional state and federal rate regulation or are subject to limited oversight in order to add value for our shareholders.
In August 2005, the rate regulationEnergy Policy Act of 2005 (Energy Act) was enacted. The Energy Act authorized many broad energy policy provisions including significant funding for consumers and accountingbusinesses for energy-related activities, energy-related tax credits, accelerated depreciation for certain natural gas utility infrastructure investments and the repeal of the Public Utility Holding Company Act of 1935, as amended (PUHCA). The effective date of the PUHCA repeal is February 8, 2006. We continue to evaluate the Energy Act, but we expect to benefit from provisions in the legislation that will support our efforts to promote energy efficiency in a manner that benefits customers and shareholders.
The Energy Act gives the Federal Energy Regulatory Commission (FERC) increased authority over utility merger and acquisition activity, removes many of the geographic and structural restrictions on the ownership of public utilities and eliminates certain regulatory burdens. Some of the SEC reporting requirements, financing authorizations and affiliate relationship approvals that previously applied to us under the PUHCA were replaced by the requirements of various statethe Energy Act.
In addition, the Energy Act requires a public utility holding company to maintain its books and federal regulatory agencies in the jurisdictions in which we do business. We are committed to working cooperativelyrecords and constructively with the regulatory agencies in these states, as well as with federal regulatory agencies in a way that benefits our customers, shareholders and other stakeholders. We believe the dynamic energy environment in which we operate demands that we maintain an open, respectful and ongoing dialogue with these agencies. This posture is the best way to ensure we are working toward common solutionsmake them available to the many issuesFERC and to comply with certain reporting requirements. However, the FERC may exempt a class of entities or class of transactions if the FERC finds that they are not relevant to the jurisdictional rate of a public utility or natural gas company.
In February 2006, we requested an exemption from Energy Act oversight of our industry faces. These issues includelocal distribution companies that were previously exempt from regulation by the changing natureFERC. Our filing request will provide us with a temporary exemption. If the FERC has not taken action within 60 days of resource availability, pricing volatility, price levels and their effect on economic development in our service territories,request, the likelihood of increased importation of LNG and the needexemption shall be deemed to have been granted. We expect to qualify for reasonably-priced alternatives for our customers to meet their rapidly growing peak demands. an exemption from these reporting requirements.
For more information regarding pending federal and state regulatory matters, see "ResultsResults of Operations - Distribution Operations"Operations and “ResultsResults of Operations - Wholesale Services.”
Technology Initiatives
We continue to make progress with regard to several of our strategic technology initiatives. During the third quarter of 2004, we implemented new technological tools that enable marketers of natural gas in Georgia (Marketers) to create and input service orders directly into Atlanta Gas Light’s systems, eliminating the need for duplicate data entry or three-way calls between the customer, Marketers and our customer call center. This system allowed for a reduction in the number of customer service representatives servicing Marketers in our call center, while providing enhanced service to the Marketers. It also allowed us to further develop our strategy for the replacement of our customer information system, which should result in less capital investment over time than previously estimated.
In addition, we implemented our new energy trading and risk management (ETRM) system at Sequent in the fourth quarter of 2004. The ETRM system is designed to enhance internal controls and provide additional transparency into the activities of Sequent’s business. We also anticipate the system will enable Sequent to continue to grow its commercial business without significant growth in support staff.
Internal Controls
Section 404 of the Sarbanes-Oxley Act of 2002 (SOX 404) complianceSOX 404 and related rules of the SEC require management of public companies to assess the effectiveness of the company’s internal controls over financial reporting as of the end of each fiscal year. This includes disclosure of any material weaknesses in the company’s internal controls over financial reporting that have been identified by management. In addition, SOX 404 requires the company’s independent auditor to attest to and report on management’s annual assessment of the company’s internal controls over financial reporting. We have documented, tested and assessed our systems of internal control over financial reporting, as required under SOX 404 and Public Accounting Oversight Board Standard No. 2, “An Audit of Internal Control Over Financial Reporting Performed in Conjunction With An Audit of Financial Statements” (Standard No. 2), which was adopted in June 2004, to provide the basis for management’s report and our independent auditor’s attestation on the effectiveness of our internal control over financial reporting as of December 31, 2004. We estimate our SOX 404 compliance costs in 2004 were approximately $8 million, which include $5 million of external costs.
There are three levels of possible deficiencies in our internal controls over financial reporting that can be identified during our assessment phase, which are
· | an internal control deficiency, which exists when the design or the operation of a control does not allow management or employees, in the normal course of performing their functions, to prevent or detect misstatements on a timely basis |
· | a significant deficiency, which exists when an internal control deficiency or a combination of internal controls deficiencies adversely affects our ability to initiate, authorize, record, process or report financial data in accordance with accounting principles generally accepted in the United States of America (GAAP) such that there is a more than remote likelihood that a misstatement of the annual or interim financial statements that is more than inconsequential will not be prevented or detected |
· | a material weakness, which exists when a significant deficiency or a combination of significant deficiencies results in a more than remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected |
As a result, our assessment could result in two possible outcomes at our reporting date:Table of Contents
· | we could conclude that our internal controls over financial reporting were designed and were operating effectively, or |
· | we could conclude that our internal controls over financial reporting were not properly designed or did not operate effectively. A material weakness that exists at the reporting date would require our assessment to be that our internal controls over financial reporting are not effective, and we would be required to disclose such material weaknesses |
Our independent auditor is now required to issue three opinions annually, beginning with our 2004 consolidated financial statements. First, the auditor must evaluate and opine regarding the process by which we assessed the effectiveness of our internal controls over financial reporting. A second opinion must be issued as to the effectiveness of our internal controls over financial reporting. Finally, the independent auditor must issue an opinion, as is normally done, as to whether our consolidated financial statements are fairly presented, in all material respects.
The scope of our assessment of our internal controls over financial reporting included all of our consolidated entities except those falling under NUI, which we acquired on November 30, 2004, and Jefferson Island, which we acquired on October 1, 2004. In accordance with the SEC’s published guidance, we excluded these entities from our assessment as they were acquired late in the year, and it was not possible to conduct our assessment between the date of acquisition and the end of the year. SEC rules require that we complete our assessment of the internal control over financial reporting of these entities within one year from the date of acquisition.
We have completed the assessment of the effectiveness on our internal controls over financial reporting as of December 31, 2004, and have concluded that our controls are operating effectively. Our report on internal control over financial reporting is included in Item 9A, “Controls and Procedures,” and our independent auditors’ reports are included in Item 8, “Financial Statements and Supplementary Data,” following the notes to the financial statements.
NUI internal control weaknessesNUI’s external and internal auditors performed audits during NUI’s fiscal 2003 and 2004 years that identified material weaknesses in NUI’s internal controls. These weaknesses were previously discussed in NUI’s filings with the SEC. In March 2004, additional internal control issues and deficiencies were identified in the focused audit of NUI that was conducted at the request of the New Jersey Board of Public Utilities (NJBPU). These deficiencies resulted in a material weakness in internal controls over NUI’s financial reporting process and also resulted in a need for NUI to restate certain of its financial statements. The internal control deficiencies reported by NUI that were identified by NUI’s external and internal auditors included, but were not limited to, the following:
· | General ledger cash account balances were not being reconciled to the bank statements. |
· | General ledger account analyses were not being consistently performed. |
· | A listing of debt covenants was not being maintained. |
· | Comprehensive and formalized accounting and financial reporting policies and procedures did not exist. |
· | Instances were noted where management lacked certain technical accounting and tax expertise that resulted in accounting errors. |
· | The flow of accounting information between business units and corporate accounting was not timely or formalized. |
· | Accounts payable invoice processing procedures needed to be improved. |
· | A formal plan and implementation timetable needed to be developed to address compliance with the certification requirements of SOX 404. |
· | The contract review process was not formally documented, and appropriate procedures had not been developed to ensure timely review of contracts for accounting implications. |
· | There was a lack of adherence to policies and procedures for travel and entertainment expense reimbursements and procurement card expenditures. |
· | The payroll timekeeping and tracking process was manual in nature and prone to errors. |
· | Information technology had a number of areas where formal, documented policies and procedures had not been developed. |
The focused audit conducted at the request of the NJBPU revealed the following accounting concerns and weaknesses:
· | inappropriate and inaccurate treatment of intercompany payable and receivable balances |
· | inappropriate use of a common cash pool |
· | lack of a formal cash management agreement |
· | weaknesses in internal controls for accounts payable and receivable |
· | lack of formal or appropriate policies and procedures in certain accounting functions, and |
· | the need to audit procedures for fixed asset and continuing property records functions |
To address the deficiencies in its internal controls and procedures noted above, NUI expanded its internal controls and procedures to include the additional analysis and other post-closing procedures described below. The company
· | provided comprehensive in-house training in early fiscal 2004 covering the financial reporting process and internal accounting controls, including NUI’s written accounting policies and procedures and a policy on disclosure controls, to individuals who participate in the preparation of the company’s financial statements and required disclosures |
· | conducted meetings in which NUI’s President and CEO, Vice President and CFO, General Counsel and Secretary reviewed and discussed accounting and operational issues to ensure completeness and accuracy of disclosures in NUI’s SEC filings |
· | requested that NUI’s in-house counsel and key financial and operational personnel provide information regarding any known commitments and contingencies that may have financial statement and/or disclosure implications |
· | obtained internal certifications from key accounting and operational personnel indicating that they reviewed drafts of NUI’s SEC filings for completeness and accuracy |
· | conducted formal meetings, led by NUI’s Corporate Controller with participation of key accounting personnel (prior to closing the books of account and filing required reports), to identify and resolve accounting and disclosure issues |
· | prepared and distributed to participants involved in the preparation and review of NUI’s SEC filings a detailed time schedule outlining key dates and responsibilities for the preparation of financial information and required disclosures |
· | completed an audit disclosure checklist to ensure all disclosures required by GAAP and applicable securities laws and regulations were properly addressed |
· | assembled supporting documentation for disclosures made in its SEC filings |
· | retained external counsel to review drafts of its SEC filings to assist management in ensuring compliance with SEC rules and regulations |
· | created documentation, including flowcharts and formal written policies and procedures of NUI’s financial reporting process, to assist management with its responsibility to ensure key internal accounting controls are identified and addressed |
· | distributed a business ethics policy to all employees requesting their acknowledgement that they received, read and complied with the ethics policy |
· | conducted internal audits to evaluate internal accounting controls of key business functions |
We have initiated our efforts to assess the systems of internal control related to NUI’s business to comply with the requirements of both Sections 302 and 404 of the Sarbanes-Oxley Act of 2002. We believe that material deficiencies in internal controls discussed above related to the NUI business persists and that we are required to address and resolve these deficiencies. Our integration plans with respect to the NUI businesses include the integration and conversion of NUI’s accounting systems and internal control processes into our accounting systems and internal control processes, the majority of which we expect to complete during the first quarter of 2005. In addition, we have incorporated the NUI businesses into our disclosure control processes, which include the same or similar activities to those undertaken by NUI management described above, as well as other procedures, in our closing and financial reporting process.
We acquired Jefferson Island on October 1, 2004 and NUI on November 30, 2004. As a result, ourOur results of operations for 2004 includeincluded three months of the acquired operations of Jefferson Island and one month of the acquired operations of NUI.
Pursuant to FIN 46R,Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46) as revised, which we adopted in January 2004, we consolidated all of SouthStar’s accounts with our subsidiaries’ accounts as of January 1, 2004. WeFor the years ended December 31, 2005 and 2004, we recorded the Piedmont Natural Gas Company, Inc.’s (Piedmont) portion of SouthStar’s earnings as a minority interest in our statements of consolidated income and Piedmont’sthe Piedmont portion of SouthStar’s contributed capital as a minority interest onin our consolidated balance sheet.sheets. We eliminated any intercompany profits between segments.
In 2003, we accounted for our 70% noncontrolling financial ownership interest in SouthStar using the equity method of accounting because SouthStar did not meet the definition of a variable interest entity under FIN 46. Under the equity method, we reported our ownership interest in SouthStar as an investment in our consolidated balance sheets, and we reported our share of SouthStar’s earnings based on our ownership percentage in our statements of consolidated income as a component of other income.
Seasonality The operating revenues and EBIT of our distribution operations, retail energy operations and wholesale services segments are seasonal. During the heating season (October - March), natural gas usage and operating revenues are higher because generally more customers are connected to our distribution systems and because natural gas usage is higher in periods of colder weather than in periods of warmer weather. Approximately 70% of these segments’ operating revenues and EBIT for the year ended December 31, 2005 were generated during the six-month heating season and are reflected in our consolidated income statements for the quarters ended March 31, 2005 and December 31, 2005. Our base operating expenses, excluding cost of gas, interest expense and certain incentive compensation costs, are incurred relatively equally over any given year. Thus our operating results vary significantly from quarter to quarter as a result of seasonality. Seasonality also affects the comparison of certain balance sheet items such as receivables, unbilled revenue, inventories and short-term debt across quarters.
HedgingChanges in commodity prices subject a significant portion of our operations to variability. Commodity prices tend to be higher in colder months. Our nonutility businesses principally use physical and financial arrangements to economically hedge the risks associated with both seasonal fluctuations and changing commodity prices. In addition, because these economic hedges are generally not designated for hedge accounting treatment, our reported earnings for the wholesale services and retail energy operations segments reflect changes in the fair values of certain derivatives; these values may change significantly from period to period.
Elizabethtown Gas utilizes certain derivatives to hedge the impact of market fluctuations in natural gas prices. These derivative products are marked to market each reporting period. In accordance with regulatory requirements, realized gains and losses related to these derivatives are reflected in purchased gas costs and ultimately included in billings to customers. Unrealized gains and losses are reflected as a regulatory asset (loss) or liability (gain), as appropriate, in our consolidated balance sheets.
Revenues We generate nearly all of our operating revenues through the sale, distribution and storage of natural gas. We include in our consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period. We record these estimated revenues as unbilled revenues onin our consolidated balance sheet.sheets.
A significant portion
Operating marginMargin and EBIT We evaluate the performance of our operating segments using the measures of operating margin and EBIT. We believe operating margin is a better indicator than revenues for the contribution resulting from customer growth in our distribution operations segment since the cost of gas can vary significantly and is generally passed directly to our customers. We also consider operating margin to be a better indicator in our retail energy operations, wholesale services and energy investments segments since it is a direct measure of gross profit before overhead costs. We believe EBIT is a useful measurement of our operating segments’ performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.
Our operating margin and EBIT are not measures that are considered to be calculated in accordance with GAAP.accounting principles generally accepted in the United States of America (GAAP). You should not consider operating margin or EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our operating margin or EBIT measuresmeasure may not be comparable to a similarly titled measuremeasures of another company. other companies.
The following are reconciliationstable sets forth a reconciliation of our operating margin and EBIT to our operating income and net income, andtogether with other consolidated financial information for the years ended December 31, 2004,2005 and 2004; and pro-forma results as if SouthStar’s accounts were consolidated with our subsidiaries’ accounts for the year ended December 31, 2003. The unaudited pro-forma results are presented for comparative purposes as a result of our consolidation of SouthStar’s accounts with our subsidiaries’ accounts as of January 1, 2004. This pro-forma basis is a non-GAAP presentation; however, we believe it is useful to readers of our financial statements since it presents our revenues and expenses for 2003 on the same basis as 2005 and 2002.2004.
In millions | | 2005 | | 2004 | | Pro-forma 2003 | |
Operating revenues | | $ | 2,718 | | $ | 1,832 | | $ | 1,557 | |
Cost of gas | | | 1,626 | | | 995 | | | 789 | |
Operating margin | | | 1,092 | | | 837 | | | 768 | |
Operating expenses | | | | | | | | | | |
Operation and maintenance | | | 477 | | | 377 | | | 343 | |
Depreciation and amortization | | | 133 | | | 99 | | | 92 | |
Taxes other than income | | | 40 | | | 29 | | | 28 | |
Total operating expenses | | | 650 | | | 505 | | | 463 | |
Gain on sale of Caroline Street campus | | | - | | | - | | | 16 | |
Operating income | | | 442 | | | 332 | | | 321 | |
Other losses | | | (1 | ) | | - | | | (6 | ) |
Minority interest | | | (22 | ) | | (18 | ) | | (17 | ) |
EBIT | | | 419 | | | 314 | | | 298 | |
Interest expense | | | 109 | | | 71 | | | 75 | |
Earnings before income taxes | | | 310 | | | 243 | | | 223 | |
Income taxes | | | 117 | | | 90 | | | 87 | |
Income before cumulative effect of change in accounting principle | | | 193 | | | 153 | | | 136 | |
Cumulative effect of change in accounting principle | | | - | | | - | | | (8 | ) |
Net income | | $ | 193 | | $ | 153 | | $ | 128 | |
Basic earnings per common share: | | | | | | | | | | |
Income before cumulative effect of change in accounting principle | | $ | 2.50 | | $ | 2.30 | | $ | 2.15 | |
Cumulative effect of change in accounting principle | | | - | | | - | | | (0.12 | ) |
Basic earnings per common share | | $ | 2.50 | | $ | 2.30 | | $ | 2.03 | |
Fully diluted earnings per common share: | | | | | | | | | | |
Income before cumulative effect of change in accounting principle | | $ | 2.48 | | $ | 2.28 | | $ | 2.13 | |
Cumulative effect of change in accounting principle | | | - | | | - | | | (0.12 | ) |
Fully diluted earnings per common share | | $ | 2.48 | | $ | 2.28 | | $ | 2.01 | |
Weighted average number of common shares outstanding: | | | | | | | | | | |
Basic | | | 77.3 | | | 66.3 | | | 63.1 | |
Diluted | | | 77.8 | | | 67.0 | | | 63.7 | |
Segment information Operating revenues, operating margin and EBIT information for each of our segments are presented in the following table for the years ended December 31, 2005, 2004 and 2003:
In millions | | Operating revenues | | Operating margin | | EBIT | |
2005 | | | | | | | |
Distribution operations | | $ | 1,753 | | $ | 814 | | $ | 299 | |
Retail energy operations | | | 996 | | | 146 | | | 63 | |
Wholesale services | | | 95 | | | 92 | | | 49 | |
Energy investments | | | 56 | | | 40 | | | 19 | |
Corporate (1) | | | (182 | ) | | - | | | (11 | ) |
Consolidated | | $ | 2,718 | | $ | 1,092 | | $ | 419 | |
2004 | | | | | | | | | | |
Distribution operations | | $ | 1,111 | | $ | 640 | | $ | 247 | |
Retail energy operations | | | 827 | | | 132 | | | 52 | |
Wholesale services | | | 54 | | | 53 | | | 24 | |
Energy investments | | | 25 | | | 13 | | | 7 | |
Corporate (1) | | | (185 | ) | | (1 | ) | | (16 | ) |
Consolidated | | $ | 1,832 | | $ | 837 | | $ | 314 | |
2003 | | | | | | | | | | |
Distribution operations | | $ | 936 | | $ | 599 | | $ | 247 | |
Retail energy operations (2) | | | 743 | | | 124 | | | 46 | |
Wholesale services | | | 41 | | | 40 | | | 20 | |
Energy investments | | | 6 | | | 5 | | | (3 | ) |
Corporate (1) (2) | | | (169 | ) | | - | | | (12 | ) |
Consolidated | | $ | 1,557 | | $ | 768 | | $ | 298 | |
In millions | | 2004 | | 2003 | | 2002 | |
Operating revenues | | $ | 1,832 | | $ | 983 | | $ | 877 | |
Cost of gas | | | 994 | | | 339 | | | 268 | |
Operating margin | | | 838 | | | 644 | | | 609 | |
Operating expenses | | | | | | | | | | |
Operation and maintenance | | | 377 | | | 283 | | | 274 | |
Depreciation and amortization | | | 99 | | | 91 | | | 89 | |
Taxes other than income taxes | | | 30 | | | 28 | | | 29 | |
Total operating expenses | | | 506 | | | 402 | | | 392 | |
Gain on sale of Caroline Street campus | | | - | | | 16 | | | - | |
Operating income | | | 332 | | | 258 | | | 217 | |
Other income | | | - | | | 40 | | | 30 | |
Minority interest | | | (18 | ) | | - | | | - | |
EBIT | | | 314 | | | 298 | | | 247 | |
Interest expense | | | 71 | | | 75 | | | 86 | |
Earnings before income taxes | | | 243 | | | 223 | | | 161 | |
Income taxes | | | 90 | | | 87 | | | 58 | |
Income before cumulative effect of change in accounting principle | | | 153 | | | 136 | | | 103 | |
Cumulative effect of change in accounting principle | | | - | | | (8 | ) | | - | |
Net income | | $ | 153 | | $ | 128 | | $ | 103 | |
Basic earnings per common share | | | | | | | | | | |
Income before cumulative effect of change in accounting principle | | $ | 2.30 | | $ | 2.15 | | $ | 1.84 | |
Cumulative effect of change in accounting principle | | | - | | | (0.12 | ) | | - | |
Basic earnings per common share | | $ | 2.30 | | $ | 2.03 | | $ | 1.84 | |
Fully diluted earnings per common share | | | | | | | | | | |
Income before cumulative effect of change in accounting principle | | $ | 2.28 | | $ | 2.13 | | $ | 1.82 | |
Cumulative effect of change in accounting principle | | | - | | | (0.12 | ) | | - | |
Fully diluted earnings per common share | | $ | 2.28 | | $ | 2.01 | | $ | 1.82 | |
Weighted average number of common shares outstanding | | | | | | | | | | |
Basic | | | 66.3 | | | 63.1 | | | 56.1 | |
Fully diluted | | | 67.0 | | | 63.7 | | | 56.6 | |
(1) | Includes the elimination of intercompany revenues. |
(2) | Includes pro-forma results as if SouthStar’s accounts were consolidated with our subsidiaries’ accounts. |
In the following table, our reported results in 2003 are reconciled to the pro-forma presentation presented in the tables above. In 2003, we recognized our portion of SouthStar’s earnings of $46 million as equity earnings. The amounts presented below for SouthStar represent 100% of its revenues and expenses for 2003 and include minority interest which adjusts our 80% share of SouthStar’s earnings to reflect Piedmont’s and Dynegy Inc.’s share of SouthStar’s earnings.
| | For the twelve months ended December 31, 2003 | |
| | As | | South- | | Elimin- | | Pro- | |
In millions | | Reported | | Star | | ations | | Forma | |
Operating revenues | | $ | 983 | | $ | 743 | | $ | (169 | ) | $ | 1,557 | |
Cost of gas | | | 339 | | | 619 | | | (169 | ) | | 789 | |
Operating margin | | | 644 | | | 124 | | | - | | | 768 | |
Operating expenses | | | | | | | | | | | | | |
Operation and maintenance | | | 283 | | | 60 | | | - | | | 343 | |
Depreciation and amortization | | | 91 | | | 1 | | | - | | | 92 | |
Taxes other than income | | | 28 | | | - | | | - | | | 28 | |
Total operating expenses | | | 402 | | | 61 | | | - | | | 463 | |
Gain on sale of Caroline Street campus | | | 16 | | | - | | | - | | | 16 | |
Operating income | | | 258 | | | 63 | | | - | | | 321 | |
Equity earnings from SouthStar | | | 46 | | | - | | | (46 | ) | | - | |
Other losses | | | (6 | ) | | - | | | - | | | (6 | ) |
Minority interest | | | - | | | (17 | ) | | - | | | (17 | ) |
EBIT | | | 298 | | | 46 | | | (46 | ) | | 298 | |
Interest expense | | | 75 | | | - | | | - | | | 75 | |
Earnings before income taxes | | | 223 | | | 46 | | | (46 | ) | | 223 | |
Income taxes | | | 87 | | | - | | | - | | | 87 | |
Income before cumulative effect of change in accounting principle | | $ | 136 | | $ | 46 | | $ | (46 | ) | $ | 136 | |
Discussion of Consolidated Results
20042005 compared to 20032004 Our earnings per share and net income for the year ended December 31, 2005 were higher than the prior year due to the acquisitions of NUI and Jefferson Island combined with strong contributions from our wholesale services and retail energy operations businesses.
Consolidated EBIT for 2005 increased by $105 million or 33% from the previous year, of which $56 million related to EBIT contributions from the 2004 acquisitions of NUI and Jefferson Island and from Pivotal Propane of Virginia, Inc. (Pivotal Propane) which became operational in 2005. The increase further reflected increased contributions of $8 million from Atlanta Gas Light in distribution operations, $11 million from retail energy operations and $3 million from AGL Networks, LLC (AGL Networks) in energy investments. Wholesale services’ EBIT increased $25 million primarily due to increased operating margins partially offset by higher operating expenses. The corporate segment improved by $5 million as compared to last year primarily due to merger and acquisition related costs incurred in 2004 but not in 2005.
Operating margin increased $255 million or 30%, primarily reflecting the NUI and Pivotal Jefferson Island acquisitions and completion of the Pivotal Propane facility in Virginia, as well as improved margins at SouthStar, Sequent and AGL Networks. Excluding the addition of the NUI utilities, distribution operations’ margins improved by $8 million mainly as a result of higher pipeline replacement revenues and additional carrying costs charged to retail marketers in Georgia for gas storage. Retail energy operations’ margins were up $14 million, due primarily to higher commodity margins. Wholesale services' operating margin increased $39 million year over year, primarily due to activity during the third and fourth quarters of 2005. Energy investments’ margins were also up $27 million, primarily as a result of the acquisition of Jefferson Island that contributed $13 million; contributions from NUI’s nonutility businesses of $8 million; contribution from Pivotal Propane of $3 million; and improved operating margin at AGL Networks of $4 million.
Operating expenses increased $145 million or 29%, primarily as a result of $124 million in higher expenses at distribution operations due to the addition of NUI. In addition, operating expenses at energy investments increased $15 million due to the addition of Jefferson Island, the NUI nonutility assets and Pivotal Propane. Operating expenses at wholesale services increased $13 million due to increased payroll and employee incentive compensation costs resulting from its operational and financial growth and depreciation on a trading and risk management system placed in service during 2004. The increased operating expenses were offset by lower corporate operating expenses primarily due to prior-year costs incurred with merger and acquisition activities.
Interest expense for 2005 was $109 million, or $38 million higher than in 2004. As indicated in the table below, higher short-term interest rates and higher debt outstanding combined to increase our interest expense in 2005 relative to the previous year. The increase of $549 million in average debt outstanding for 2005 compared to 2004 was due to additional debt incurred as a result of the acquisitions of NUI and Jefferson Island, and higher working capital requirements as a result of higher natural gas prices.
Dollars in millions | | 2005 | | 2004 | |
Total interest expense | | $ | 109 | | $ | 71 | |
Average debt outstanding (1) | | | 1,823 | | | 1,274 | |
Average interest rate | | | 6.0 | % | | 5.6 | % |
(1) | Daily average of all outstanding debt |
We anticipate our interest expense in 2006 will be higher than in 2005 due to higher projected interest rates. Based on $728 million of variable-rate debt, which includes $522 million of our short-term debt, $100 million of variable-rate senior notes and $106 million of variable-rate gas facility revenue bonds outstanding at December 31, 2005, a 100 basis point change in market interest rates from 4.7% to 5.7% would result in an increase in annual pretax interest expense of $7 million.
The increase in income tax expense of $27 million or 30% for 2005 compared to 2004 reflected additional income taxes of $25 million due to higher corporate earnings year over year and $2 million due to a slightly higher effective tax rate of 38% for 2005 as compared to 37% in 2004. We expect our effective tax rate for the year ending December 31, 2006 to be similar to the effective rate for the year ended December 31, 2005.
As a result of our 11 million share equity offering in November 2004, earnings results for the year are based on weighted average shares outstanding of 77.3 million, while 2004 results were based on weighted average shares outstanding of 66.3 million.
2004 compared to 2003 Our EBIT for the year ended December 31, 2004 was higher than the prior year due to stronger contributions from our wholesale services business SouthStar and retail energy operations and from the acquisitions of NUI and Jefferson Island. The following table provides a summary of certain items that impacted 2004 earnings.
In millions | | Increase (Decrease) in 2004 Operating Income (Before Taxes) | |
Accelerated recognition of margins associated with Sequent storage positions originally were anticipated to be liquidated in the first quarter of 2005 | | $ | 5 | |
Asset sales in the second quarter of 2004 for a residential and retail property in Savannah, Georgia which resulted in a $2 million contribution to EBIT and the sale of our remaining investment units in U.S. Propane LP | | | 3 | |
Change in Atlanta Gas Light’s property taxes as a result of revised estimates and intangible property tax assessment | | | 3 | |
Contributions to the AGL Resources Private Foundation Inc. and for energy assistance by our subsidiary SouthStar | | | (3 | ) |
The distribution operations segment’sConsolidated EBIT for 2004 was $247increased $16 million equalor 5% as compared to 2003, results.of which $10 million related to EBIT contributions from our acquisitions of NUI ($7 million) and Jefferson Island ($3 million) during the fourth quarter of 2004. Distribution operations’ EBIT for 2004 remained relatively flat as compared to 2003. For comparison purposes, however, the distribution operations segment’soperations’ EBIT in 2004 increased by $13 million after excluding the effect of a net $13 million pretax gain on the salesales of company property and a related charitable contribution in 2003. In addition,2003.The increase further reflected increased contributions from SouthStar in retail energy operations of $6 million, AGL Networks in energy investments of $3 million and Sequent in wholesale services of $4 million. Additionally, our energy investments segment had a $4 million increase in EBIT due to the 2004 EBIT includessale of Heritage Propane and of a $7residential development property in Savannah, Georgia. These increases were partially offset by lower contributions of $4 million contribution from NUI.our corporate segment due to increased outside service costs associated with software maintenance, licensing and implementation of our work management project, higher costs due to Section 404 of the Sarbanes-Oxley Act of 2002 (SOX 404) compliance efforts and merger and acquisition related costs.
OperatingOur operating margin for 2004 increased $69 million or 9% as compared to 2003 pro-forma operating margin, primarily reflecting the 2004 NUI and Jefferson Island acquisitions, which contributed $29 million. Sequent, SouthStar and AGL Networks also had improved 2004 operating margins of $13 million, $8 million (on a pro-forma basis) and $2 million, respectively. Excluding the addition of the NUI utilities, distribution operations segmentoperations’ margins improved by $17 million mainly at Atlanta Gas Light and Virginia Natural Gas. Atlanta Gas Light’s operating margin increased as a result of higher pipeline replacement revenues, additional carrying costs charged to retail marketers in Georgia for gas storage, customer growth and higher customer usage. Virginia Natural Gas’ operating margin increased primarily due to customer growth.
Operating expenses increased $42 million on a pro-forma basis or 7%,9% primarily as a result of $19 million in higher expenses due to the additions of NUI and Jefferson Island. In addition, operating expenses at wholesale services increased $9 million due to increased outside service costs related to its energy trading and risk management system and SOX 404 compliance projects and an increase in the number of employees, as well as increased depreciation. Excluding the effects of our acquisition of NUI, ($25 million) and an approximately 2% increase in the total number of average connected customers at Atlanta Gas Light, Chattanooga Gas and Virginia Natural Gas. Operatingdistribution operations’ expenses increased $29$10 million or 8% in 2004 relative to 2003, primarily as a result of NUI ($19 million) and increased costs related to information technology projects, regulatory activities (including Sarbanes-Oxley compliance)SOX 404 compliance and depreciation expense, offset by decreased bad debt expense andexpense. Our corporate segment also had a decrease$6 million increase in operating expenses primarily from increased outside service costs associated with postretirement benefits.
The wholesale services segment contributed $24 million in EBIT in 2004 compared with $20 million in 2003. The $4 million increase is primarily the result of unusually strong fourth-quarter 2004 results, reflecting the accelerated recognition of margins associated with storage positions that originally were anticipated to be liquidated in the first quarter of 2005. The accelerated margin recognition resulted in $5 million of operating income in the fourth quarter that otherwise would have been recognized in the first quarter of 2005. Primarilysoftware maintenance, licensing and implementation projects, as a result of the decline in forward gas prices at the end of December 2004,well as for SOX 404 compliance efforts and the positive mark-to-market impact that decline had on the futures contracts Sequent utilizes to economically hedge its storage positions, approximately $18 million or 75% of Sequent’s full-year EBIT contribution was generated in the fourth quarter of 2004.
Sequent also continued to increase its volumesmerger and business transaction activity in 2004. Full-year volumesacquisition activities. These increased 20%, from 1.75 billion cubic feet (Bcf) per day in 2003 to 2.10 Bcf per day in 2004. New peaking and third-party asset management transactions also contributed to strong results for the year. Sequent’s operating expenses for 2004 were $29offset by a $2 million compared with $20 million in 2003. The increase was due primarily to increased personnel and increased costs associated with the implementation of a new energy trading and risk management system and Sarbanes-Oxley 404 compliance.
The energy investments segment contributed EBIT of $59 million in 2004, a 37% increase over the segment’s $43 million contribution in 2003. The primary driver of this segment’s results was the performance of SouthStar, which contributed $53 million in EBIT in 2004 compared with $46 million in 2003. The improved resultsdecrease at SouthStar on a pro-forma basis mainly reflected higher commodity margins and decreaseddue to lower bad debt expense during the year. Energy investments’ EBIT contribution increased due tooffset by higher contributions from AGL Networkscorporate allocated overhead and the acquisition of Jefferson Island in October 2004.
The corporate segment EBIT contribution decreased by $4 million to ($16) million in 2004, primarily the result of costs associated with information technology projects, SOX 404 compliance and merger-and-acquisition related expenses.costs.
Interest expense for 2004 was $71 million which wasor $4 million lower than in 2003. AAs shown in the following table, a favorable interest rate environment and the issuance of lower-interest long-term debt combined to lower the company’s interest expense in 2004 relative to the previous year. The increase of $19 million in average debt outstanding for 2004 compared to 2003 was due to additional debt incurred as a result of the acquisitions of NUI and Jefferson Island.
Dollars in millions | | 2004 | | 2003 | | 2004 vs. 2003 | |
Interest rate | | $ | 71 | | $ | 75 | | | ($4 | ) |
Average debt outstanding(1) | | | 1,274 | | | 1,255 | | | 19 | |
Average rate | | | 5.6 | % | | 6.0 | % | | (0.4 | %) |
Dollars in millions | | 2004 | | 2003 | |
Total interest expense | | $ | 71 | | $ | 75 | |
Average debt outstanding (1) | | | 1,274 | | | 1,255 | |
Average interest rate | | | 5.6 | % | | 6.0 | % |
(1) | Daily average of all outstanding debt |
Based on variable-rate debt outstanding at December 31, 2004, a 100 basis point change in market interest rates from 3.1% to 4.1% would result in a change in annual pretax interest expense of $5 million. We anticipate that our interest expense in 2005 will be higher than in 2004 due to the following:
· | higher projected short-term interest rates based upon higher 2005 London Interbank Offered Rate (LIBOR) rates |
· | higher debt balances and higher interest rates from 2004 and 2005 on debt issued for the acquisitions of NUI and Jefferson Islanddebt. |
The increase in income tax expense of $3 million or 3% for 2004 as compared to 2003 reflected $8 million of additional income taxes due to higher corporate earnings year-over-year,year over year, offset by a $5 million decrease in income taxes due to a decrease in the effective tax rate from 39% in 2003 to 37% in 2004. The decline in the effective tax rate was primarily the result of income tax adjustments recorded in the third quarter of 2004 in connection with our annual comparison of our filed tax returns to the related income tax accruals. We expect our effective tax rate for the year ending December 31, 2005 to be higher due to the favorable adjustments recorded in 2004 and the higher state income tax rate that will be applicable to earnings from Elizabethtown Gas in New Jersey.
As a result of the company’s 11-millionour 11 million share equity offering in November 2004, earnings results for the year are based on weighted average shares outstanding of 66.3 million, while 2003 results were based on weighted average shares outstanding of 63.1 million. Currently, we have approximately 76.9 million shares outstanding.
2003 compared to 2002Net income increased $25 million or 24% from 2002, reflecting higher earnings at each operating segment. EBIT from distribution operations, excluding the net gain on the sale of the Caroline Street campus of $13 million, increased 4% to $234 million from $225 million in 2002 due to higher operating margins, an increase in the number of connected customers and increased pipeline replacement revenue in 2003. Wholesale services contributed $20 million in EBIT compared to $9 million in 2002. The earnings improvement resulted primarily from Sequent’s optimization of various transportation and storage assets and increased physical volumes sold as well as increased margins driven by favorable pricing and market volatility, particularly in the first quarter of 2003.
Energy investments contributed $43 million in EBIT compared to $24 million in 2002. SouthStar accounted for the majority of the increase, and its results were driven primarily by higher operating margins, reduced bad debt expense, our expanded ownership interest in the business and the resolution of an income-sharing issue with Piedmont. Our corporate segment’s expenses decreased primarily as a result of favorable interest expense and lower average debt balances. The 7 million share increase in our weighted average shares outstanding was a result of our 6.4 million share equity offering in February 2003.
The following table shows the impact of the 2003 sale of our Caroline Street campus and the related donation to the private foundation:
In millions | | Distribution Operations | | Corporate | | Consolidated | |
Gain (loss) on sale of Caroline Street campus | | $ | 21 | | | ($5 | ) | $ | 16 | |
Donation to private foundation | | | (8 | ) | | - | | | (8 | ) |
EBIT | | | 13 | | | (5 | ) | | 8 | |
Income taxes | | | | | | | | | (3 | ) |
Net income | | | | | | | | $ | 5 | |
The decrease in interest expense of $11 million or 13% for 2003 as compared to 2002 was a result of lower average debt balances, as shown in the following table, due primarily to the proceeds generated from our public offering of 6.4 million shares of common stock in February 2003; repayment of Medium-Term notes, which had higher rates than our bond issuance in July 2003; the benefits of our interest rate swaps; and lower interest rates on commercial paper borrowings.
Dollars in millions | | 2003 | | 2002 | | 2003 vs. 2002 | |
Total interest expense | | $ | 75 | | $ | 86 | | | ($11 | ) |
Average debt outstanding(1) | | | 1,255 | | | 1,412 | | | (157 | ) |
Average rate | | | 6.0 | % | | 6.1 | % | | (0.1 | %) |
(1) | Daily average of all outstanding debt |
The increase in income tax expense of $29 million or 50% for 2003 compared to 2002 was primarily due to the increase in earnings before income taxes of $62 million or 39% and an increase in our effective tax rate from 36% in 2002 to 39% in 2003. The increase in the effective tax rate for 2003 was primarily due to higher projected state income taxes resulting from a change in Georgia law governing the methodology by which Georgia companies must compute their tax liabilities and to the accrual of deferred tax liabilities related to temporary differences between the book and tax basis of some of our assets.
ConsolidationTable of SouthStarBelow are our unaudited pro-forma condensed consolidated balance sheet and statement of income, presented as if SouthStar’s balances were consolidated with our subsidiaries’ accounts as of December 31, 2003. This pro-forma presentation is a non-GAAP presentation; however, we believe this pro-forma presentation is useful to the readers of our financial statements since it presents our financial statements for prior years on the same basis as 2004 following our consolidation of SouthStar pursuant to our adoption of FIN 46R. These unaudited pro-forma amounts are presented only for comparative purposes. The eliminations include intercompany eliminations, our investment in SouthStar, SouthStar’s capitalization and our equity in earnings from SouthStar.Contents
AGL Resources Inc. and Subsidiaries | |
Pro-forma condensed consolidated balance sheet | |
December 31, 2003 | |
| | | | | | | | | |
In millions | | As Reported | | SouthStar | | Eliminations | | (Unaudited) Pro-forma | |
Current assets | | $ | 742 | | $ | 174 | | | ($11 | ) | $ | 905 | |
Property, plant and equipment | | | 2,352 | | | 2 | | | - | | | 2,354 | |
Deferred debits and other assets(1) | | | 878 | | | - | | | (71 | ) | | 807 | |
Total assets | | $ | 3,972 | | $ | 176 | | | ($82 | ) | $ | 4,066 | |
Current liabilities | | $ | 1,048 | | $ | 75 | | | ($11 | ) | $ | 1,112 | |
Accumulated deferred income taxes | | | 376 | | | - | | | - | | | 376 | |
Long-term liabilities | | | 569 | | | - | | | - | | | 569 | |
Deferred credits | | | 78 | | | - | | | - | | | 78 | |
Minority interest(2) | | | - | | | - | | | 30 | | | 30 | |
Capitalization | | | 1,901 | | | 101 | | | (101 | ) | | 1,901 | |
Total liabilities and capitalization | | $ | 3,972 | | $ | 176 | | | ($82 | ) | $ | 4,066 | |
(1) | Our investment in SouthStar was $71 million. |
(2) | Minority interest adjusts our balance sheet to reflect Piedmont’s portion of SouthStar’s contributed capital. |
AGL Resources Inc. and Subsidiaries | |
Pro-forma condensed consolidated statement of income | |
for the year ended December 31, 2003 | |
| | | | | | | | | |
In millions | | As Reported | | SouthStar(1) | | Eliminations | | (Unaudited) Pro-forma | |
Operating revenues | | $ | 983 | | $ | 746 | | | ($169 | ) | $ | 1,560 | |
Operating expenses | | | | | | | | | | | | | |
Cost of gas | | | 339 | | | 622 | | | (169 | ) | | 792 | |
Operation and maintenance expenses | | | 283 | | | 60 | | | - | | | 343 | |
Depreciation and amortization | | | 91 | | | 1 | | | - | | | 92 | |
Taxes other than income | | | 28 | | | - | | | - | | | 28 | |
Total operating expenses | | | 741 | | | 683 | | | (169 | ) | | 1,255 | |
Gain on sale of Caroline Street campus | | | 16 | | | - | | | - | | | 16 | |
Operating income | | | 258 | | | 63 | | | - | | | 321 | |
Equity earnings from SouthStar | | | 46 | | | - | | | (46 | ) | | - | |
Donation to private foundation | | | (8 | ) | | - | | | - | | | (8 | ) |
Other income | | | 2 | | | - | | | - | | | 2 | |
Interest expense | | | (75 | ) | | - | | | - | | | (75 | ) |
Minority interest in income of consolidated subsidiary(2) | | | - | | | - | | | (17 | ) | | (17 | ) |
Earnings before income taxes | | | 223 | | | 63 | | | (63 | ) | | 223 | |
Income taxes | | | (87 | ) | | - | | | - | | | (87 | ) |
Income before cumulative effect of change in accounting principle | | $ | 136 | | $ | 63 | | | ($63 | ) | $ | 136 | |
(1) | Includes 100% of SouthStar’s revenues and expenses for comparisons of SouthStar’s consolidation in 2004. |
(2) | Minority interest adjusts our earnings to reflect our 80% share of SouthStar’s earnings, less Dynegy Inc.’s 20% share of SouthStar’s income prior to February 18, 2003. |
AGL Resources Inc. and Subsidiaries | |
Pro-forma condensed consolidated statement of income | |
for the year ended December 31, 2002 | |
| | | | | | | | | |
In millions | | As Reported | | SouthStar(1) | | Eliminations | | (Unaudited) Pro-forma | |
Operating revenues | | $ | 877 | | $ | 630 | | | ($171 | ) | $ | 1,336 | |
Operating expenses | | | | | | | | | | | | | |
Cost of gas | | | 268 | | | 515 | | | (171 | ) | | 612 | |
Operation and maintenance expenses | | | 274 | | | 72 | | | - | | | 346 | |
Depreciation and amortization | | | 89 | | | 2 | | | - | | | 91 | |
Taxes other than income | | | 29 | | | - | | | - | | | 29 | |
Total operating expenses | | | 660 | | | 589 | | | (171 | ) | | 1,078 | |
Operating income | | | 217 | | | 41 | | | - | | | 258 | |
Equity earnings from SouthStar | | | 27 | | | - | | | (27 | ) | | - | |
Other income | | | 3 | | | 1 | | | - | | | 4 | |
Interest expense | | | (86 | ) | | - | | | - | | | (86 | ) |
Minority interest in income of consolidated subsidiary(2) | | | - | | | - | | | (15 | ) | | (15 | ) |
Earnings before income taxes | | | 161 | | | 42 | | | (42 | ) | | 161 | |
Income taxes | | | (58 | ) | | - | | | - | | | (58 | ) |
Net income | | $ | 103 | | $ | 42 | | | ($42 | ) | $ | 103 | |
(1) | Includes 100% of SouthStar’s revenues and expenses for comparisons of SouthStar’s consolidation in 2004. |
(2) | Minority interest adjusts our earnings to reflect our 50% share of SouthStar’s earnings. |
Segment information Operating revenues, operating margin and EBIT information for each of our segments are contained in the following table for the years ended December 31, 2004, 2003 and 2002:
2004(in millions) | | Operating revenues | | Operating margin | | EBIT | |
Distribution operations | | $ | 1,111 | | $ | 641 | | $ | 247 | |
Wholesale services | | | 54 | | | 53 | | | 24 | |
Energy investments | | | 852 | | | 145 | | | 59 | |
Corporate (1) | | | (185 | ) | | (1 | ) | | (16 | ) |
Consolidated | | $ | 1,832 | | $ | 838 | | $ | 314 | |
2003 | | | | | | | | | | |
Distribution operations | | $ | 936 | | $ | 599 | | $ | 247 | |
Wholesale services | | | 41 | | | 40 | | | 20 | |
Energy investments | | | 6 | | | 5 | | | 43 | |
Corporate | | | - | | | - | | | (12 | ) |
Consolidated | | $ | 983 | | $ | 644 | | $ | 298 | |
2002 | | | | | | | | | | |
Distribution operations | | $ | 852 | | $ | 585 | | $ | 225 | |
Wholesale services | | | 23 | | | 23 | | | 9 | |
Energy investments | | | 2 | | | 1 | | | 24 | |
Corporate | | | - | | | - | | | (11 | ) |
Consolidated | | $ | 877 | | $ | 609 | | $ | 247 | |
(1) | Includes the elimination of intercompany revenues. |
Distribution Operations
Distribution operations includes our natural gas local distribution utility companies whichthat construct, manage and maintain natural gas pipelines and distribution facilities and serve more than 2.2 million end-use customers. Distribution operations’ revenues contributed 61% of our consolidated revenues for 2004, 95% for 2003 and 97% for 2002. The decrease of 34% in the contribution of distribution operations’ revenues from 2003 is due to the impact of our consolidation of SouthStar in 2004. The following table provides operational information for our larger utilities. The daily capacity represents total system capability, and the storage capacity includes on-system LNGliquefied natural gas (LNG) and propane volumes.
| Atlanta Gas Light | Elizabethtown Gas | Virginia Natural Gas | Florida Gas | Chattanooga Gas |
| | | | | |
Average end-use customers (in thousands) (1) | 1,533 | 266 | 256 | 104 | 60 |
Daily capacity (2) | 2.5 | 0.4 | 0.4 | 0.1 | 0.2 |
Storage capacity(2) | 55.6 | 14.0 | 10.2 | - | 4.8 |
2004 peak day demand (2) | 1.8 | 0.4 | 0.3 | 0.04 | 0.1 |
Average monthly throughput (2) | 19.8 | 5.0 | 2.9 | 0.8 | 1.4 |
| | | | | |
Authorized return on rate base (3) (4) | 9.16% | 7.95% | 9.24% | 7.36% | 7.43% |
Authorized return on equity (4) | 10.0-12.0% | 10.0% | 10.0-11.4% | 11.25% | 10.2% |
Authorized rate base % of equity (4) | 47.0% | 53.0% | 52.4% | 36.8% | 35.5% |
Estimated 2004 return on equity (4) (5) | 11.2% | 5.2% | 11.4% | 6.6% | 9.4% |
Rate base included in estimated 2004 return of equity(6) (7) (in millions) | $1,120 | $397 | $325 | $125 | $94 |
| Atlanta Gas Light | Elizabethtown Gas | Virginia Natural Gas | Florida City Gas | Chattanooga Gas |
Operations | | | | | |
Average end-use customers (in thousands) | 1,545 | 266 | 261 | 103 | 61 |
Daily capacity (1) | 2.5 | 0.4 | 0.4 | 0.1 | 0.2 |
Storage capacity (1) | 49.4 | 13.6 | 9.6 | - | 3.6 |
Annual distribution (1) | 232 | 59 | 36 | 10 | 16 |
2005 peak day demand (1) | 1.9 | 0.4 | 0.4 | 0.04 | 0.1 |
Peak storage capacity (1) | 6.2 | 0.1 | 0.8 | - | 1.2 |
Average monthly throughput (1) | 19.3 | 4.9 | 3.0 | 0.8 | 1.4 |
Miles of pipeline | 30,427 | 4,948 | 5,106 | 3,162 | 1,521 |
Rates | | | | | |
Last decision on change in rates | Jun. 2005 | Nov. 2002 | Oct. 1996 | Feb. 2004 | Oct. 2004 |
Authorized return on rate base | 8.53% | 7.95% | 9.24% | 7.36% | 7.43% |
Estimated 2005 return on rate base (2) (3) | 8.68% | 6.54% | 8.71% | 6.25% | 7.88% |
Authorized return on equity | 10.9% | 10.0% | 10.9% | 11.25% | 10.2% |
Estimated 2005 return on equity (2) (3) | 11.21% | 6.37% | 10.51% | 8.32% | 11.47% |
Authorized rate base % of equity (4) | 47.9% | 53.0% | 52.4% | 36.8% | 35.5% |
Rate base included in 2005 return on equity (in millions) (3) (4) | $1,181 | $433 | $321 | $118 | $96 |
(1) | Represents an average for 2004 except Elizabethtown Gas and Florida gas, which are December 2004 amounts. |
(2) | In millions of dekatherms. |
(3) | The authorized return on rate base for Florida Gas includes a credit for deferred taxes that is considered a rate base deduction in all other jurisdictions. |
(4) | The authorized returns on rate base and equity along with authorized rate base % of equity for Chattanooga Gas are currently under reconsideration by the Tennessee Regulatory Authority (Tennessee Authority). The estimated 2004 return on equity for Chattanooga Gas is calculated consistent with the Tennessee Authority order that is under reconsideration. |
(5)(2) | Estimate based on principles consistent with utility ratemaking in each jurisdiction. Returns are not consistent with GAAP returns. |
(6) (3) | Based uponEstimated based on 13-month average. |
(7)(4) | Rate base for Elizabethtown Gas is based uponon amounts filed in a 2002 rate case; however, no specific level of rate base was authorized due to settlement by stipulation with NJBPU.the New Jersey Board of Public Utilities. A 53% rate base of equity for Elizabethtown Gas was authorized in most recent rate case; however, 50% is used for rate of return calculation purposes based on estimated current regulatory capital structure. |
Each utility operates subject to regulations provided by the state regulatory agenciesagency in its service territories with respect to rates charged to our customers, maintenance of accounting records, and various other service and safety matters. Rates charged to our customers vary according to customer class (residential, commercial or industrial) and rate jurisdiction. Rates are set at levels that allow for the recovery of all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return on common equity. Rate base consists generally of the original cost of utility plant in service, working capital, inventories and certain other assets; less accumulated depreciation on utility plant in service, net deferred income tax liabilities and certain other deductions. Our utilities are authorized to use a purchased gas adjustment (PGA) mechanism that allows them to automatically adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure the utilities recover 100% of the costs incurred in purchasing gas for their customers. We continuously monitor the performance of our utilities to determine whether rates need to be further adjusted by making a rate case filing.
Increased Natural Gas Prices, Bad Debt and Conservation Increased prices of natural gas are being driven by increased demand that is exceeding the growth in available supply. The hurricanes in the Gulf Coast region during the late summer and early fall of 2005 impacted the availability of natural gas supply, causing a dramatic rise in natural gas prices. These higher prices have thus far been mitigated in part by significantly warmer-than-normal temperatures in the eastern United States during the first half of the heating season. We expect our customers will incur increases in their bills during the remainder of the current winter heating season.
An increase in the cost of gas due to higher natural gas commodity costs generally has no direct effect on our utility’s net operating margins and net income due to the PGA mechanisms at our utilities. However, net income may be reduced as a result of higher expenses that may be incurred for bad debt, as well as lower volumes of natural gas deliveries to customers due to customer conservation and thus lower natural gas consumption.
These risks of increased bad debt expense and decreased operating margins from conservation are minimized at our largest utility, Atlanta Gas Light, as a result of its straight-fixed-variable rate structure and because customers in Georgia buy gas from certificated marketers rather than from Atlanta Gas Light. Our credit exposure at Atlanta Gas Light is primarily related to the provision of services for the certificated marketers, but that exposure is mitigated because we obtain security support in an amount equal to a minimum of two times a marketer’s highest month’s estimated bill.
As part of our integration strategy, we have implemented measures at our New Jersey and Florida utilities to collect delinquent accounts; these measures are similar to our processes at Virginia Natural Gas and Chattanooga Gas. Across our utility system, bad debt levels are lower year-to-date than they have been in previous years, and we will continue to monitor and mitigate the impact of uncollectible expenses.
We are partnering with regulators and state agencies in each of our jurisdictions to educate customers about these issues, and particularly to ensure that those who qualify for Low Income Home Energy Assistance funds and similar programs receive that assistance.
Competition Our distribution operations businesses face competition based on our customers’customer preferences for natural gas compared to other energy products and the comparative prices of those products. Our principal competition relates to the electric utilities and oil and propane providers serving the residential and small commercial markets throughout our service areas and the potential displacement or replacement of natural gas appliances with electric appliances. The primary competitive factors are the price of energy and the desirability of natural gas heating versus alternative heating sources. Also, price volatility in the wholesale natural gas commodity market has resulted in increases in the cost of natural gas billed to customers.
Competition for space heating and general household and small commercial energy needs generally occurs at the initial installation phase when the customer/builder typically makes decisions as to which types of equipment to install and operate. The customer willinstall. Customers generally continue to use the chosen energy source for the life of the equipment. Our customers’Customer demand for natural gas and the level of business of natural gas assets could be affected by numerous factors, including
· | changes in the availability or price of natural gas and other forms of energy |
· | general economic conditions |
· | legislation and regulations |
· | the capability to convert from natural gas to alternative fuels |
In 2004, our distribution operation segment’s customers grew by approximately 2%. However, in some of our service areas primarily in Georgia, overallnet growth continues to be limitedslowed due to the number of customers who choose to leave our systems. systems because of higher natural gas prices and competition from alternative fuel sources, including incentives offered by the local electric utilities to switch to electric heat alternatives.
We expect our customer growth to improve in the future through our efforts in new business and retention. These efforts include working to add residential customers with three or more appliances, multifamily complexes and high-value commercial customers that use natural gas for purposes other than space heating. In addition, we partner with numerous entities to market the benefits of gas appliances and to identify potential retention options early in the process for those customers who might consider leaving our franchise by converting to alternative fuels.
Our distribution operation utilities include:
Atlanta Gas Light is aThis natural gas local distribution utility withoperates distribution systems and related facilities throughout Georgia. Atlanta Gas Light has approximately 6 Bcf of LNG storage capacity in three LNG plants to supplement the supply of natural gas during peak usage periods. Atlanta Gas Light is regulated by the Georgia Public Service Commission (Georgia Commission).
Prior to Georgia’s 1997 Natural Gas Competition and Deregulation Act (Deregulation Act), whichderegulatedwhich deregulated Georgia’s natural gas market, Atlanta Gas Light was the supplier and seller of natural gas to its customers. TodayMarketers—Today, Marketers—that is, marketers who are certificated by the Georgia Commission to sell retail natural gas in Georgia at rates and on terms approved by the Georgia Commission — sell natural gas to the end useend-use customers in Georgia and arehandlinghandle customer billing functions. Atlanta Gas Light's role includes
· | Distributingdistributing natural gas for the Marketers |
· | Constructing,constructing, operating and maintaining the gas system infrastructure, including responding to customer service calls and leaks |
· | Performing meter reading meters and maintaining underlying customer premise information for the Marketers |
Since 1998, a number of federal and state proceedings have addressed the role of Atlanta Gas Light in administering and assigning interstate assets to Marketers pursuant to the provisions of the Deregulation Act. In this role, Atlanta Gas Light is authorized to offer additional sales services pursuant to Georgia Commission-approved tariffs and to acquire and continue managing the interstate transportation and storage contracts that underlie the sales services provided to Marketers on its distribution system under Georgia Commission-approved tariffs.
Performance-Based RatesRate Settlement Agreement In June 2005, the Georgia Commission approved a Settlement Agreement with Atlanta Gas Light that froze Atlanta Gas Light’s base rates billed to customers as of April 30, 2005 through April 30, 2010. The Settlement Agreement also requires Atlanta Gas Light to recognize reduced revenues are established pursuantof $25 million over the same period, to a three-year performance-based rate (PBR) plan that becamespend $2 million annually on energy conservation programs and to spend an additional $2 million for social responsibility and education programs. The Settlement Agreement was effective for rates as of May 1, 2002,2005. Atlanta Gas Light offset the impact of the Settlement Agreement on its 2005 EBIT by identifying and implementing reductions in its operating costs and by realizing increased operating margins from net customer growth in 2005.
During the term of the Settlement Agreement, Atlanta Gas Light will not seek a rate increase, nor will the Georgia Commission initiate a new rate proceeding. Atlanta Gas Light will file information equivalent to information that would be required for a general rate case on November 1, 2009, with new rates to be effective on May 1, 2010.
The Settlement Agreement establishes an authorized return on equity of 11%10.9% for Atlanta Gas Light, resulting in an overall rate of return of 8.53%. The PBR plan also establishes an earnings band based on aPrior to the settlement, Atlanta Gas Light’s authorized return on equity was 11% and its overall return was set at 9.16%.
The Settlement Agreement extends Atlanta Gas Light’s pipeline replacement program (PRP) by five years to require that all replacements be completed by December 2013 and sets the per-customer PRP rate to be billed at $1.29 per customer per month from May 2005 through September 2008 and at $1.95 from October 2008 through December 2013. Atlanta Gas Light will apply the five-year total reduction in recognized base rate revenues of 10%$25 million to 12%, subjectthe amount of costs incurred to certain adjustments, with three-quartersreplace pipe, reducing the amount recovered from customers under the PRP. The timing of any earnings above a 12% returnreplacements was subsequently specified in an amendment to the PRP stipulation.
This amendment, which was approved by the Georgia Commission on equity shared with Georgia customersDecember 20, 2005, requires Atlanta Gas Light to replace the remaining 152 miles of cast iron pipe and one-quarter retained70% of the remaining 687 miles of bare steel pipe by December 2010. The remaining 30% of bare steel pipe is required to be replaced by December 2013. The amendment requires an evaluation by Atlanta Gas Light.Light and the Georgia Commission staff of 22 miles of 24-inch pipe in Atlanta by December 2010 to determine if such pipe requires replacement. If replacement of this pipe is required, the pipe must be replaced by December 2013. The additional cost to replace this pipe is projected to be approximately $37 million.
The Georgia Commission staff has reviewedSettlement Agreement includes a provision that allows for a true-up of any over- or under-recovery of PRP revenues that may result from a difference between PRP charges collected through fixed rates and actual PRP revenues recognized through the operationremainder of the plan and Atlanta Gas Light’s revenue requirement to determine whether base rates should be reset upon the expiration of the existing plan in April 2005. The Georgia Commission will then determine whether the plan should be discontinued, extended or otherwise modified.program.
In connection with this review, Atlanta Gas Light filed a general rate case request for a $26 million rate increase withwill be allowed under the Georgia Commission. The request would continue the PBR plan and include a return on equity band of 10.2%Settlement Agreement to 12.2%. The Georgia Commission is scheduled to issue its decision on April 28, 2005, with any rate adjustments to be effective May 1, 2005. Any rate adjustments would be comprised of changes from May 1, 2002 and projectedrecover through April 30, 2005 related to depreciation expense, capital expenditures and various other operating expenses such as pipeline integrity costs mandated by federal regulations and changes in the property tax valuation method.
Pipeline Replacement Program (PRP)Pursuant to the Georgia Commission’s revised procedural and scheduling order, Atlanta Gas Light’s rate case filing included testimony on whether the PRP should be$4 million of the $32 million in capital costs associated with its March 2005 purchase of 250 miles of pipeline in central Georgia from Southern Natural Gas Company (SNG), a subsidiary of El Paso Corporation. We expect the acquired pipeline to improve deliverable capacity and reliability of the storage capacity from our LNG facility in Macon to our markets in Atlanta. The remaining capital costs are included in Atlanta Gas Light’s rate base rates or whether the rider currently used for recovery of PRP expenses should be otherwise modified or discontinued. Atlanta Gas Light’s testimony supported continuing the current PRP rider agreement. Including the PRP capital costs inand collected through base rates before the end of the program would result in a regulatory delay in recovery of our total unrecovered PRP regulatory asset of $361 million. This delay could require more frequent rate requests to fund the annual cost of PRP capital expenditures and resulting depreciation. In addition, the future loss of a recovery mechanism could impair the PRP regulatory asset. Any resulting impairment would reduce Atlanta Gas Light’s earnings.rates.
Straight-Fixed-Variable Rates Atlanta Gas Light’s revenue is recognized under a straight-fixed-variable rate design whereby Atlanta Gas Light charges rates to its customers based primarily on monthly fixed charges. This mechanism minimizes the seasonality of revenues since the fixed charge is not volumetric and the monthly charges are not set to be directly weather dependent. Weather indirectly influences the number of customers that have active accounts during the heating season, and this has a seasonal impact on Atlanta Gas Light’s revenues since generally more customers will beare connected in periods of colder weather than in periods of warmer weather.
Interstate Pipeline AcquisitionElizabethtown Gas Atlanta Gas Light has executed an agreement with Southern Natural Gas (Southern Natural), a subsidiary of El Paso Corporation, to acquire a portion of Southern Natural’s interstate pipeline that runs from Macon, Georgia to the vicinity of Atlanta, Georgia. The transaction is valued at approximately $32 million. As part of the agreement, Atlanta Gas Light will extend certain existing Southern Natural transportation and storage contracts to ensure reliable delivery of natural gas into Georgia in return for the right to expand Atlanta Gas Light’s system off of the purchased facilities.On January 19, 2005, the Federal Energy Regulatory Commission (FERC) approved the abandonment of Southern Natural’s facilities to Atlanta Gas Light, thereby allowing the transaction to proceed to closing.We expect the Southern Natural transaction to close by April 30, 2005, subject to securing the remaining regulatory approvals.
Capacity Supply PlanIn May 2004, Atlanta Gas Light and 8 of the 10 Marketers entered into a settlement that resolved matters related to a capacity supply plan that was required to be filed by Atlanta Gas Light in July 2004. As a result of the settlement, the parties filed a three year capacity supply plan for the Georgia market with the Georgia Commission. In October 2004, we received reconsideration and approval by the Georgia Commission of the capacity supply plan, which includes, among other things:
· | calculation of the design (peak) day requirements for the next three years |
· | purchase by Atlanta Gas Light of the above-described Southern Natural facilities and the recovery of those costs through the pending rate case |
· | construction of a pipeline from the Macon LNG facility to the purchased Southern Natural facilities |
· | extension of the Sequent peaking contract to March 2005 |
· | approval of Sequent’s current asset management contract for retained assets through March 1, 2006 |
· | other tariff provisions |
Elizabethtown Gasis aThis natural gas local distribution utility that we acquired with our NUI acquisition, withoperates distribution systems and related facilities in central and northwestern New Jersey. Most Elizabethtown Gas has an LNG storage and vaporization facility to supplement the supply of natural gas during peak usage periods. The facility has a daily capacity of 24,200 million cubic feet (Mcf) and storage capacity of 131,000 Mcf. Most of Elizabethtown Gas’ customers are located in densely populated central New Jersey, where increases in the number of customers primarily result from conversions to gas heating from alternative forms of heating. In the northwestnorthwestern region of the state, customer additions are driven primarily by new construction. Elizabethtown Gas is regulated by the NJBPU.
On November 9, 2004, the NJBPU approved our acquisitionNew Jersey Board of NUI and our agreement with the NJBPU’s staff and certain third parties related to post-closing operations. This agreement provided, among other things, for
· | a freeze of Elizabethtown Gas’ base rates for five years, with earnings over an 11% return of equity to be shared with ratepayers in the fourth and fifth years |
· | Sequent to serve as asset manager for Elizabethtown Gas, beginning April 1, 2005, for a three year term for an annual fixed fee payment by Sequent to Elizabethtown Gas of $4 million |
· | new performance standards with respect to customer satisfaction, safety and reliability, with negotiations with the various interested parties of the applicable standards beginning in February 2005 |
· | acceleration of the payment of the outstanding balances due on Elizabethtown Gas’ $28 million refund to its ratepayers and a related $2 million penalty to the NJBPU |
· | a commitment to make $9 million available for the purpose of enhancing severance packages for certain employees located in New Jersey |
Public Utilities (NJBPU).
Weather Normalization The Elizabethtown Gas’Gas tariff contains a weather normalization clause that is designed to help stabilize Elizabethtown Gas’Gas results by increasing base rate amounts charged to customers when weather has beenis warmer than normal and decreasing amounts charged when weather is colder than normal. The weather normalization clause was renewed in October 2004 and is based on the 20 yeara 20-year average of weather conditions.
Pipeline Replacement In April 2005, Elizabethtown Gas presented the NJBPU with a proposal to accelerate the replacement of approximately 88 miles of 8” to 12” diameter elevated-pressure cast iron pipe. Under the proposal, approximately $42 million in estimated capital costs incurred over a three-year period would be recovered through a pipeline replacement rider similar to the program in effect at Atlanta Gas Light. If the program as proposed is approved, cost recovery would occur on a one-year lag basis, with collections starting on October 1, 2006 and extending through December 31, 2009, after which time the program would be rolled into base rates. On December 7, 2005, Elizabethtown Gas filed testimony in support of its proposal. The proposal and related testimony will be considered in the following timeframe:
· | The New Jersey Rate Payer Advocate will file testimony on February 28, 2006. |
· | Elizabethtown Gas will file rebuttal testimony on March 17, 2006. |
· | Public hearings will convene on March 30, 2006. |
Virginia Natural Gas is aThis natural gas local distribution utility withoperates distribution systems and related facilities in southeastern Virginia. Virginia Natural Gas owns and operates approximately 155 miles of a separate high-pressure pipeline that provides delivery of gas to customers under firm transportation agreements within the state of Virginia. Virginia Natural Gas also has approximately five million gallons of propane storage capacity in its two propane facilities to supplement the supply of natural gas during peak usage periods. Virginia Natural Gas is regulated by the Virginia State Corporation Commission (Virginia Commission).
Performance-based Rates In March 2005, the Virginia Commission staff issued a report alleging that Virginia Natural Gas rates were excessive and that its rates should be adjusted to produce a $15 million reduction in revenue. The staff also filed a motion requesting that Virginia Natural Gas rates be declared interim and subject to refund.
In April 2005, Virginia Natural Gas responded to the staff’s report and motion, contesting the allegations in the report and objecting to the motion filed by the staff. On April 29, 2005, the Virginia Commission ordered the staff’s motion to be held in abeyance and directed Virginia Natural Gas to file a rate case by July 2005.
In July 2005, Virginia Natural Gas filed a performance-based rate (PBR) plan with the Virginia Commission and included the schedules required for a general rate case in support of its proposal. Under the PBR plan, Virginia Natural Gas proposes to freeze base rates at their 1996 levels for 5 additional years. This would provide Virginia Natural Gas customers an additional 5 years of rate stability, for a total of 14 years without a rate increase. If the Virginia Commission approves the proposal, Virginia Natural Gas will become the first Virginia natural gas utility to operate under a 1996 state law that authorized PBR plans for natural gas utilities. Consistent with state law, Virginia Natural Gas has proposed two exceptions that allow for adjustments to frozen base rates. Virginia Natural Gas could request a rate adjustment in connection with (1) any changes in taxation of gas utility revenues by the Commonwealth and (2) any financial distress of Virginia Natural Gas beyond its control.
Based on the Virginia Commission’s scheduling order issued on July 14, 2005, current rates will stay in effect until the PBR is decided; consequently, there was no impact on Virginia Natural Gas’ 2005 revenues. Based on this scheduling order and the Virginia Commission’s approval of requests for extension made by the Virginia Commission staff in December 2005, the PBR proposal to freeze rates for another five years will be considered on the following timeframe:
· | Virginia Commission staff filed its testimony and exhibits on January 24, 2006 and requested a $10 million rate decrease |
· | Virginia Natural Gas filed rebuttal testimony and exhibits on February 7, 2006 |
· | public evidentiary hearings will convene on February 21, 2006 |
The Virginia state law authorizing PBR plans also allows a utility to withdraw or modify its PBR application at any time prior to a final ruling by the Virginia Commission. Virginia Natural Gas is currently evaluating the withdrawal or modification of its PBR plan in light of current market conditions including rising interest rates, tight natural gas supplies, rising costs and material constraints caused by lower oil supplies. If the PBR plan is not approved or is modified by the Virginia Commission in a manner that Virginia Natural Gas chooses not to accept, the Virginia Commission can take action in the general rate case filing. Virginia Natural Gas’ proposal would not affect its Virginia Commission-authorized purchased gas cost, which passes gas commodity costs through to consumers.
On January 12, 2006, Virginia Natural Gas filed with the Virginia Commission a proposed motion for approval of Virginia Natural Gas’ PBR plan. If the proposed motion is approved, the PBR plan would be implemented as filed and Virginia Natural Gas would commit to certain actions, primarily to construct a pipeline that would connect Virginia Natural Gas’ northern system to its southern system. Participants in and supporters of the proposed motion include Virginia Natural Gas; AGL Resources; the Virginia Office of the Attorney General - Division of Consumer Counsel; and the Virginia Industrial Gas Users’ Association. On February 3, 2006, the Virginia Commission’s hearing examiner recommended that the Virginia Commission approve the PBR plan. Accordingly, the rate case schedule remains as previously stipulated.
Weather Normalization Adjustment (WNA) OnIn September 27, 2002, the Virginia Commission approved a WNA program as a two-year experiment involving the use of special rates. The WNA program’s purpose is to reduce the effect of weather on customer bills by reducing bills when winter weather is colder than normal and increasing bills when winter weather is warmer than normal. In September 2004, Virginia Natural Gas received approval from the Virginia Commission to extend Virginia Natural Gas’the WNA program for an additional two years with certain modifications to the existing program. The significant modifications include the removal of the commercial class of customers from the WNA program and the use of a rolling 30 year30-year average to calculate the weather factor that is updated annually.
Propane Air FacilityIn June 2004, the Virginia Commission issued its final order authorizing the recovery by Virginia Natural Gas of all charges for the services of a new propane air facility through Virginia Natural Gas’ gas cost recovery mechanism. The approval is for an initial 10-year term, with the possibility of renewal thereafter for terms of two years subject to Virginia Commission approval. The facility will provide Virginia Natural Gas with 28,800 dekatherms (dth) of propane air per day on a 10-day-per-year basis to more reliably serve its peaking needs.
Florida City Gas Company (Florida Gas) is aThis natural gas local distribution utility acquired with our NUI acquisition. Florida Gas hasoperates distribution systems and related facilities in central and southern Florida. Florida City Gas customers purchase gas primarily for heating water, drying clothes and cooking. Some customers, mainly in central Florida, also purchase gas to provide space heating during the winter season. Florida City Gas is regulated by the Florida Public Service Commission (Florida Commission).Commission.
In January 2004, Florida Gas received approval from the Florida Commission to increase its base rates by approximately $7 million, effective February 23, 2004. The increase represents a portion of Florida Gas’ request for a rate increase to cover the costs of investments in its customer service assets, system maintenance and growth and increases in its operating expenses.
Chattanooga Gas is aThis natural gas local distribution utility withoperates distribution systems and related facilities in the Chattanooga and Cleveland areas of southeastern Tennessee. Chattanooga Gas has approximately 1.2 Bcf of LNG storage capacity in its LNG plant. Included in theGas’ base rates charged by Chattanooga Gas isinclude a weather normalization clause that allows for revenue to be recognized based on a factor derived from average temperatures over a 30-year period, which offsets the impact of unusually cold or warm weather on its operating income. Chattanooga Gas is regulated by the Tennessee Regulatory Authority (Tennessee Authority).
Base Rate Increase In January 2004, Chattanooga Gas filed a rate plan request withJune 2005, the Tennessee Authority for a total rate increase of approximately $5 million annually. The rate plan was filed to cover Chattanooga Gas’ rising cost of providing natural gas toupheld its customers. In Mayprevious October 2004 the Tennessee Authority suspended the increase until July 28, 2004 and subsequently deferred the decision to August 30, 2004. After its initial filing,order denying Chattanooga Gas reduced its rate plan increase to approximatelya $4 million primarily as a result of the Februaryrate increase. The October 2004 Tennessee Authority ruling discussed in “Purchased Gas Adjustment” below. Chattanooga Gas received a written order from the Tennessee Authority on October 20, 2004 that authorized new rates based on a 7.43% return on rate base forapproved an increase in revenues of approximately $1 million annually. In November 2004, the Tennessee Authority granted Chattanooga Gas’ motion for reconsideration of the rate increase and in December 2004 heard oral argumentsbased on the issues of the appropriate capital structure and thea 10.2% return on equity to be used in setting Chattanooga Gas’ rates. The Tennessee Authority has not yet issued its ruling after reconsideration.
Purchased Gas AdjustmentIn March 2003, Chattanooga Gas filedand a joint petition with other Tennessee distribution companies requesting the Tennessee Authority issue a declaratory ruling that the portioncapital structure of uncollectible accounts directly related to the cost of its natural gas is recoverable through a Purchased Gas Adjustment (PGA) mechanism. The PGA mechanism allows the local distribution companies to automatically adjust their rates to reflect changes in the wholesale cost of natural gas and to insure the utilities recover 100% of the cost incurred in purchasing gas for their customers. On February 9, 2004, the Tennessee Authority ruled that the gas portion of accounts written-off as uncollectible after March 10, 2004 could be recovered through the PGA.35.5% common equity.
Elkton Gas Company (Elkton Gas)is aThis natural gas local distribution utility that we acquired with our NUI acquisition. Elkton Gas hasoperates distribution systems and related facilities serving approximately 5,9005,800 customers in Cecil County, Maryland. Elkton Gas customers are approximately 93%7% commercial and industrial and 7%93% residential. Elkton Gas’ current rates were authorized in June 1992 by theMaryland Public Service Commission.
Virginia Gas Distribution Companyis a natural gas local distribution utilitythat we acquired with our NUI acquisition. Virginia Gas Distribution Company services approximately 300 customers in franchised territories in the southwestern Virginia counties of Buchanan and Russell. Approximately 76% of its natural gas sales are to residential customers with its remaining sales to commercial and industrial customers. Virginia Gas Distribution Company is regulated by the VirginiaMaryland Public Service Commission.
Results of Operations The following table presents results of operations for our distribution operations segment for the years ended December 31, 2005, 2004 2003 and 2002 are shown in the following table:2003.
In millions | | 2004 | | 2003 | | 2002 | | 2004 vs. 2003 | | 2003 vs. 2002 | | | 2005 | | 2004 | | 2003 | |
Operating revenues | | $ | 1,111 | | $ | 936 | | $ | 852 | | $ | 175 | | $ | 84 | | | $ | 1,753 | | $ | 1,111 | | $ | 936 | |
Cost of gas | | | 470 | | | 337 | | | 267 | | | 133 | | | 70 | | | | 939 | | | 471 | | | 337 | |
Operating margin | | | 641 | | | 599 | | | 585 | | | 42 | | | 14 | | | | 814 | | | 640 | | | 599 | |
Operation and maintenance expenses | | | 286 | | 261 | | 255 | | 25 | | 6 | | |
Operation and maintenance | | | | 372 | | | 286 | | | 261 | |
Depreciation and amortization | | | 85 | | 81 | | 82 | | 4 | | (1 | ) | | | 114 | | | 85 | | | 81 | |
Taxes other than income | | | 24 | | | 24 | | | 25 | | | - | | | (1 | ) | |
Taxes other than income taxes | | | | 32 | | | 23 | | | 24 | |
Total operating expenses | | | 395 | | | 366 | | | 362 | | | 29 | | | 4 | | | | 518 | | | 394 | | | 366 | |
Gain on sale of Caroline Street campus | | | - | | 21 | | - | | (21 | ) | | 21 | | | | - | | | - | | | 21 | |
Operating income | | | 246 | | | 254 | | | 223 | | | (8 | ) | | 31 | | | | 296 | | | 246 | | | 254 | |
Donation to private foundation | | | - | | (8 | ) | | - | | 8 | | (8 | ) | | | - | | | - | | | (8 | ) |
Other income | | | 1 | | 1 | | 2 | | - | | (1 | ) | | | 3 | | | 1 | | | 1 | |
Total other (loss) income | | | 1 | | | (7 | ) | | 2 | | | 8 | | | (9 | ) | |
EBIT | | $ | 247 | | $ | 247 | | $ | 225 | | $ | - | | $ | 22 | | | $ | 299 | | $ | 247 | | $ | 247 | |
| | | | | | | | | | | | | | | | | | | | | | |
Metrics | | | | | | | | | | | | | | | | | |
Average end-use customers(in thousands) (1) | | | 1,880 | | 1,838 | | 1,824 | | 2 | % | | 1 | % | |
Metrics (1) | | | | | | | | | | | |
Average end-use customers (in thousands) | | | | 2,242 | | | 1,880 | | | 1,838 | |
Operation and maintenance expenses per customer | | $ | 152 | | $ | 142 | | $ | 140 | | 7 | | 1 | | | $ | 166 | | $ | 152 | | $ | 142 | |
EBIT per customer(2) | | $ | 131 | | $ | 127 | | $ | 123 | | | 3 | | | 3 | | |
Throughput(in millions of dekatherms) (1) | | | | | | | | | | | | | |
EBIT per customer (2) | | | $ | 133 | | $ | 131 | | $ | 127 | |
Throughput (in millions of Dth) | | | | | | | | | | | |
Firm | | | 194 | | 190 | | 182 | | 2 | % | | 4 | % | | | 234 | | | 194 | | | 190 | |
Interruptible | | | 105 | | | 109 | | | 124 | | | 4 | | | (12 | ) | | | 120 | | | 105 | | | 109 | |
Total | | | 299 | | | 299 | | | 306 | | | - | | | (2 | ) | | | 354 | | | 299 | | | 299 | |
Heating degree days(3): | | | | | | | | | | | | | |
Florida(1) | | | 239 | | - | | - | | n/a | % | | n/a | % | |
Heating degree days (3): | | | | | | | | | | | |
Florida | | | | 698 | | | 239 | | | - | |
Georgia | | | 2,589 | | 2,654 | | 2,812 | | (2 | ) | | (6 | ) | | | 2,726 | | | 2,589 | | | 2,654 | |
Maryland (1) | | | 860 | | - | | - | | n/a | | n/a | | |
New Jersey (1) | | | 873 | | - | | - | | n/a | | n/a | | |
Maryland | | | | 5,004 | | | 860 | | | - | |
New Jersey | | | | 5,017 | | | 873 | | | - | |
Tennessee | | | 3,010 | | 3,168 | | 3,052 | | (5 | ) | | 4 | | | | 3,115 | | | 3,010 | | | 3,168 | |
Virginia | | | 3,214 | | | 3,264 | | | 3,030 | | | (2 | ) | | 8 | | | | 3,465 | | | 3,214 | | | 3,264 | |
(1) | Represents information2004 metrics include only December for December 2004 for the utilities acquired from NUI.Florida City Gas, Elizabethtown Gas and Elkton Gas. |
(2) | Excludes the gain on the sale of our Caroline Street campus in 2003. |
(3) | We measure effects of weather on our businesses using “degree days.” The measure of degree days for a given day is the difference between average daily actual temperature and a baseline temperature of 65 degrees Fahrenheit. Heating degree days result when the average daily actual temperature is less than the 65-degree baseline. Generally, increased heating degree days result in greater demand for gas on our distribution systems. |
2005 compared to 2004 EBIT increased $52 million or 21% reflecting an increase in operating margin of $174 million, partially offset by increased operating expenses of $124 million. The businesses acquired from NUI on November 30, 2004 contributed approximately $50 million of EBIT in 2005 compared to $7 million in 2004. This was due to the full-year inclusion of the NUI results in 2005 compared to one month in 2004.
The $174 million or 27% increase in operating margin was primarily due to the addition of NUI’s operations, which contributed $167 million. The remainder was primarily due to $8 million of higher operating margin at Atlanta Gas Light. The increase at Atlanta Gas Light resulted primarily from higher PRP revenues of $6 million and higher revenue of $3 million from additional carrying charges for gas stored for Marketers primarily due to higher gas prices. Atlanta Gas Light also had approximately $3 million of increased operating margin from net customer growth, which offset a $3 million decrease in operating revenues that resulted from the June 2005 Settlement Agreement with the Georgia Commission. Operating margin at Virginia Natural Gas and Chattanooga Gas remained relatively flat compared to last year.
The $124 million or 31% increase in operating expenses primarily reflected the addition of NUI’s operations which increased operating expenses by $125 million.
2004 compared to 2003 There was no change in the distribution operations segment’soperations’ EBIT from 2003; however, the 2003 results included a pretax gain of $21 million on the sale of our Caroline Street campus, offset by an $8 million donation to AGL Resources Private Foundation, Inc. Exclusive of the gain and donation, EBIT in 2004 increased $13 million or 5% due to increased operating margin, that was partially offset by increased operating expenses.
The $41 million or 7% increase in operating margin of $42 million or 7% from 2003 includesincluded $17 million in combined increases at Atlanta Gas Light and Virginia Natural Gas. The increase in Atlanta Gas Light’s operating margin was primarily fromdue to higher PRP revenue as a result of continued PRP capital spending, customer growth, higher customer usage and additional carrying charges from gas stored for Marketers due to a higher average cost of gas. The increase in operating margin at Virginia Natural Gas’ operating marginGas was primarily fromdue to customer growth. The acquisition of NUI added $25$24 million of operating margin primarily from NUI’s December operations of Elizabethtown Gas and Florida City Gas.
Operating expenses increased $29$28 million or 8% from 2003. This was due primarily to the addition of NUI operations for the month of December of $19$17 million. The remaining increase of $10$11 million was due to increases in the cost of outside services related to increased information technology services as a result of our ongoing implementation of a work management system,system; increased legal services due to increased regulatory activityactivity; and increased accounting services related to our implementation of SOX 404. Employee benefit and compensation expenses also increased primarily as a result of higher health care insurance costs and increased long termlong-term compensation expenses. In addition, depreciation expenses increased primarily fromdue to new depreciation rates implemented forat Virginia Natural Gas and increased assets at each utility. These increases were partially offset by a reduction in bad debt expenses, which wasexpense, primarily due to a Tennessee Authority ruling that allowsallowed for recovery of the gas portion of accounts written off as uncollectible at Chattanooga Gas and increased collection efforts at both Chattanooga Gas and Virginia Natural Gas.
Our retail energy operations segment consists of SouthStar, a joint venture owned 70% by our subsidiary, Georgia Natural Gas Company, and 30% by Piedmont. SouthStar markets natural gas and related services to 2002retail customers on an unregulated basis, principally in Georgia.
The SouthStar executive committee, which acts as the governing board, comprises six members, with three representatives from us and three from Piedmont. Under the joint venture agreement, all significant management decisions require the unanimous approval of the SouthStar executive committee; accordingly, our 70% financial interest is considered to be noncontrolling. Although our ownership interest in the SouthStar partnership is 70%, SouthStar's earnings are allocated 75% to us and 25% to Piedmont, under an amended and restated joint venture agreement executed in March 2004.
Beginning January 1, 2004, we consolidated the accounts of SouthStar and eliminated all intercompany balances in the consolidation. We recorded the portion of SouthStar’s earnings that are attributable to our joint venture partner, Piedmont, as a minority interest in our statements of consolidated income, and we recorded Piedmont’s portion of SouthStar’s capital as a minority interest in our consolidated balance sheets.
Competition SouthStar competes with other energy marketers, including Marketers in Georgia, to provide natural gas and related services to customers in Georgia and the Southeast. Based on its market share, SouthStar is the largest Marketer of natural gas in Georgia, with average customers in 2003 through 2005 in excess of 530,000.
In addition, similar to distribution operations, SouthStar faces competition based on customer preferences for natural gas compared to other energy products and the comparative prices of those products. SouthStar’s principal competition relates to electric utilities and the potential displacement or replacement of natural gas appliances with electric appliances. This competition with other energy products has been exacerbated by price volatility in the wholesale natural gas commodity market which has resulted in significant increases in the cost of natural gas billed to SouthStar’s customers.
Operating MarginSouthStar generates its operating margin primarily in two ways. The first is through the sale of natural gas to retail customers in the residential, commercial and industrial sectors, primarily in Georgia. SouthStar captures a spread between wholesale and retail natural gas prices and also realizes a portion of its operating margin through the collection of a monthly service fee and customer late payment fees. SouthStar’s operating margins are impacted by weather seasonality as well as by customer growth, and SouthStar’s related market share in Georgia, which traditionally ranges from 35% to 38%. SouthStar employs a strategy to attract and retain a higher-quality customer base through the application of stringent credit requirements. This strategy results not only in higher operating margin contributions, as customers tend to utilize higher volumes of natural gas, but also higher EBIT increased $22through a reduction in bad debt expenses.
The second way in which SouthStar generates margin is through the optimization of storage and transportation assets. Through its hedging transactions and derivative instruments aimed at managing exposures arising from changing commodity prices, SouthStar utilizes natural gas storage transactions to profit from natural gas pricing differences that occur over time. SouthStar does not hold speculative derivative instruments.
SouthStar is actively seeking to improve its margin-generating capabilities by evaluating a number of growth opportunities, including incremental customer growth in Georgia and expansion of its retail model to other markets, through either organic growth or acquisition of an existing customer portfolio.
Impact of High Gas Prices SouthStar’s operating margin and EBIT from the sales of natural gas to retail customers could be affected by conservation and bad debt trends as a result of higher natural gas prices in the 2005 - 2006 winter heating season. SouthStar’s bad debt expense as a percentage of operating revenues of approximately 1% for 2005 remained consistent with 2004. We believe SouthStar’s higher-quality customer base and the unregulated pricing structure in Georgia mitigates our exposure to higher bad debt expenses.
Results of OperationsThe following table presents results of operations for retail energy operations for the years ended December 31, 2005 and 2004, and pro-forma results as if SouthStar’s accounts were consolidated with our subsidiaries’ accounts for the year ended December 31, 2003. The unaudited pro-forma results are presented for comparative purposes as a result of our consolidation of SouthStar in 2004. This pro-forma basis is a non-GAAP presentation; however, we believe it is useful to readers of our financial statements since it presents the revenues and expenses for 2003 on the same basis as 2005 and 2004. In 2003, we recognized our portion of SouthStar’s earnings of $46 million as equity earnings.
In millions | | 2005 | | 2004 | | Pro-forma2003 | |
Operating revenues | | $ | 996 | | $ | 827 | | $ | 743 | |
Cost of gas | | | 850 | | | 695 | | | 619 | |
Operating margin | | | 146 | | | 132 | | | 124 | |
Operation and maintenance | | | 58 | | | 60 | | | 60 | |
Depreciation and amortization | | | 2 | | | 2 | | | 1 | |
Taxes other than income | | | 1 | | | - | | | - | |
Total operating expenses | | | 61 | | | 62 | | | 61 | |
Operating income | | | 85 | | | 70 | | | 63 | |
Minority interest | | | (22 | ) | | (18 | ) | | (17 | ) |
EBIT | | $ | 63 | | $ | 52 | | $ | 46 | |
| | | | | | | | | | |
Metrics | | | | | | | | | | |
Average customers (in thousands) | | | 531 | | | 533 | | | 558 | |
Market share in Georgia | | | 35 | % | | 36 | % | | 38 | % |
Natural gas volumes (billion cubic feet) | | | 44 | | | 45 | | | 49 | |
2005 compared to 2004 The $11 million or 10%21% increase in EBIT for 2003 asthe year ended December 31, 2005 was driven by a $14 million increase in operating margin and a $1 million decrease in total operating expenses, offset by a $4 million increase in minority interest due to higher earnings.
The $14 million or 11% increase in operating margin was primarily the result of higher commodity margins and positive margin captured with SouthStar’s storage assets, offset by lower use per customer and lower late payment fees relative to last year.
There was a slight decrease in operating expenses in 2005 compared to 2002,2004. The decrease was due to lower bad debt expense resulting from ongoing collection process improvements.
Minority interest increased $4 million or 22% as a direct result of increased operating income in 2005 compared to 2004.
2004 compared to 2003 The increase in EBIT of $6 million or 13% for the year ended December 31, 2004 was primarily the result of higher commodity margins and decreased bad debt expense during the year.
Operating margin for the year increased $8 million or 6%, primarily as a result of the gain, net of donation, of $13 million on the sale of our Caroline Street campus described above. Excluding the gain and donation, EBIT increaseda $9 million or 4%increase due primarily to a lower commodity cost structure resulting from increased operating margin,continued refinement of SouthStar’s hedging strategies and a $3 million increase due to a full year of higher customer service charges from third-party providers. These increases were partially offset by increased operating expenses.
Operating margin increased $14a decrease of $2 million or 2% from 2002. This wasrelated to a one-time sale of stored gas in 2003 and a $2 million decrease in late payment fees due primarily to an increased number of customers and a higher usage per degree day, of which Virginia Natural Gas contributed approximately $12 million. Atlanta Gas Light’s PRP rider revenues increased $2 million, resulting from recovery of prior-year program expenses, and Atlanta Gas Light’s carrying costs charged to Marketers for gas stored underground contributed approximately $1 million due to higher storage volumes. Offsetting these increases was a reduction in Atlanta Gas Light’s rates as compared to prior year of $3 million for the first four months of 2003 due to the PBR settlement agreement with the Georgia Commission effective May 1, 2002. Chattanooga Gas’ operating margin for 2003 was not materially different from 2002.improved customer base.
Operating expenses increased $4by $1 million or 1% from 20022% primarily due primarily to a $2$5 million increase in corporate allocated costs related to anSOX 404 implementation and corporate overhead allocations, partially offset by lower bad debt expense resulting from collection process improvements and increased quality of customer base. There was also a $1 million increase in corporate building lease costs and higher general business insurance premiums. Bad debt expenses increased $2 million, primarilyminority interest as a result of colder-than-normal weather and higher natural gas prices. Additional increasesSouthStar earnings in operating expenses were attributed2004 compared to a $1 million Virginia Natural Gas regulatory asset write-off in 2003. These increases in operating expenses were partially offset by a $1 million decrease in depreciation expenses due to lower depreciation rates at Atlanta Gas Light for the first four months of 2003 as a result of the PBR settlement agreement with the Georgia Commission.
Wholesale services consists of Sequent, our subsidiary involved in asset optimization,management, transportation, and storage, producer and peaking services and wholesale marketing. Our asset optimizationmanagement business focuses on capturing economic value from idle or underutilized natural gas assets, which are typically amassed by companies via investments in or contractual rights to natural gas transportation and storage assets. Margin is typically created in this business by participating in transactions that balance the needs of varying markets and time horizons.
Sequent provides its customers in the eastern and mid-continental United States with natural gas from the major producing regions and market hubs primarily in the Eastern and Mid-Continental United States.country. Sequent also purchases transportation and storage capacity to meet its delivery requirements and customer obligations in the marketplace. Sequent’s customers benefit from its logistics expertise and ability to deliver natural gas at prices that are advantageous relative to the other alternatives available to its end-use customers.
Asset management transactionsManagement Transactions Our asset management customers include Atlanta Gas Light, Chattanooga Gas and Virginia Natural Gas,our own utilities, nonaffiliated utilities, municipal customersutilities and large industrial customers. These customers must independently contract for transportation and storage services to meet their demands, and they typically contract for these services on a 365-day basis even though they may only need a portion of these services to meet their peak demands for a much shorter period. We enterdemands. Sequent enters into agreements with these customers, either through contract assignment or agency arrangement, whereby we useit uses their rights to transportation and storage services during periods when they do not need them. We captureSequent captures margin by optimizing the purchase, transportation, storage and sale of natural gas, and weSequent typically either shareshares profits with customers or paypays them a fee for using their assets. On
In April 1, 2005, in connection with the acquisition of NUI, Sequent plans to commencecommenced asset management responsibilities for Elizabethtown Gas, Florida City Gas and Elkton Gas. In October 2005, the agreement between Sequent and Virginia Natural Gas was renewed for an additional three years. The contractagreement was scheduled to expire in October 2005. In January 2006, the Georgia Commission extended the asset management agreement between Sequent and Atlanta Gas Light for two additional years. The agreement was scheduled to expire in March 2006. Under the terms are currently being negotiated.
We have reachedof the following agreements withextended agreement, Sequent will increase its aggregate net sharing percentage paid to Atlanta Gas Light from 50% to 60% on the Virginia, Georgia and Tennessee state regulatory commissions to clarify Sequent’smajority of transactions Sequent will initiate going forward in its role as asset manager for our regulated utilities. Failure to renew these agreements on terms substantially similar to the current terms would, over time, have a significant impactmanager. The following table provides additional information on Sequent’s EBIT if other customers and assets were not found to replace our utility asset management earnings.agreements with its affiliated utilities.
· | In November 2000, the Virginia Commission approved an asset management agreement that provides for a sharing of profits between Sequent and Virginia Natural Gas customers. This agreement expires in October 2005, unless Sequent, Virginia Natural Gas and the Virginia Commission agree to extend the contract. In December 2004, we contributed approximately $3 million to Virginia Natural Gas customers for the contract year November 2003 through October 2004. This contribution is being reflected as a reduction to customers’ gas cost in 2005. We commenced discussions as to mutually acceptable terms under which this agreement could be extended. |
· | Various Georgia statutes require Sequent, as asset manager for Atlanta Gas Light, to share 90% of its earnings from capacity release transactions with Georgia’s Universal Service Fund (USF). A December 2002 GPSC order requires net margin earned by Sequent, for transactions involving Atlanta Gas Light assets other than capacity release, to be shared equally with the USF. Sequent operates under an asset management agreement with Atlanta Gas Light which is currently scheduled to expire in March 2006. In 2004, we contributed approximately $4 million to the USF based upon profits earned in the last six months of 2003 and for the first six months of 2004. |
· | In June 2003, the Chattanooga Gas tariff was amended effective January 1, 2003 to require all net margin earned by Sequent for transactions involving Chattanooga Gas assets to be shared equally with Chattanooga Gas ratepayers. This agreement expires in April 2006 and is subject to automatic extensions unless specifically terminated by either party. In 2004, Sequent contributed approximately $1 million to Chattanooga Gas customers based upon profits earned in 2003. This contribution was reflected as reduction to customer’s gas costs in 2004. |
| Duration of | Expiration | Type of fee | % Shared or | Profit sharing / fees payments |
Dollars in millions | contract (in years) | date | structure | annual fee | 2005 | 2004 | 2003 |
Elkton Gas | 2 | Mar 2007 | Fixed-fee | (A) | $- | $- | $- |
Chattanooga Gas | 3 | Mar 2007 | Profit -sharing | 50% | 2 | 1 | - |
Atlanta Gas Light | 2 | Mar 2008 | Profit -sharing | 60% | 4 | 4 | 3 |
Elizabethtown Gas | 3 | Mar 2008 | Fixed -fee | $4 | - | - | - |
Florida City Gas | 3 | Mar 2008 | Profit -sharing | 50% | - | - | - |
Virginia Natural Gas | 3 | Mar 2009 | Profit -sharing | (B) | 5 | 3 | 5 |
(A) Annual fixed fee is less than $1 million |
(B) Sharing is based on a tiered sharing structure |
Transportation and storage transactionsStorage Transactions In our wholesale marketing and risk management business, Sequent also contracts for natural gas transportation and storage services. We participate in transactions to manage the natural gas commodity and transportation costs that result in the lowest cost to serve our various markets. We seek to optimize this process on a daily basis, as market conditions change, by evaluating all the natural gas supplies, transportation alternatives and markets to which we have access and identifying the least-cost alternatives to serve our various markets. This enables us to capture geographic pricing differences across these various markets as delivered gas prices change.
In a similar manner, we participate in natural gas storage transactions where we seek to identify pricing differences that occur over time as prices forwith regard to future delivery periods at many locations are readily available.multiple locations. We capture margin by locking in the price differential between purchasing natural gas at the lowest future price and, in a related transaction, selling that gas at the highest future price, all within the constraints of our contracts. Through the use of transportation and storage services, we are able to capture margin through the arbitrage of geographical pricing differences and by recognizing pricing differences that occur over time.
Producer servicesServices Our producer services business primarily focuses on aggregating natural gas supply from various small and medium-sized producers located throughout the natural gas production areas of the United States, principally in the Gulf Coast region. We provide the producers with certain logistical and risk management services that offer them attractive options to move their supply into the pipeline grid. Aggregating volumes of natural gas from these producers allows us to provide markets to producers who seek a reliable outlet for their natural gas production.
Peaking servicesServices Wholesale servicesSequent generates operating margin through, among other things, the sale of peaking services, which includes receiving a fee from affiliated and non-affiliatednonaffiliated customers that guarantees that those customers will receive gas under peak conditions. Wholesale servicesSequent incurs costs to support our obligations under these agreements, which will beare reduced in whole or in part as the matching obligations expire. We will continue to seek new peaking transactions as well as work toward extending those that are set to expire.
Competition Sequent competes for asset management business with other energy wholesalers, often through a competitive bidding process. Sequent has historically been successful in obtaining new asset management business by placing bids that were based primarily on the intrinsic value of the transaction, which is the difference in commodity prices between time periods or locations at the inception of the transaction.
There has been significant consolidation of energy wholesale operations, particularly among major gas producers. Financial institutions have also entered the marketplace. As a result, energy wholesalers have become increasingly willing to place bids for asset management transactions that are priced to capture market share. We expect this trend to continue in the near term, which could result in downward pressure on the volume of transactions and the related margins available in this portion of Sequent’s business.
Business expansionSequent has been focusing on expanding its business, both geographically and through added emphasis on the origination of new asset management transactions and growing the producer services businesses. Throughout 2004, we added personnel to focus specifically on these opportunities and continued to execute additional nonaffiliated asset management transactions. Our business territory now extends from Texas to Michigan and most other areas of the United States east of the Mississippi River.
This expansion, as well as our other business growth, has increased Sequent’s fixed cost commitments in the form of firm capacity charges for transportation and storage contracts and has lengthened the average tenure of our portfolio to 25 months at December 31, 2004. At December 31, 2004, Sequent’s longest-dated contract in its portfolio was 23 years and was obtained as part of the NUI acquisition. Excluding this contract, Sequent’s portfolio contains transactions with contract terms ranging from one day to eight years. At December 31, 2004, Sequent’s firm capacity commitments were
In millions | | Contract From NUI Acquisition | | Other | | Total | |
2005 | | $ | 5 | | $ | 8 | | $ | 13 | |
2006 | | | 5 | | | 2 | | | 7 | |
2007 and thereafter | | | 107 | | | 9 | | | 116 | |
Seasonality Fixed cost commitments are generally incurred evenly over the year, while margins generated through the use of these assets are generally greatest in the winter heating season and occasionally in the summer due to peak usage by power generators in meeting air conditioning load. This increases the seasonality of our business, generally resulting in expected higher margins in the first and fourth quarters.
Business outlookContinued growth of the nonaffiliated asset managementEnergy Marketing and producer services business lines will be critical to Sequent’s success in 2005. Despite the consolidations within the industry, many entities are reluctant to turn over the marketing of their gas or their assets to a major competitor and may favor an independent wholesale services provider. In addition, many utilities are seeking incremental services to meet peak-day needs, which is an area of core expertise for Sequent.
We manage our business with limited open positions and limited value at risk (VaR). However, the rescission of EITF 98-10 and our adoption of EITF 02-03 in 2003 have increased earnings volatility in our reported results, as more fully discussed below. Given significant underlying volatility in gas commodity prices, we expect volatility in our earnings to continue.
Energy marketing and risk management activitiesRisk Management Activities We accountedaccount for derivative transactions in connection with our energy marketing activities on a fair value basis in accordance with SFASStatement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), and prior to 2003 we accounted for nonderivative energy and energy-related activities in accordance with EITF 98-10.
Under these methods, we recorded. We record derivative energy commodity contracts (including both physical transactions and financial instruments) at fair value, with unrealized gains or losses from changes in fair value reflected in our earnings in the period of change. We also recorded
Sequent’s energy-trading contracts as defined under EITF 98-10, on a mark-to-market basis for transactions executed on or before October 25, 2002. Energy-trading contracts entered into after October 25, 2002 wereare recorded on an accrual basis as required under the EITF Issue No. 02-03, “Issues Involved in Accounting for Contracts under EITF Issue No. 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities'” (EITF 02-03) rescission of EITF 98-10, unless they wereare derivatives that must be recorded at fair value under SFAS 133.
Effective January 1, 2003, we adopted EITF 02-03 (which rescinded EITF 98-10) which had the following effects:
· | Contracts that do not meet the definition of a derivative under SFAS 133 are not marked to fair market value. |
· | Revenues are shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled. |
As a result of our adoption of EITF 02-03:
· | We recorded an adjustment to the carrying value of our non-derivative trading instruments (principally our storage capacity contracts) to zero, and we now account for them using the accrual method of accounting. |
· | We recorded an adjustment to the value of our natural gas inventories used in wholesale services to the lower of average cost or market; we previously recorded them at fair value. This resulted in the cumulative effect of a change in accounting principle in our statement of consolidated income for the three months ended March 31, 2003 of $13 million ($8 million net of taxes), which resulted in a decrease of $13 million to our energy marketing and risk management assets, and a decrease in accumulated deferred income taxes of $5 million in our accompanying consolidated balance sheet. |
· | We reclassified our trading activity on a net basis (revenues net of costs) effective July 1, 2002 as a result of the first consensus of EITF 02-03. This reclassification had no impact on our previously reported net income or shareholders’ equity. Revenues for all periods are shown net of costs associated with trading activities. |
As shown in the table below, Sequent recorded net unrealized gainslosses related to changes in the fair value of derivative instruments utilized in ourits energy marketing and risk management activities of $30 million during 2005, unrealized gains of $22 million during 2004 and $1 million during 2003 and $4 million in 2002.2003. The tables below illustrate the change in the net fair value of the derivative instruments and energy-trading contracts during 2005, 2004 2003 and 20022003 and provide details of the net fair value of contracts outstanding as of December 31, 2004. Sequent’s storage positions are affected by price sensitivity in the New York Mercantile Exchange (NYMEX) average price.2005.
In millions | | 2004 | | 2003 | | 2002 | |
Net fair value of contracts outstanding at beginning of period | | | ($5 | ) | $ | 7 | | $ | 3 | |
Cumulative effect of change in accounting principle | | | - | | | (13 | ) | | - | |
Net fair value of contracts outstanding at beginning of period, as adjusted | | | (5 | ) | | (6 | ) | | 3 | |
Contracts realized or otherwise settled during period | | | 11 | | | 2 | | | (5 | ) |
Change in net fair value of contract gains (losses) | | | 11 | | | (1 | ) | | 9 | |
Net fair value of new contracts entered into during period | | | - | | | - | | | - | |
Net fair value of contracts outstanding at end of period | | | 17 | | | (5 | ) | | 7 | |
Less net fair value of contracts outstanding at beginning of period, as adjusted for cumulative effect of change in accounting principle | | | (5 | ) | | (6 | ) | | 3 | |
Unrealized gain related to changes in the fair value of derivative instruments | | $ | 22 | | $ | 1 | | $ | 4 | |
In millions | | 2005 | | 2004 | | 2003 | |
Net fair value of contracts outstanding at beginning of period | | $ | 17 | | | ($5 | ) | $ | 7 | |
Cumulative effect of change in accounting principle | | | - | | | - | | | (13 | ) |
Net fair value of contracts outstanding at beginning of period, as adjusted | | | 17 | | | (5 | ) | | (6 | ) |
Contracts realized or otherwise settled during period | | | (47 | ) | | 11 | | | 2 | |
Change in net fair value of contract gains (losses) | | | 17 | | | 11 | | | (1 | ) |
Net fair value of new contracts entered into during period | | | - | | | - | | | - | |
Net fair value of contracts outstanding at end of period | | | (13 | ) | | 17 | | | (5 | ) |
Less net fair value of contracts outstanding at beginning of period, as adjusted for cumulative effect of change in accounting principle | | | 17 | | | (5 | ) | | (6 | ) |
Unrealized (loss) gain related to changes in the fair value of derivative instruments | | $ | (30 | ) | $ | 22 | | $ | 1 | |
The sources of our net fair value at December 31, 20042005 are as follows. The “prices actively quoted” category represents Sequent’s positions in natural gas, which are valued exclusively using NYMEXNew York Mercantile Exchange, Inc. (NYMEX) futures prices. “Prices provided by other external sources” are basis transactions that represent the cost to transport the commodity from a NYMEX delivery point to the contract delivery point. Our basis spreads are primarily based on quotes obtained either directly from brokers or through electronic trading platforms.
In millions | | Maturity Less Than 1 Year | | Maturity 1-3 Years | | Maturity 4-5 Years | | Maturity in Excess of 5 Years | | Total Net Fair Value | |
Prices actively quoted | | $ | 6 | | $ | 1 | | $ | - | | $ | - | | $ | 7 | |
Prices provided by other external sources | | $ | 10 | | $ | - | | $ | - | | $ | - | | $ | 10 | |
In millions | | Prices actively quoted | | Prices provided by other external sources | |
Mature through 2006 | | | ($3 | ) | | ($14 | ) |
Mature 2007 - 2008 | | | 3 | | | - | |
Mature 2009 - 2011 | | | - | | | 1 | |
Mature after 2011 | | | - | | | - | |
Total net fair value | | $ | - | | | ($13 | ) |
Mark-to-market versus lowerMark-to-Market Versus Lower of average costAverage Cost or marketMarket We purchaseSequent purchases natural gas for storage when the current market price we pay for gasit pays plus the cost to store the gasfor transportation and storage is less than the market price weit could receive in the future. We attemptSequent attempts to mitigate substantially all of ourthe commodity price risk associated with ourits storage gas portfolio. We useSequent uses derivative instruments to reduce the risk associated with future changes in the price of natural gas. We sellSequent sells NYMEX futures contracts or other over-the-counter derivatives in forward months to substantially lock-inlock in the profit margin weit will ultimately realize when the stored gas is actually sold.
GasNatural gas stored in inventory is accounted for differently than the derivatives we useSequent uses to mitigate the commodity price risk associated with ourits storage portfolio. The difference in accounting can result in volatility in our reported net income, even though the profit margin is essentially unchanged from the date the transactions were consummated. Gasnatural gas that we purchaseSequent purchases and injectinjects into storage is accounted for at the lower of average cost or market. The derivatives we usethat Sequent uses to mitigate commodity price risk are accounted for at fair value and marked to market each period. These differencesThe difference in our accounting treatment, including the accrual basis for our gas storage inventory versus fair value accounting for the derivatives used to mitigate commodity price risk, can result in volatility in ourSequent’s reported earnings.results, even though the expected profit margin is essentially unchanged from the date the transactions were consummated.
Earnings volatilityVolatility and price sensitivityPrice Sensitivity Over time, gains or losses onThe market dynamics created by the sale oftwo Gulf Coast hurricanes significantly impacted natural gas storage inventory will be offset by losses or gains on the derivatives used as hedges, resultingprices, primarily in the realizationlast five months of the profit margin we expected when we entered into the transactions. Accounting differences cause Sequent’s earnings on its storage gas positions2005. From June 30, 2005 to be affected by natural gas price changes, even though the economic profits remain essentially unchanged. Based upon our storage positions at December 31, 2004, a $0.10 change inSeptember 30, 2005, the forward NYMEX prices would result in a $0.3 millionthrough March 2006 increased on average approximately $6.10, or 75%. From October 1, 2005 to December 31, 2005, the same prices decreased on average approximately $3.10, or 21%. These market dynamics created significant market opportunities for Sequent, as its storage and transportation activities created increased economic value compared to 2004.
The accounting differences described above also impact to Sequent’s EBIT. As Sequent’s storage position increases, its earnings volatility may also increase. For example, at year end, if allthe comparability of Sequent’s storage had been full, a $0.10 changeperiod-over-period results, since changes in forward NYMEX prices would havedo not increase and decrease on a consistent basis from year to year. During most of 2005, Sequent’s reported results were negatively impacted by increases in forward NYMEX prices which resulted in the recognition of unrealized losses. During 2004, the reported results were not as significantly impacted by changes in forward NYMEX prices. As a $0.7 million impact to its earnings.result, a comparison of the 2005 and 2004 reported results yielded an unfavorable variance during the first nine months of 2005; however, the majority of these unrealized losses were recovered during the fourth quarter of 2005.
In addition, if we were to value the gas inventory at fair value, with the change in fair value during the year reflected in earnings, Sequent’s EBIT would have increased, net
Storage inventory outlookInventory Outlook The following table presents the NYMEX forward curve graph set forth below reflects the NYMEX natural gas prices as of September 30, 20042005 and December 31, 20042005 for the period of January 20052006 through November 2005. The curveMarch 2006, and reflects the prices at which weSequent could buy natural gas at the Henry Hub for delivery in the same time period. (Note: January 20052006 futures expired on December 28, 2004;2005; however they are included in the table below as they coincide with the January 2006 storage withdrawals.) The Henry Hub, located in Louisiana, is the largest centralized point for natural gas spot and futures trading in the United States. NYMEX uses the Henry Hub as the point of delivery for its natural gas futures contracts. Many natural gas marketers also use the Henry Hub as their physical contract delivery point foror their price benchmark for spot trades of natural gas.
| | NYMEX forward natural gas prices as of | | | | | |
| | Sep 2005 | | Dec 2005 | | $ Change | | % Change | |
Jan-06 | | $ | 14.77 | | $ | 11.43 | | $ | (3.34 | ) | | (23 | %) |
Feb-06 | | | 14.51 | | | 11.23 | | | (3.28 | ) | | (23 | %) |
Mar-06 | | | 14.04 | | | 11.36 | | | (2.68 | ) | | (19 | %) |
Avg. | | | 14.44 | | | 11.34 | | | (3.10 | ) | | (21 | %) |
The NYMEX forward curve graph also displays the significant decline in first quarter 2005 NYMEX prices experienced duringdecreased on average 21% in the fourth quarter of 2004. As shown2005 due to warmer-than-normal weather in late December 2005 and the diminishing effects of hurricanes Rita and Katrina in the table following the graph, the majorityfall of our inventory in storage as of December 31, 2004 was scheduled for withdrawal in early 2005. Since we have these NYMEX contracts in place, ourSequent’s original economic profit margin is unaffected.was unaffected by these changes in the NYMEX forward natural gas prices due to the hedging instruments that it has in place. However, the decline in NYMEX prices during the fourth quarter of 20042005 resulted in the recovery of previously reported unrealized gainslosses associated with ourSequent’s NYMEX contracts. During the fourth quarter of 2003, we experienced the opposite occurrence when NYMEX prices were increasing. In 2003, our near-term profits declined because our future period hedges were at values lower than the prevailing market prices for the months in which we held the NYMEX contracts. See further discussions in “Results of Operations” below.
As shownSequent’s expected withdrawals from physical salt dome and reservoir storage are presented in the table below “Open Futures NYMEX Contracts” represents the volume in contract equivalentsalong with its expected gross margin. Sequent’s expected gross margin is net of the transactionsimpact of regulatory sharing and reflects the amounts that we executedwould expect to lockrealize in our storagefuture periods based on the inventory margin. Each contract equivalent represents 10,000 million British thermal units (MMBtu’s). As ofwithdrawal schedule and forward natural gas prices at December 31, 2004, the expected withdrawal schedule of this inventory is reflected in items (B) and (C). At December 31, 2004, the weighted average cost of gas (WACOG) in salt dome storage was $5.83, and the WACOG for gas in reservoir storage was $5.88.
The table also reflects that our2005. Sequent’s storage inventory is fully hedged with futures as its NYMEX short positions are equal to the physical long positions, which results in an overall locked-in margin, timing notwithstanding. Expected gross margin after regulatory sharing reflects the gross margin we would generateSequent’s physical salt dome and reservoir volumes are presented in future periods based on the forward curveincrements of 10,000 million British thermal units (MMBtu).
| | Withdrawal schedule (in MMBtu) | | Expected | |
| | Physical salt dome | | Physical reservoir | | gross margin (in millions) (1) | |
Jan-06 | | | 119 | | | 92 | | $ | 5 | |
Feb-06 | | | 149 | | | 212 | | | 6 | |
Mar-06 | | | 16 | | | 252 | | | 5 | |
Total | | | 284 | | | 556 | | $ | 16 | |
(1) | After regulatory sharing |
The weighted average cost of natural gas in inventory was $9.76 for physical salt dome storage and inventory withdrawal schedule at December 31, 2004. Our current$8.98 for physical reservoir storage. As noted above, Sequent’s inventory level and pricing willas of December 31, 2005 should result in a gross margin of $1approximately $16 million during 2005. This gross marginthrough March 2006 if all factors remain the same, but could change if we adjust ourSequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months.
| | | | | | | | | | | | Total |
(A) | (21) | (105) | (286) | - | - | - | - | - | (2) | (10) | - | (424) |
| | | | | | | | | | | | |
(B) | 4 | - | - | - | - | - | - | - | - | - | - | 4 |
(C) | 17 | 105 | 286 | - | - | - | - | - | 2 | 10 | - | 420 |
| 21 | 105 | 286 | - | - | - | - | - | 2 | 10 | - | 424 |
(D) | $0.1 | $0.2 | $0.8 | $- | $- | $- | $- | $- | $- | $- | $- | $1.1 |
(A) Open futures NYMEX contracts (short) long (in MMBtu)
(B) Physical salt dome withdrawal schedule (in MMBtu)
(C) Physical reservoir withdrawal schedule (in MMBtu)
(D) Expected gross margin, in millions, after regulatory sharing for withdrawal activity
Park and loan outlookCredit Rating Additionally, we have entered into park and loan transactions with various pipelines. A park and loan transaction is a tariff transaction offered by pipelines in which the pipeline allows the customer to park gas on or borrow gas from the pipeline in one period and reclaim gas from or repay gas to the pipeline in a subsequent period. The economics of these transactions are evaluated and price risks are managed similar to the way traditional reservoir and salt dome storage transactions are evaluated and managed. Sequent enters into forward NYMEX contracts to hedge its park and loan transactions. However, these transactions have elements that qualify as and must be accounted for as derivatives in accordance with SFAS 133.
Under SFAS 133, park and loan transactions are considered to be financing arrangements when the contracts contain volumes that are payable or repaid at determinable dates and at a specific time to third parties. Because these park and loan transactions have fixed volumes, they contain price risk for the change in market prices from the date the transaction is initiated to the time the gas is repaid. As a result, these transactions qualify as derivatives under SFAS 133 that must be recorded at their fair value. Certain park and loan transactions that we execute meet this definition. As such, we account for these transactions at fair value once the transaction has started (either the gas is originally parked on or borrowed from the pipeline) and represent the fair value of the derivatives in the consolidated balance sheet as “Inventories” and reflect the related changes in fair value in our statement of consolidated income.
The table below shows Sequent’s park and loan volumes and expected gross margin from park and loans for the indicated periods. “Park and (loan) volumes” represents the contract equivalent for the volumes of our park and loan transactions as of December 31, 2004 that is not already accounted for at fair value. “Expected gross margin from park and loans” represents the gross margin from those transactions expected to be recognized in future periods based on the NYMEX forward curves at December 31, 2004.
In millions | | Jan. 2005 | | Feb. 2005 | | Mar. 2005 | | Apr. 2005 | | May 2005 | | June 2005 | | July 2005 | | Total | |
Park and (loan) volumes (MMBtu) | | | (15 | ) | | 12 | | | 6 | | | - | | | 15 | | | (12 | ) | | (6 | ) | | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Expected gross margin from park and (loans) | | | ($0.3 | ) | $ | 0.3 | | $ | 0.1 | | | - | | | - | | | - | | | - | | $ | 0.1 | |
Credit ratingSequent has certain trade and credit contracts that have explicit credit rating trigger events in case of a credit rating downgrade. These rating triggers typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, we would need to post collateral to continue transacting business with some of our counterparties. Posting collateral would have a negative effect on our liquidity. If such collateral were not posted, our ability to continue transacting business with these counterparties would be impaired. If at December 31, 2004,2005 our credit ratings had been downgraded to non-investment grade, status, the required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $20$51 million.
Results of Operations The following table presents results of operations for our wholesale services segment for the years ended December 31, 2005, 2004 2003 and 2002 are as follows:2003.
In millions | | 2005 | | 2004 | | 2003 | |
Operating revenues | | $ | 95 | | $ | 54 | | $ | 41 | |
Cost of sales | | | 3 | | | 1 | | | 1 | |
Operating margin | | | 92 | | | 53 | | | 40 | |
Operation and maintenance | | | 39 | | | 27 | | | 20 | |
Depreciation and amortization | | | 2 | | | 1 | | | - | |
Taxes other than income | | | 1 | | | 1 | | | - | |
Total operating expenses | | | 42 | | | 29 | | | 20 | |
Operating income | | | 50 | | | 24 | | | 20 | |
Other loss | | | (1 | ) | | - | | | - | |
EBIT | | $ | 49 | | $ | 24 | | $ | 20 | |
| | | | | | | | | | |
Metrics | | | | | | | | | | |
Physical sales volumes (billion cubic feet / day) | | | 2.17 | | | 2.10 | | | 1.75 | |
2005 compared to 2004 The increase in EBIT of $25 million or 104% in 2005 compared to 2004 was due to an increase in operating margin of $39 million partially offset by an increase in operating expenses of $13 million.
In millions | | 2004 | | 2003 | | 2002 | | 2004 vs. 2003 | | 2003 vs. 2002 | |
Operating revenues | | $ | 54 | | $ | 41 | | $ | 23 | | $ | 13 | | $ | 18 | |
Cost of sales | | | 1 | | | 1 | | | - | | | - | | | 1 | |
Operating margin | | | 53 | | | 40 | | | 23 | | | 13 | | | 17 | |
Operation and maintenance expenses | | | 27 | | | 20 | | | 13 | | | 7 | | | 7 | |
Depreciation and amortization | | | 1 | | | - | | | - | | | 1 | | | - | |
Taxes other than income | | | 1 | | | - | | | 1 | | | 1 | | | (1 | ) |
Total operating expenses | | | 29 | | | 20 | | | 14 | | | 9 | | | 6 | |
Operating income | | | 24 | | | 20 | | | 9 | | | 4 | | | 11 | |
Other loss | | | - | | | - | | | - | | | - | | | - | |
EBIT | | $ | 24 | | $ | 20 | | $ | 9 | | $ | 4 | | $ | 11 | |
| | | | | | | | | | | | | | | | |
Metrics | | | | | | | | | | | | | | | | |
Physical sales volumes(Bcf/day) | | | 2.10 | | | 1.75 | | | 1.39 | | | 20 | % | | 26 | % |
Sequent’s operating margin increased by $39 million or 74% primarily due to the significant effects of the Gulf Coast hurricanes during the third quarter of 2005 and lingering market disruptions and price volatility throughout the fourth quarter. For the first nine months of the year, reported operating margin was similar to that of the prior year, with quarterly decreases being offset by quarterly increases. However, during the third quarter of 2005, while we created substantial economic value by serving our customers during the storms, our reported operating margin was negatively impacted by accounting losses associated with our storage hedges as a result of increases in forward natural gas prices of approximately $6 per MMBtu. During the fourth quarter, natural gas prices continued to be volatile in the aftermath of the hurricanes and we were able to further optimize our storage and transportation positions at levels in excess of the prior year. In addition, our previously reported hedge losses were partially recovered during the fourth quarter as forward natural gas prices decreased approximately $3 per MMBtu.
Operating expenses increased by $13 million or 45% due to additional payroll associated with increased headcount and increased employee incentive compensation costs driven by Sequent’s operational and financial growth and depreciation expense in connection with Sequent’s new energy trading and risk management (ETRM) system, which was implemented during the fourth quarter of the prior year.
2004 compared to 2003EBIT increased $4 million or 20% from 2003 to 2004 due to a $13 million increase in operating margin, partially offset by a $9 million increase in operating expenses.
Operating margin increased by $13 million or 33% primarily due to increased volatility during the fourth quarter of 2004 which provided Sequent with seasonal trading, marketing, origination and asset management opportunities in excess of those experienced during the prior year. Also contributing to the increase were advantageous transportation values to the Northeast and new peaking and third-party asset management transactions. Sequent’s sales volumes for 2004 wereaveraged 2.10 Bcf/billion cubic feet per day, a 20% increase from the prior year. This increase resulted primarily from the addition of new counterparties, increased presence in the Midwestmidwestern and Northeastnortheastern markets and continued growth in origination and asset management activities, as well as the business generated due to the market volatility experienced during the fourth quarter.
As a result of a decline in forward NYMEX prices, the 2004 results reflectreflected the recognition of unrealized gains associated with the financial instruments used to economically hedge Sequent’s inventory held in storage. If the forward NYMEX price in effect at December 1, 2004 had also been in effect at December 31, 2004, based uponon Sequent’s storage positions at December 31, 2004, Sequent’s reported EBIT would have been $19 million. At December 31, 2003, an increase in forward NYMEX prices resulted in the recognition of modest unrealized losses associated with inventory hedges.
Partially offsetting the improved fourth quarterfourth-quarter results was lower volatility during the second quarter of 2004 compared to the same period in 2003, which compressed Sequent's trading and marketing activities and the related margins within its transportation portfolio. In addition, Sequent's weighted average cost of natural gas stored in inventory was $5.06 per MMBtu during the first quarter of 2004 compared to $2.20 per MMBtu during the same period in 2003. This significant difference in cost resulted in reduced operating margins period over period.
Operating expenses increased by $9 million or 45% due primarily to additional salary expense as a result of an increase in the number of employees,employees; additional costs for outside services related to the development and implementation of Sequent’s ETRM system,system; the implementation of SOX 404404; and increased corporate costs. In addition, 2004 operating expenses reflectreflected depreciation associated with the recently implemented ETRM system.
2003 compared to 2002EBIT increased $11 million or 122% from 2002 primarily due to a $17 million increase in operating margin, offset by an increase of $6 million in operating expenses. The increase of $17 million or 74% in operating margin was due primarily to Sequent’s optimization of various transportation and storage assets, mainly in the first quarter when natural gas prices were highly volatile. Sequent’s physical sales volumes for 2003 increased 26% to 1.75 Bcf/day as compared to 2002. This increase was partially attributable to Sequent’s successful efforts to gain additional new business in the Midwest and Northeast. Additionally, a number of market factors, including colder temperatures during the winter in market areas served by Sequent and reduced amounts of gas in storage as the winter progressed, resulted in increased volatility in Sequent’s markets during the first quarter of 2003 compared to the same period of 2002. The volatility in the second and third quarters returned to seasonal averages and increased slightly above average in the fourth quarter.
In the first quarter, Sequent sold substantially all of its inventory that was previously recorded on a mark-to-market basis under the now-rescinded EITF 98-10. This resulted in $13 million in realized income, offset by amounts shared with our affiliated LDCs for transactions that were recorded on a mark-to-market basis in prior periods. The increase in operating margin was partly offset by lower natural gas volatility created by unseasonably cool temperatures in the Southeast, Midwest and Upper Mid-Atlantic during the summer of 2003. In the summer of 2002, volatility was higher as a result of two hurricanes in the Gulf of Mexico and warmer-than-normal temperatures in the Northeast.
Operating expenses increased by $6 million or 43%, primarily due to a $3 million increase in corporate costs and a $3 million increase primarily due to personnel and outside consulting costs incurred while growing the business.
Our energy investments segment includes
SouthStar is a joint venture formed in 1998 by our subsidiary, Georgia Natural Gas Company, Piedmont and Dynegy Inc. (Dynegy) to market natural gas and related services to retail customers, principally in Georgia. On March 11, 2003, we purchased Dynegy’s 20% ownership interest in a transaction that for accounting purposes had an effective date of February 18, 2003.
We currently own a non-controlling 70% financial interest in SouthStar, and Piedmont owns the remaining 30%. Our 70% interest is non-controlling because all significant management decisions require approval of both owners. On March 29, 2004, we executed an amended and restated partnership agreement with Piedmont. This amended and restated partnership agreement calls for SouthStar’s future earnings starting in 2004 to be allocated 75% to our subsidiary and 25% to Piedmont. In addition, we executed a services agreement which provided that AGL Services Company will provide and administer accounting, treasury, internal audit, human resources and information technology functions for SouthStar.
CompetitionSouthStar, which operates under the trade name Georgia Natural Gas, competes with other energy marketers, including Marketers in Georgia, to provide natural gas and related services to customers in Georgia and the Southeast. Based upon its market share, SouthStar is the largest retail marketer of natural gas in Georgia with average customers in 2004 in excess of 500,000. This represents a market share of approximately 36% as of December 31, 2004, which is consistent with its market share in 2003 and 2002.
Pivotal Jefferson Island Storage & Hub, LLC (Pivotal Jefferson Island), ourThis wholly owned subsidiary operates a salt dome storage and hub facility in Louisiana, approximately eight miles from the Henry Hub. We acquired the facilityfrom American Electric Power in October 2004 for an adjusted price of $90 million, which included approximately $9 million of working gas inventory. We funded the acquisition with a portion of the net proceeds we received from our November 2004 common stock offering and debt borrowings.
The storage facility is regulated by the Louisiana Public Service Commission and by the FERC the latter of which regulateshas limited regulatory authority over the storage and transportation services. The facility consists of two salt dome gas storage caverns with 9.410 million Dekatherms (Dth)Dth (MMDth) of total capacity and about 6.97.2 million DthMMDth of working gas capacity. By increasing the maximum operating pressure, we can periodically increase the working gas capacity to approximately 7.4 million Dth. The facility has approximately 720,000 Dth/day withdrawal capacity and 240,000360,000 Dth/day injection capacity. Pivotal Jefferson Island provides for storage and hub services through its direct connection to the Henry Hub via the Sabine Pipeline and its interconnection with seven other pipelines in the area. Our subsidiary Pivotal Energy Development (Pivotal Development) is responsible for the day-to-day operation of the facility.
Pivotal Jefferson Island is fully subscribed for the 2004-20052005-2006 winter period. Beginning April 1,
In October 2005, approximately 2.5 Bcf of capacity will become available. Marketing of this capacity is ongoing. Pivotal Jefferson Island intendsalso announced that it is soliciting customer interest, in the form of nonbinding bids for capacity, in a project that would expand Pivotal Jefferson Island’s salt dome storage facility by 175% from its current capacity of 7.2 MMDth to lease any unsubscribedas much as 19.8 MMDth. The expansion under consideration includes the development of a third and a fourth storage cavern at the facility, with each cavern having a working gas capacity of 6 MMDth. If there is sufficient customer interest in the project, construction would begin in early 2006. We would expect to one or more customerscomplete the third cavern by 2009 and would expect the fourth cavern to be operational by 2011. The expansion project also includes expanding the number of pipeline interconnections in 2005, for varying term lengthsorder to create a portfolioenhance Pivotal Jefferson Island’s flexibility with regard to storage capacity and deliverability. In February 2006, our Board of contracts for service.Directors approved the project and authorized it to go forward. We expect to spend up to approximately $160 million on the expansion project. Pivotal Development’s engineering estimates and the need to acquire equipment with appropriate specifications could result in increased costs and delays in the completion of the project.
Pivotal Jefferson Island’s competition is limited to other saltdome caverns in the Gulf Coast. We believe that Pivotal Jefferson Island is currently expandinguniquely situated with its compression capabilitydirect connection to enhance the numberHenry Hub and its connection to seven other pipelines. For these reasons we believe that Pivotal Jefferson Island will be subscribed ahead of times a customer can inject and withdraw gas. We expect to complete this upgrade in the third quartermost of 2005.its competitors.
Pivotal Propane of Virginia, Inc. (Pivotal Propane), our In 2005, this wholly owned subsidiary intends to complete in the first quarter of 2005completed the construction of a propane air facility in the Virginia Natural Gas service area to provide it withthat provides up to 28,800 Dth of propane air per day on a 10-day-per-year basis to serve Virginia Natural Gas’ peaking needs. The cold storage tank foundation is complete and construction of the process facility is under way. We expect the plant to be initially available in the first quarter of 2005.
Virginia Gas Companyis a natural gas storage, pipeline and distribution company with principal operations in Southwestern Virginia. Virginia Gas Company, through its wholly owned subsidiary Virginia Gas Pipeline Co., owns and operates a 72-mile intrastate pipeline and operates two storage facilities, a high-deliverability salt cavern facility, Saltville Storage Inc. (Saltville Storage) in Saltville, Virginia, and a depleted reservoir facility in Early Grove, Virginia. Combined, the storage facilities have approximately 2.6 Bcf of working gas capacity. Virginia Gas Pipeline Co. also serves as construction and operations manager for our Saltville Storage joint venture described below.
Saltville Storageis a 50% member of Saltville Gas Storage Company, LLC, a joint venture formed in 2001 with a subsidiary of Duke Energy Corporation (Duke) to develop a high-deliverability natural gas storage facility in Saltville, Virginia and is accounted for under the equity method of accounting. Saltville Storage serves customers in the Mid-Atlantic region. Saltville Storage currently has approximately 1.8 Bcf of storage capacity and is planning an expansion to increase its storage capacity to 5.3 Bcf of working gas with deliverability of up to 500 million cubic feet per day. The expansion is expected to be completed in 2008. Saltville Storage connects to Duke’s East Tennessee Natural Gas interstate system and its Patriot pipeline.
All of Virginia Gas Company’s businesses are regulated by the Virginia Commission except Saltville Storage, which is regulated by the FERC. As such, Saltville Storage is required to construct and operate its facilities and provide service subject to FERC regulations.
AGL Networks LLC (AGL Networks), our This wholly owned subsidiary is a provider of telecommunications conduit and dark fiber. AGL Networks leases and sells its fiber to a variety of customers in the Atlanta, Georgia and Phoenix, Arizona metropolitan areas, with a small presence in other cities in the United States. Its customers include local, regional and national telecommunications companies, internet service providers, educational institutions and other commercial entities. AGL Networks typically provides underground conduit and dark fiber to its customers under leasing arrangements with terms that vary from 1 to 20 years. In addition, AGL Networks offers telecommunications construction services to companies.
CompetitionAGL Networks’ competitors exist to the extentare any entities that they have or will lay conduit and fiber or may install conduit in the future on the same route as AGL Networks in the respective metropolitan areas. We believe our conduit and dark fiber footprint in Atlanta and Phoenix are unique continuous rings and, as such, will be subscribed ahead of most competitors as market conditions support greater use of our product.
US PropaneSale of certain NUI Assets is a joint venture formed in 2000 by us, Atmos Energy Corporation, Piedmont and TECO Energy, Inc. US Propane owned all the general partnership interests, directly or indirectly, and approximately 25% of the limited partnership interests in Heritage Propane Partners, L.P., a publicly traded marketer of propane. On January 20, 2004,In August 2005, we sold our 50% interest in Saltville Gas Storage Company, LLC (Saltville) and associated subsidiaries (Virginia Gas Pipeline and Virginia Gas Storage) to a subsidiary of Duke Energy Corporation, the other 50% partner in the Saltville joint venture. We acquired these non-utility assets as part of our purchase of NUI in November 2004. We received $66 million in cash at closing, which included $4 million in working capital adjustments, and used the proceeds to repay short-term debt and for other general and limited partnership interests for $29 million and recognized a gain of $1 million, which we recorded in other income.corporate purposes.
Results of operationsOperations The following table presents results of operations for our energy investments segment for the year ended December 31, 2004, and pro-forma results as if SouthStar’s accounts were consolidated with our subsidiaries’ accounts for the years ended December 31, 20032005, 2004 and 2002 are set forth below. The unaudited pro-forma results are presented for comparative purposes as a result of our consolidation of SouthStar in 2004. This pro-forma basis is a non-GAAP presentation; however, we believe it is useful to the readers of our financial statements since it presents prior years’ revenue and expenses on the same basis as 2004.2003.
In 2003In millions | | 2005 | | 2004 | | 2003 | |
Operating revenues | | $ | 56 | | $ | 25 | | $ | 6 | |
Cost of sales | | | 16 | | | 12 | | | 1 | |
Operating margin | | | 40 | | | 13 | | | 5 | |
Operation and maintenance | | | 17 | | | 5 | | | 9 | |
Depreciation and amortization | | | 5 | | | 2 | | | 1 | |
Taxes other than income | | | 1 | | | 1 | | | - | |
Total operating expenses | | | 23 | | | 8 | | | 10 | |
Operating income | | | 17 | | | 5 | | | (5 | ) |
Other income | | | 2 | | | 2 | | | 2 | |
EBIT | | $ | 19 | | $ | 7 | | $ | (3 | ) |
2005 compared to 2004 The $12 million or 171% increase in EBIT in 2005 was primarily the result of increased operating margin of $27 million, offset by $15 million in higher operating expenses.
Of the $27 million or 208% increase in operating margin, $13 million resulted from Pivotal Jefferson Island; NUI’s nonutility businesses, which contributed $8 million; and 2002, we recognized our portionPivotal Propane which contributed $3 million. AGL Networks contributed $4 million primarily from growth both in recurring revenues from fiber leasing activities of SouthStar’s earnings of $46$1 million and $27 million, respectively, as equity earnings. The increasein construction and new business activities of $19$3 million.
Of the $15 million or 70% was primarily due188% increase in operating expenses, $8 million resulted from NUI’s nonutility businesses, $3 million resulted from Pivotal Jefferson Island and $1 million resulted from Pivotal Propane. AGL Networks’ operating expenses were relatively flat in 2005 as compared to resolution of an income sharing issue with Piedmont of $6 million, higher volumes and related operating margin, an additional 20% ownership interest (which contributed approximately $8 million), and lower bad debt and operating expenses.
In millions | | 2004 | | Pro-forma 2003 | | Pro-forma 2002 | | 2004 vs. 2003 | | 2003 vs. 2002 | |
Operating revenues | | $ | 852 | | $ | 752 | | $ | 632 | | $ | 100 | | $ | 120 | |
Cost of sales | | | 707 | | | 622 | | | 515 | | | 85 | | | 107 | |
Operating margin | | | 145 | | | 130 | | | 117 | | | 15 | | | 13 | |
Operation and maintenance expenses | | | 65 | | | 69 | | | 80 | | | (4 | ) | | (11 | ) |
Depreciation and amortization | | | 4 | | | 2 | | | 2 | | | 2 | | | - | |
Taxes other than income | | | 1 | | | 1 | | | - | | | - | | | 1 | |
Total operating expenses | | | 70 | | | 72 | | | 82 | | | (2 | ) | | (10 | ) |
Operating income | | | 75 | | | 58 | | | 35 | | | 17 | | | 23 | |
Other income | | | 2 | | | 2 | | | 4 | | | - | | | (2 | ) |
Minority interest | | | (18 | ) | | (17 | ) | | (15 | ) | | (1 | ) | | (2 | ) |
EBIT | | $ | 59 | | $ | 43 | | $ | 24 | | $ | 16 | | $ | 19 | |
| | | | | | | | | | | | | | | | |
Metrics | | | | | | | | | | | | | | | | |
SouthStar | | | | | | | | | | | | | | | | |
Average customers(in thousands) | | | 533 | | | 558 | | | 564 | | | (4 | %) | | (1 | %) |
Market share in Georgia | | | 36 | % | | 38 | % | | 38 | % | | (5 | %) | | - | |
2004.
2004 compared to 2003The increase in EBIT of $16$10 million or 37% for the year ended December 31, 2004 was primarily the result of increased EBIT of $7 million from SouthStar, EBIT of $3 million from Pivotal Jefferson Island and EBIT of $3 million from AGL Networks. The remaining increase of $3$4 million was from the sale of Heritage Propane Partners, L.P. and the sale of a residential and retail development property in Savannah, Georgia in the second quarter of 2004.
Operating margin for the year increased $15$8 million or 12% primarily as a result of operating margin increases at SouthStar of $8 million, the addition of Pivotal Jefferson Island’s $4 million of operating margin and an operating margin increase at AGL Networks of $4 million. SouthStar’s $8 million operating margin increase was a result of a $9 million increase due primarily to a lower commodity cost structure resulting from continued refinement of SouthStar’s hedging strategies and a $3 million increase due to a full year of higher customer service charges from third party providers. These increases were partially offset by a decrease of $2 million related to a one-time sale of stored gas in 2003 and a $2 million decrease in late payment fees due to an improved customer base. AGL Networks’ increase was due to increased revenue from a variety of customers.
Operating expenses decreased by $2 million or 3%20% primarily due to $6 million lower bad debt expense as a result of ongoing active customer collection process improvements and increased quality of the customer base partially offset by a $5 million increase in corporate allocations and increased costs related to SOX 404 implementation. There was also a $1 million increase in minority interest as a result of higher SouthStar earnings in 2004 as compared to 2003.decreased headcount at AGL Networks.
2003 compared to 2002The EBIT increase of $19 million or 79% was primarily due to increased EBIT at SouthStar and US Propane, offset by lower AGL Networks earnings.
Operating margin increased $13 million or 11% primarily due to $9 million from increased margin from SouthStar resulting from a $3 million one-time sale of storage, a $3 million increase from higher customer service charges and a $3 million increase in additional interruptible margin. There was also a $4 million increase in margin from AGL Networks due to a $3 million increase in monthly recurring contract revenues and a $2 million sales-type lease completed in the first quarter of 2003, partially offset by $1 million of feasibility fee income in 2002; no such fees were recognized in 2003.
The decrease in operating expenses of $10 million or 12% was due primarily to lower bad debt expense at SouthStar of $10 million as a result of improved delinquency processes and customer base and lower operating expenses from a reduction in customer care costs of $3 million. AGL Networks had a $3 million increase in operating expenses due primarily to business growth and higher corporate overhead costs. Other income decreased $2 million due primarily to a contract renewal payment of $2 million associated with the sale of Utilipro.
Our corporate segment includes our nonoperating business units, including AGL Services Company (AGL Services) and(AGSC), AGL Capital Corporation (AGL Capital). AGL Services and Pivotal Development. AGSC is a service company established in accordance with the Public Utility Holding Company Act of 1935, as amended (PUHCA).PUHCA. AGL Capital provides for our ongoing financing needs through itsa commercial paper program, the issuance of various debt and hybrid securities, and other financing arrangements.
In August 2003, we formed Pivotal Energy Development (Pivotal Development) as an operating division within AGL Services. Pivotal Development coordinates, among our related operating segments, the development, construction or acquisition of gas-related assets in the southeastern, mid-Atlantic and northeastern regions our gas utilities serve or where their gas supply originates in order to extend our natural gas capabilities and improve system reliability while enhancing service to our customers in thesethose areas. The focus of Pivotal Development’s commercial activities is to improve the economics of system reliability and natural gas deliverability in these regions as well as acquire and operate natural gas assets that serve wholesale markets, such as underground storage.targeted regions.
We allocate substantially all AGL Services’of AGSC’s and AGL Capital’s operating expenses and interest costs to our operating segments in accordance with the PUHCA and state regulations. Our corporate segment also includes intercompany eliminations for transactions between our operating business segments. Our EBIT results include the impact of these allocations to the various operating segments. The acquisition of additional assets, such as NUI and Pivotal Jefferson Island, typically will enable us to allocate corporate costs across a larger number of businesses and, as a result, lower the relative allocations charged to those business units we owned prior to the acquisition of the new businesses.
Results of operationsAGSC Restructuring As a result of the NUI acquisition, the associated centralization of certain administrative and operational functions and our ongoing desire to operate as efficiently as possible, we began, during the first quarter of 2005, a review of certain functions within our AGSC subsidiary. We expect this process to be part of an ongoing effort to optimize staffing levels and work processes across our entire company.
The effects of this effort were the restructuring of certain key corporate functions and the elimination of filled and vacant positions within AGSC. We recorded a charge of $3 million in 2005, primarily as a result of severance-related costs associated with the restructuring and elimination of the filled positions at AGSC. Based on efforts performed to date, as well as actual costs incurred to date and our original basis for the earnings guidance previously provided, we estimate the annual savings from these efforts to be in the range of $6 million to $10 million.
Results of OperationsThe following table presents results of operations for our corporate segment for the years ended December 31, 2005, 2004 2003 and 2002 are2003.
In millions | | 2005 | | 2004 | | 2003 | |
Payroll | | $ | 57 | | $ | 48 | | $ | 48 | |
Benefits and incentives | | | 34 | | | 32 | | | 32 | |
Outside services | | | 43 | | | 29 | | | 19 | |
Taxes other than income | | | 5 | | | 4 | | | 2 | |
Other | | | 52 | | | 46 | | | 44 | |
Total operating expenses before allocations | | | 191 | | | 159 | | | 145 | |
Allocations to operating segments | | | (185 | ) | | (147 | ) | | (139 | ) |
Operating expenses | | | 6 | | | 12 | | | 6 | |
Loss on asset disposed -Caroline Street campus | | | - | | | - | | | (5 | ) |
Operating loss | | | (6 | ) | | (12 | ) | | (11 | ) |
Other losses | | | (5 | ) | | (4 | ) | | (1 | ) |
EBIT | | $ | (11 | ) | $ | (16 | ) | $ | (12 | ) |
The corporate segment is a nonoperating segment. As such, changes in EBIT amounts for the indicated periods reflect the relative changes in various general and administrative expenses, such as follows:payroll, benefits and incentives and outside services.
2005 compared to 2004The $5 million or 31% increase in EBIT for 2005 compared to 2004 was primarily due to decreased operating expenses of $6 million. These decreased costs were primarily due to merger- and acquisition-related costs incurred in 2004 but not in 2005. With respect to total operating expenses before allocations, payroll expenses in 2005 increased due to headcount in the corporate segment resulting from the acquisition of NUI in November of 2004 and the realignment and transfer of certain corporate functions to AGSC.
In millions | | 2004 | | 2003 | | 2002 | | 2004 vs. 2003 | | 2003 vs. 2002 | |
Payroll | | $ | 48 | | $ | 48 | | $ | 44 | | $ | - | | $ | 4 | |
Benefits and incentives | | | 32 | | | 32 | | | 38 | | | - | | | (6 | ) |
Outside services | | | 29 | | | 19 | | | 21 | | | 10 | | | (2 | ) |
Taxes other than income | | | 4 | | | 2 | | | 4 | | | 2 | | | (2 | ) |
Other | | | 46 | | | 44 | | | 35 | | | 2 | | | 9 | |
Total operating expenses before allocations | | | 159 | | | 145 | | | 142 | | | 14 | | | 3 | |
Allocation to operating segments | | | (147 | ) | | (139 | ) | | (134 | ) | | (8 | ) | | (5 | ) |
Operating expenses | | | 12 | | | 6 | | | 8 | | | 6 | | | (2 | ) |
Loss on asset disposed of Caroline Street campus | | | - | | | (5 | ) | | - | | | 5 | | | (5 | ) |
Operating loss | | | (12 | ) | | (11 | ) | | (8 | ) | | (1 | ) | | (3 | ) |
Other losses | | | (4 | ) | | (1 | ) | | (3 | ) | | (3 | ) | | 2 | |
EBIT | | | ($16 | ) | | ($12 | ) | | ($11 | ) | | ($4 | ) | | ($1 | ) |
Outside services expenses increased primarily due to higher costs associated with process improvement projects in the information technology, finance and human resources areas.
Benefits and incentives increased primarily as a result of higher payroll-related expenses. In addition, severance expenses increased as a result of the AGSC restructuring and process improvement initiatives.
2004 compared to 2003 The decrease in EBIT of $4 million or 33% for the year ended December 31, 2004 as compared to the same period last yearin 2003 primarily was due to an increase in operating expenses of $6 million. The increase in operating expenses was primarily fromdue to increased outside services costs associated with software maintenance,maintenance; licensing and implementation of our work management system project,project; higher costs due to our SOX 404 compliance efforts,efforts; merger and acquisition related expensesacquisition-related expenses; and expenses related to Pivotal Development’s activities in 2004. The increase in operating expenses was offset by a loss of $5 million on the sale of our Caroline Street campus in 2003.
2003 compared to 2002The decrease in EBIT of $1 million or 9% for 2003 compared to 2002 was primarily the result of a loss of $5 million on the sale of our Caroline Street campus. The decrease was offset by decreased operating expenses of $2 million for 2003 as compared to 2002.
The $2 million decrease in operating expenses was due to charges incurred in 2002 that were not incurred in 2003. In 2002, we recorded $6 million for the termination of an automated meter reading contract, $2 million for the write-off of capital costs related to a terminated risk management software implementation project and $2 million in employee severance costs. These decreases in operating expenses were offset by an $8 million increase in operating expenses consisting primarily of higher payroll due to the transfer of call center employees to AGL Services from distribution operations, and the increase in facility lease expense as a result of our headquarters move in 2003.
WeTo meet our capital and liquidity requirements we rely on operating cash flow; short-term borrowings under our commercial paper program, which is backed by our supporting credit agreement (Credit Facility); borrowings under Sequent’s and SouthStar’s lines of credit; and borrowings or stock issuances in the long-term capital marketsmarkets. Our issuance of various securities, including long-term and short-term debt, is subject to meetcustomary approval or authorization by state and federal regulatory bodies including state public service commissions and, through February 8, 2006, the SEC. Furthermore, a substantial portion of our capitalconsolidated assets, earnings and liquidity requirements. cash flow is derived from the operation of our regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. The availability of borrowings under our Credit Facility is limited and subject to a total-debt-to-capital ratio financial covenant specified within the Credit Facility, which we currently meet.
We believe these sources will be sufficient for our working capital needs, including the potentially significant volatility of working capital requirements of our wholesale services business, debt service obligations and scheduled capital expenditures for the foreseeable future. The relatively stable operating cash flows of our distribution operations businessbusinesses currently providecontribute most of our cash flow from operations, and we anticipate this to continue in the future. However, we have historically had a
We will continue to evaluate our need to increase our available liquidity based on our view of working capital deficit, primarily as a resultrequirements, including the impact of our borrowings of short-term debt to financechanges in natural gas prices, liquidity requirements established by the purchase of long-term assets, principally property, plantrating agencies and equipment, and we expect this to continue in the future. Ourother factors. Additionally, our liquidity and capital resource requirements may change in the future due to a number of other factors, some of which we cannot control. These factors include
· | the seasonal nature of the natural gas business and our resulting short-term borrowing requirements, which typically peak during colder months |
· | increased gas supplies required to meet our customers’ needs during cold weather |
· | changes in wholesale prices and customer demand for our products and services |
· | regulatory changes and changes in rate-makingratemaking policies of regulatory commissions |
· | contractual cash obligations and other commercial commitments |
· | pension and postretirement benefit funding requirements |
· | changes in income tax laws |
· | margin requirements resulting from significant increases or decreases in our commodity prices |
Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies, including state public service commissions and the SEC. Furthermore, a substantial portion of our consolidated assets, earnings and cash flow is derived from the operation of regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. On April 1, 2004, we received approval from the SEC, under the PUHCA, for the renewal of our financing authority to issue securities through April 2007. Our total cash and available liquidity under our Credit Facility at December 31, 2004 and 2003 is represented in the table below:
In millions | | Dec. 31, 2004 | | Dec. 31, 2003 | |
Unused availability under the Credit Facility | | $ | 750 | | $ | 500 | |
Cash and cash equivalents | | | 49 | | | 17 | |
Total cash and available liquidity under the Credit Facility | | $ | 799 | | $ | 517 | |
The increase in total cash and available liquidity under our Credit Facility of $282 million is due primarily to the amendment to our Credit Facility in September 2004 that, among other things, increased the facility size by $250 million, and additional cash from operations at December 31, 2004.· | the impact of natural disasters, including weather |
Contractual obligationsObligations and commitmentsCommitments We have incurred various contractual obligations and financial commitments in the normal course of our operationsoperating and financing activities. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.
We calculate any expectedrequired pension contributions using an actuarial method called the projected unit credit cost method. Under this method, and as a result of our calculations, we expectwere not required to make a $1 millionany pension contribution in 2005.The2005, but we voluntarily made a $5 million contribution in August 2005. The following table below illustrates our expected future contractual obligations:obligations as of December 31, 2005.
| | | | Payments Due Before December 31, | |
| | | | | | 2006 | | 2008 | | 2010 | |
| | | | | | & | | & | | & | |
In millions | | Total | | 2005 | | 2007 | | 2009 | | Thereafter | |
Long-term debt(1) (2) | | $ | 1,623 | | $ | - | | $ | 2 | | $ | 2 | | $ | 1,619 | |
Pipeline charges, storage capacity and gas supply(3) (4) | | | 1,051 | | | 258 | | | 262 | | | 179 | | | 352 | |
Short-term debt (2) | | | 334 | | | 334 | | | - | | | - | | | - | |
PRP costs(5) | | | 327 | | | 85 | | | 162 | | | 80 | | | - | |
Operating leases (6) | | | 170 | | | 27 | | | 39 | | | 29 | | | 75 | |
ERC(5) | | | 90 | | | 27 | | | 10 | | | 12 | | | 41 | |
Commodity and transportation charges | | | 20 | | | 19 | | | 1 | | | - | | | - | |
Total | | $ | 3,615 | | $ | 750 | | $ | 476 | | $ | 302 | | $ | 2,087 | |
(1) | Includes $232 million of Notes Payable to Trusts redeemable in 2006 and 2007. |
(2) | Does not include the interest expense associated with the long-term and short-term debt. |
(3) | Charges recoverable through a PGA mechanism or alternatively billed to Marketers. Also includes demand charges associated with Sequent. |
(4) | A subsidiary of NUI entered into two 20-year agreements for the firm transportation and storage of natural gas during 2003 with the annual demand charges aggregate of approximately $5 million. As a result of our acquisition of NUI and in accordance with SFAS 141, the contracts were valued at fair value. The $38 million currently allocated to accrued pipeline demand dharges on our consolidated balance sheets represent our estimate of the fair value of the acquired contracts. The liability will be amortized over the remaining life of the contracts. |
(5) | Charges recoverable through rate rider mechanisms. |
| | | | Payments due before December 31, |
| | | | | | 2007 | | 2009 | | 2011 | |
| | | | | | & | | & | | & | |
In millions | | Total | | 2006 | | 2008 | | 2010 | | thereafter | |
Interest charges on outstanding debt (1) | | $ | 1,870 | | $ | 103 | | $ | 201 | | $ | 200 | | $ | 1,366 | |
Pipeline charges, storage capacity and gas supply (2) (3) | | | 1,766 | | | 285 | | | 515 | | | 411 | | | 555 | |
Long-term debt (4) | | | 1,615 | | | - | | | 2 | | | 2 | | | 1,611 | |
Short-term debt | | | 522 | | | 522 | | | - | | | - | | | - | |
PRP costs (5) | | | 265 | | | 30 | | | 72 | | | 95 | | | 68 | |
Operating leases (6) | | | 160 | | | 27 | | | 44 | | | 33 | | | 56 | |
Commodity and transportation charges | | | 129 | | | 30 | | | 19 | | | 14 | | | 66 | |
Environmental remediation costs (5) | | | 97 | | | 13 | | | 27 | | | 53 | | | 4 | |
Total | | $ | 6,424 | | $ | 1,010 | | $ | 880 | | $ | 808 | | $ | 3,726 | |
(1) Floating rate debt is based on the interest rate as of December 31, 2005 and the maturity of the underlying debt instrument. (2) Charges recoverable through a PGA mechanism or alternatively billed to Marketers. Also includes demand charges associated with Sequent. (3) A subsidiary of NUI entered into two 20-year agreements for the firm transportation and storage of natural gas during 2003 with annual aggregate demand charges of approximately $5 million. As a result of our acquisition of NUI and in accordance with SFAS No. 141, “Business Combinations, “ we valued the contracts at fair value. The $38 million allocated to accrued pipeline demand charges in our consolidated balance sheets as of December 31, 2005 represents our estimate of the fair value of the acquired contracts. The liability will be amortized over the remaining lives of the contracts. (4) Includes $232 million of notes payable to trusts redeemable in 2006 and 2007. (5) Includes charges recoverable through rate rider mechanisms. (6) We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with SFAS No. 13, “Accounting for Leases.” However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein. |
(6) | We have certain operating leases with provisions for step rent or escalation payments, or certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms in accordance with SFAS No. 13, “Accounting for Leases.” However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein. |
SouthStar has natural gas purchase commitments related to the supply of minimum natural gas volumes to its customers. These commitments are priced on an index plus premium basis. At December 31, 2004,2005, SouthStar had obligations under these arrangements for 11.28 Bcf for the year ending December 31, 2005.2006. This obligation is not included in the above table. SouthStar also had capacity commitments related to the purchase of transportation rights on interstate pipelines.
We also have incurred various financial commitments in the normal course of business. Contingent financial commitments represent obligations that become payable only if certain predefined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. The following table illustrates our expected contingent financial commitments as of December 31, 2004:2005.
| | | | Commitments Due Before December 31, | |
| | | | | | 2006 | | 2008 | | 2010 | |
| | | | | | & | | & | | & | |
In millions | | Total | | 2005 | | 2007 | | 2009 | | Thereafter | |
Guarantees(1) | | $ | 7 | | $ | 7 | | $ | - | | $ | - | | $ | - | |
Standby letters of credit and performance / surety bonds | | | 12 | | | 12 | | | - | | | - | | | - | |
Total | | $ | 19 | | $ | 19 | | $ | - | | $ | - | | $ | - | |
(1) We provide a guarantee on behalf of our affiliate, SouthStar. We guarantee 70% of SouthStar’s obligations to Southern Natural under certain agreements between the parties up to a maximum of $7 million if SouthStar fails to make payment to Southern Natural. We have certain guarantees that are recorded on our consolidated balance sheet that would not cause any additional impact on our financial statements beyond what was already recorded. |
| | | | Commitments due before Dec. 31, | |
| | | |
In millions | | Total | | 2006 | | 2007 & thereafter | |
Standby letters of credit, performance / surety bonds | | $ | 21 | | $ | 21 | | $ | - | |
Cash flowFlow from operating activitiesOperating Activities OurWe prepare our statement of cash flows is prepared using the indirect method. Under this method, we reconcile net income is reconciled to cash flows from operating activities by adjusting net income for those items that impact net income but do not result in actual cash receipts or payments during the period. These reconciling items include depreciation, undistributed earnings from equity investments, changes in deferred income taxes, gains or losses on the sale of assets and changes in the consolidated balance sheet for working capital from the beginning to the end of the period.
Year-over-year changes in our operating cash flows are attributable primarily to working capital changes within our distribution operations, wholesale services and retail energy operations segments resulting from the impact of weather, the price of natural gas, the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.
We generate a large portion of our annual net income and subsequent increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas delivered by distribution operations and SouthStar to our customers during the peak heating season. In addition, our natural gas inventories, which usually peak on November 1, are largely drawn down in the heating season and provide a source of cash as this asset is used to satisfy winter sales demand.
During this period, our accounts payable increases to reflect payments due to providers of the natural gas commodity and pipeline capacity. The value of the natural gas commodity can vary significantly from one period to the next as a result of the volatility in the price of natural gas. Our natural gas costs and deferred purchased natural gas costs due from or to our customers represent the difference between natural gas costs that we have been paid to suppliers in the past and what has beenamounts that we have collected from customers. These natural gas costs can cause significant variations in cash flows from period to period.
In 2005, our net cash flow provided from operating activities was $78 million, a decrease of $209 million or 73% from the same period last year. The decrease was primarily a result of increased working capital requirements including increased spending of $183 million for seasonal inventory injections in advance of the winter sales demand. We spent more on these injections in 2005 primarily because of higher natural gas prices due to the effects of the hurricanes in the Gulf Coast region and of the full year impact associated with the purchase of natural gas for the utilities acquired in November 2004 from NUI, principally for Elizabethtown Gas. These higher natural gas prices resulted in a 45% increase in the average cost of our natural gas inventories.
Our operating cash flow of $287 million for the year ended December 31, 2004 included SouthStar’s operating cash flow of approximately $79 million as a result of our consolidation of SouthStar effective January 1, 2004. In 2003 and 2002, our operating cash flow only included amounts for cash distributions from SouthStar, consistent with the equity method of accounting. Excluding SouthStar, our cash flow from operations for the year ended December 31, 2004 was $208 million, an increase of $86 million from 2003. Year-to-year changes in our operating cash flow, excluding SouthStar, were primarily the result of increased earnings of $25 million and decreased spending for injection and purchase of natural gas inventories of $63 million.
Our cash flow from operations in 2003 was $122 million, a decrease of $164 million from 2002. This decrease was primarily the result of increased spending for injection of natural gas inventories of approximately 11 Bcf. The weighted average cost of this inventory increased approximately 30% compared to 2002. In addition, we made approximately $22 million in pension contributions in 2003 as a result of our continued efforts to fully fund our pension liability. This was offset by increased net income of $25 million and cash distributions received from SouthStar of $40 million.
Cash flowFlow from investing activitiesInvesting Activities Our cash used in investing activities in 2004 consisted primarily of property, plant and equipment (PP&E) expenditures in 2005, 2004 and 2003 and our acquisitionacquisitions of NUI for $116 million and Pivotal Jefferson Island for $90 million. For more information on our acquisitions of NUI and Jefferson Island, see Note 2.million in 2004. In 2003, our investing activities included our cash payment of $20 million for the purchase of Dynegy’sDynegy Inc.’s 20% interest in SouthStar. In 2002, we received $27 million in cash from SouthStar and US Propane. The following table provides additional information on our actual and estimated PP&E expenditures:expenditures.
In millions | | 2005 (1) | | 2004 | | 2003 | | 2002 | | 2004 vs. 2003 | | 2003 vs. 2002 | |
Construction of distribution facilities | | $ | 87 | | $ | 64 | | $ | 60 | | $ | 62 | | $ | 4 | | | ($2 | ) |
Pipeline replacement program | | | 85 | | | 95 | | | 45 | | | 48 | | | 50 | | | (3 | ) |
Pivotal propane plant | | | 2 | | | 29 | | | - | | | - | | | 29 | | | - | |
Telecommunications | | | 5 | | | 5 | | | 8 | | | 28 | | | (3 | ) | | (20 | ) |
Other | | | 97 | | | 71 | | | 45 | | | 49 | | | 26 | | | (4 | ) |
Total PP&E expenditures | | $ | 276 | | $ | 264 | | $ | 158 | | $ | 187 | | $ | 106 | | | ($29 | ) |
In millions | | 2006 (1) | | 2005 | | 2004 | | 2003 | |
Construction or preservation of distribution facilities | | $ | 110 | | $ | 135 | | $ | 64 | | $ | 60 | |
SNG pipeline | | | - | | | 32 | | | - | | | - | |
PRP | | | 30 | | | 48 | | | 95 | | | 45 | |
Pivotal Propane plant | | | - | | | - | | | 29 | | | - | |
Pivotal Jefferson Island | | | 36 | | | 8 | | | 2 | | | - | |
Telecommunications | | | 3 | | | 1 | | | 5 | | | 8 | |
Other (2) | | | 54 | | | 43 | | | 69 | | | 45 | |
Total | | $ | 233 | | $ | 267 | | $ | 264 | | $ | 158 | |
(2) | Includes corporate information technology systems and infrastructure expenditures. |
The increase of $3 million or 1% in PP&E expenditures for 2005 compared to 2004 was primarily due to the $32 million acquisition of a 250-mile pipeline in Georgia from SNG and increased expenditures of $71 million for the construction of distribution facilities, including $27 million at Elizabethtown Gas and Florida City Gas, both of which were acquired in November 2004. Also contributing to the increase was $6 million of additional expenditures at Pivotal Jefferson Island which completed a capital project to improve its compression capabilities. These increases were offset by reduced PRP expenditures of $47 million due to the Settlement Agreement between Atlanta Gas Light and the Georgia Commission that extended the program to 2013, reduced expenditures of $29 million at the Pivotal Propane plant in Virginia as most of its construction expenditures were incurred last year and reduced expenditures of $7 million at Sequent as its ETRM system was implemented in 2004.
Approximately 18% of our PP&E expenditures in 2005 included costs for the PRP, which are approved by the Georgia Commission. In the near term, the primary financial impact to us from the PRP is reduced cash flow from operating and investing activities, as the timing related to cost recovery through Atlanta Gas Light’s base rates which include an allowed rate of return on its PRP capital expenditures does not match the timing related to costs incurred.
We expect our future PRP expenditures will primarily include larger-diameter pipe than in prior years, the majority of which is located in more densely populated areas. The following table provides more information on our expected PRP expenditures.
Year | | Miles of Pipe to be Replaced | | Expenditures (in millions) | |
2006 | | | 95 | | $ | 30 | |
2007 | | | 107 | | | 35 | |
2008 | | | 150 | | | 37 | |
2009 | | | 154 | | | 45 | |
2010-2013 | | | 333 | | | 118 | |
Totals | | | 839 | | $ | 265 | |
The increase of $106 million or 67% in PP&E expenditures for 2004 compared to 2003 was primarily due to increased PRP expenditures of $50 million and our construction of the Virginia propane plant by Pivotal Propane offor $29 million. In addition,Also contributing to the increase was due towere $9 million of expenditures for the construction of the Macon peaking pipeline, $7 million for the ETRM system at Sequent, $3$2 million at Pivotal Jefferson Island and $3 million at SouthStar.
The decrease of $29 million or 15% in PP&E expenditures for 2003 compared to 2002 was primarily due to lower telecommunications expenditures of $21 million as a result of the completion of the metro Atlanta fiber network in 2002, and a decrease in construction of distribution facilities of $8 million associated with distribution operations.
For 2005, we estimate that our total PP&E expenditures will increase as a result of expenditures for the construction of distribution facilities of $23 million and acquisition and enhancement of the Southern Natural interstate pipeline for $38 million. Our expected increase in the construction of distribution facilities is primarily due to increased expenditures for renewals and the acquired NUI utilities.
Our PRP costs are expected to remain at current levels of spending, through the expected end of the program in 2008, primarily as a result of the replacement of larger-diameter pipe than in prior years, the majority of which is located in more densely populated areas. The PRP recoveries are recorded as revenues and are based on a formula that allows us to recover operation and maintenance costs in excess of those included in Atlanta Gas Light’s base rates, depreciation expense and an allowed rate of return on capital expenditures. In the near term, the primary financial impact to usCash Flow from the PRP is reduced cash flow from operating and investing activities, as the timing related to cost recovery does not match the timing of when costs are incurred. As discussed earlier, Atlanta Gas Light’s current rate case includes testimony on whether the PRP should be included in its base rates or whether the rider currently used for recovery of PRP expenses should be otherwise modified or discontinued.
Cash flow from financing activitiesFinancing Activities Our financing activities are primarily composed of borrowings and payments of short-term debt, payments of Medium-Termmedium-term notes, borrowings of senior notes, distributions to minority interests, cash dividends on our common stock and the issuance of common stock. Our capitalization and financing strategy is intended to ensure that we are properly capitalized with the appropriate mix of equity and debt securities. This strategy includes active management by us of the percentage of total debt relative to our total capitalization, as well as the term and interest rate profile of our debt securities.
We also work to maintain or improve our credit ratings on our senior notesdebt to effectively manage our existing financing costs and enhance our ability to raise additional capital on favorable terms. Factors we consider important in assessing our credit ratings include:include our balance sheet leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any trigger events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that would require us to issue equity based on credit ratings or other trigger events. As of February 2005,2006, our senior unsecured debt ratings are BBB+ from Standard & Poor’s RatingRatings Services (S&P), Baa1 from Moody’s InvestorInvestors Service (Moody’s) and A- from Fitch Ratings (Fitch).
DuringIn July 2004 no fundamental adverse shift occurred in our ratings profile; however, upon the announcement of our proposed acquisition of NUI, S&P placed our credit ratings on CreditWatch with negative implications, Moody’s affirmed our ratings but changed its rating outlook to negative from stable, and Fitch placed our credit ratings on Rating Watch Negative. Since the closing of the acquisition on November 30, 2004, S&P removed us from CreditWatch and changed our outlook to negative; Fitch took us off Rating Watch Negative and affirmed our ratings with a stable outlook; and Moody’s affirmedchanged our ratings and kept the negative outlook.outlook to stable. S&P and Moody’s havehas indicated that the negative outlook is the result of the execution risks in integrating the NUI acquisition.
Our credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. We cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. If the rating agencies downgrade our ratings, particularly below investment grade, it may significantly limit our access to the commercial paper market and our borrowing costs would increase. In addition, we would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources would decrease.
Our debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. Our most important default events include maintaining covenants with respect to maximum leverage ratio, minimum net worth, insolvency events, nonpayment of scheduled principal or interest payments, and acceleration of other financial obligations and change of control provisions. Our Credit Facility’s financial covenants and our PUHCA financing authority requirecovenant requires us to maintain a ratio of total debt-to-totaldebt to total capitalization of no greater than 70%;however, our goal is to maintain this ratio at levels between 50% and 60% of debt-to-total-capitalization.debt to total capitalization. We are currently in compliance with all existing debt provisions and covenants.
For more information on our debt, see Note 9.
We believe that accomplishing these capitalization objectives and maintaining sufficient cash flow are necessary to maintain our investment-grade credit ratings and to allow us access to capital at reasonable costs. The components of our capital structure, as of the dates indicated, are summarized in the following table:tables.
Dollars in millions | | Dec. 31, 2004 | | Dec. 31, 2003 | | | Dec. 31, 2005 | |
Short-term debt | | $ | 334 | | | 10 | % | $ | 383 | | | 16 | % | | $ | 522 | | | 14 | % |
Long-term debt (1) | | | 1,623 | | | 48 | | | 956 | | | 42 | | | | 1,615 | | | 45 | |
Total debt | | | 1,957 | | | 58 | | | 1,339 | | | 58 | | | | 2,137 | | | 59 | |
Minority interest | | | 36 | | | 1 | | | - | | | - | | |
Common shareholders’ equity | | | 1,385 | | | 41 | | | 945 | | | 42 | | | | 1,499 | | | 41 | |
Total capitalization | | $ | 3,378 | | | 100 | % | $ | 2,285 | | | 100 | % | | $ | 3,636 | | | 100 | % |
Dollars in millions | | Dec. 31, 2004 | |
Short-term debt | | $ | 334 | | | 10 | % |
Long-term debt (1) | | | 1,623 | | | 49 | |
Total debt | | | 1,957 | | | 59 | |
Common shareholders’ equity | | | 1,385 | | | 41 | |
Total capitalization | | $ | 3,342 | | | 100 | % |
(1) | Net of interest rate swaps. |
Short-term debt Our short-term debt is composed of borrowings under our commercial paper program, Sequent’s lines of credit, SouthStar’s line of credit and SouthStar’s linethe current portion of credit.our capital leases. Our short-term debt financing generally increases between June and December because our payments for natural gas and pipeline capacity are generally made to suppliers prior to the collection of accounts receivable from our customers. In addition, weWe typically reduce short-term debt balances in the spring because a significant portion of our current assets are converted into cash at the end of the winter heating season.
In 2004, our $480 million of net short-term debt payments included the repayment of $500 million outstanding under NUI’s credit facilities. Upon the repayment of the outstanding amounts, we terminated NUI’s credit facilities.
Our commercial paper program is supported by our Credit Facility which was amended on September 30, 2004.in August 2005. Under the terms of the amendment, the term of the Credit Facility was extended from May 26, 2007 to September 30, 2009.August 31, 2010. The aggregate principal amount available under the amended Credit Facility was increased from $500to $850 million, to $750 million, and ourwith an option to increase the aggregate cumulative principal amount available for borrowing to $1.1 billion on not more than one occasionthree occasions during each calendar year wasyear. The increased from $200 millioncapacity under our Credit Facility increases our ability to $250 million. borrow under our commercial paper program. Our total cash and available liquidity under our Credit Facility as of the dates indicated are represented in the table below.
In millions | | Dec. 31, 2005 | | Dec. 31, 2004 | |
Unused availability under the Credit Facility | | $ | 850 | | $ | 750 | |
Cash and cash equivalents | | | 30 | | | 49 | |
Total cash and available liquidity under the Credit Facility | | $ | 880 | | $ | 799 | |
As of December 31, 20042005 and 2003,2004, we had no outstanding borrowings under the Credit Facility. However, the availability of borrowings and unused availability under our Credit Facility is limited and subject to conditions specified within the Credit Facility, which we currently meet. These conditions include
· | compliance with certain financial covenantsmaintain a ratio of total debt to total capitalization of no greater than 70% |
· | the continued accuracy of representations and warranties contained in the agreement |
Sequent uses itsIn June 2005, Sequent’s existing $25 million unsecured line of credit was extended to July 2006. In September 2005, Sequent entered into an agreement for an additional $20 million unsecured line of credit scheduled to expire in September 2006. These unsecured lines of credit, which total $45 million, are used solely for the posting of margin deposits for NYMEX transactions, and itare unconditionally guaranteed by us. At December 31, 2005, there were no outstanding amounts under these lines of credit, which is an $18 million decrease from the same time in 2004.
In September 2005, Pivotal Utility Holdings, Inc entered into an agreement for a $20 million unsecured line of credit to be used solely for the posting of margin deposits for Elizabethtown Gas’ natural gas hedging program. The line expires in September 2006 and is unconditionally guaranteed by us. ThisThere were no amounts outstanding under this line of credit expires on July 1, 2005 and bears interest at the federal funds effective rate plus 0.5%. At December 31, 2004, the line of credit had an outstanding balance of $18 million.2005.
SouthStar’s $75 million line of credit provides the additional working capital needed to meet seasonal demands and is not guaranteed by us. TheThis line of credit is secured by various percentages of its accounts receivable, unbilled revenue and inventory. The line of credit expires in April 2007 and bears interest at the prime rate and/or LIBOR plus a margin based on certain financial measures.Atmeasures. At December 31, 2004, there2005, the line of credit had an outstanding balance of $36 million. There were no amounts outstanding under this facility;facility at the interest rate would have been 5.25% based on the prime rate.same time in 2004.
In 2004, we repaid $500 million outstanding under NUI’s credit facility. Upon the repayment of the outstanding amounts, we terminated NUI’s credit facility.
Long-term debtDebt In 2004, AGL Capital issued $250 million of 6% senior notes dueSenior Notes Due October 2034 and $200 million of 4.95% senior notes dueSenior Notes Due January 2015. We fully and unconditionally guarantee the senior notes. The proceeds from the issuance were used to refinance a portion of our outstanding short-term debt under our commercial paper program.
During 2004, we also made $82 million in Medium-Termmedium-term note payments using proceeds from the borrowings under our commercial paper program. Additionally, NUI Utilities, Inc., a wholly owned subsidiary of NUI had outstanding at closing $199 million of indebtedness pursuant to gas facility revenue bonds and $10 million in capital leases, of which $2 million is reflected as current. For more information on our long-term debt, including the debt assumed fromin the NUI acquisition, see Note 8.
In 2003, we issued $225 million of 4.45% senior notes due July 2013 and used the net proceeds to repay approximately $204 million of our Medium-Term notes and approximately $21 million of short-term debt. In 2002, we made $93 million in scheduled Medium-Term note payments using a combination of cash from operations and proceeds from our commercial paper program.
Interest rate swapsRate Swaps To maintain an effective capital structure, it is our policy to borrow funds using a mix of fixed-rate debt and variable-rate debt. We have entered into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our fixed-rate and variable-rate debt obligation. At December 31, 2004,2005, including the effects of $175$100 million of interest rate swaps, 72%66% of our total short-term and long-term debt was fixed.
Refinancing of Gas Facility Revenue Bonds In April and May 2005, we refinanced $67 million of our gas facility revenue bonds. For more information, see Note 9.
Minority interestInterest As a result of our consolidation of SouthStar’s accounts effective January 1, 2004, we recorded Piedmont’s portion of SouthStar’s contributed capital as a minority interest onin our consolidated balance sheetsheets and included it as a component of our total capitalization. We also recorded aA cash distribution of $19 million in 2005 and $14 million in 2004 for SouthStar’s dividend distributiondistributions to Piedmont were recorded in our consolidated statement of cash flows as a financing activity.
Common stockStock In November 2004, we completed our public offering of 11.04 million shares of common stock, generating net proceeds of approximately $332 million. We used the proceeds to purchase the outstanding capital stock of NUI and to repay short-term debt incurred to fund our purchase of Jefferson Island.
In February 2003, we completed our public offering of 6.4 million shares of common stock. The offering generated net proceeds of approximately $137 million, which we used to repay outstanding short-term debt and for general corporate purposes.
Dividends on common stockCommon Stock In February 2005, we announced a 7% increasemade $100 million in our common stock dividend raisingpayments. This was an increase of $25 million or 33% from 2004. The increase was due to our 11 million share common stock offering in November 2004, which increased the number of shares outstanding, and the increases in the amount of our quarterly dividend from $0.29 per share to $0.31 per share, which indicates an annual dividend of $1.24common stock dividends per share. The new quarterly dividend will be paid March 1, 2005, to shareholders of record as of the close of business February 18, 2005.
In April 2004, we announced a 4% increasemade $75 million in our common stock dividend raisingpayments. This was an increase of $5 million or 7% from 2003. The increase was due to our 6.4 million common stock offering in February 2003, which increased the number of shares outstanding, and the increases in the amount of our quarterly dividend from $0.28 per share to $0.29 per share, which indicated an annual dividend of $1.16common stock dividends per share.
In April 2003,the last three fiscal years, we have made the following increases in dividends on our common stock dividend was increased by 4% increase from $0.27 per share to $0.28 per share, which indicated an annual dividend of $1.12 per share.stock. For information on theabout restrictions ofon our ability to pay dividends on our common stock, see Note 9.
Date of change | | % increase | | Quarterly dividend | | Indicated annual dividend | |
Nov 2005 | | | 19 | % | $ | 0.37 | | $ | 1.48 | |
Feb 2005 | | | 7 | | | 0.31 | | | 1.24 | |
Apr 2004 | | | 4 | | | 0.29 | | | 1.16 | |
Apr 2003 | | | 4 | | | 0.28 | | | 1.12 | |
Shelf registrationRegistration In October 2004, we filed a new shelf registration statement with the SEC for authority to increase our aggregate capacity to $1.5 billion of various capital securities. The shelf registration statement was declared effective in November 2004. We currently have remaining capacity under thatan October 2004 shelf registration statement of approximately $957 million. We may seek additional financing through debt or equity offerings in the private or public markets at any time.
The preparation of our financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Wecircumstances, and we evaluate our estimates on an ongoing basis, and ourbasis. Our actual results may differ from theseour estimates. Each of the following critical accounting policies involves complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements.
Regulatory Accounting
We account for transactions within our distribution operations segment according to the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). Applying this accounting policy allows us to defer expenses and income in the consolidated balance sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratesetting process in a period different from the period in which they would have been reflected in the statements of consolidated income of an unregulated company. We then recognize these deferred regulatory assets and liabilities in our statements of consolidated income in the period in which we reflect the same amounts in rates.
If any portion of distribution operations ceased to continue to meet the criteria for application of regulatory accounting treatment for all or part of its operations, we would eliminate the regulatory assets and liabilities related to those portions ceasing to meet such criteria from our consolidated balance sheets and include them in our statements of consolidated income for the period in which the discontinuance of regulatory accounting treatment occurred.
Pipeline Replacement Program (PRP)
Atlanta Gas Light was ordered by the Georgia Commission (through a joint stipulation between Atlanta Gas Light and the Commission staff) to undertake a PRP which willthat would replace all bare steel and cast iron pipe in its system in the state of Georgia within a 10-year period beginning October 1, 1998. Atlanta Gas Light initially identified, and provided notice to the Georgia Commission in accordance with this order,stipulation, 2,312 miles of bare steel and cast iron pipe to be replaced. Atlanta Gas Light hashad subsequently identified an additional 188320 miles of pipe subject to replacement under this program.
On June 10, 2005, the Georgia Commission approved a Settlement Agreement with Atlanta Gas Light that, among other things, extends Atlanta Gas Light’s PRP by five years to require that all replacements be completed by December 2013. The timing of replacements was subsequently specified in an amendment to the PRP stipulation. This amendment, which was approved by the Georgia Commission on December 20, 2005, requires Atlanta Gas Light to replace all cast iron pipe and 70% of all bare steel pipe by December 2010. The remaining 30% of bare steel pipe is required to be replaced by December 2013. Approximately 152 miles of cast iron and 687 miles of bare steel pipe still require replacement. The amendment also requires an evaluation by Atlanta Gas Light and the Georgia Commission staff of 22 miles of 24-inch pipe in Atlanta by December 2010 to determine if such pipe requires replacement. If replacement of this pipe is required, the pipe must be replaced by December 2013. The additional cost to replace this pipe is projected to be approximately $37 million.If Atlanta Gas Light does not perform in accordance with this order,the initial and amended PRP stipulation, it can be assessed certain nonperformance penalties. However, to date, Atlanta Gas Light is in full compliance.
The orderstipulation also provides for recovery of all prudent costs incurred in the performance of the program, which Atlanta Gas Light has recorded as a regulatory asset. The regulatory asset has two components:
· | the costs incurred to date that have not yet been recovered through rate riders |
· | the future expected costs to be recovered through rate riders |
The determination of future expected costs involves judgment. Factors that must be considered in estimating the future expected costs are projected capital expenditure spending and remaining footage of infrastructure to be replaced for the remaining years of the program. Atlanta Gas Light recorded a long-term liability of $235 million as of December 31, 2005 and $242 million as of December 31, 2004, and $323 million as of December 31, 2003, which represented engineering estimates for remaining capital expenditure costs in the PRP. As of December 31, 2004,2005, Atlanta Gas Light had recorded a current liability of $85$30 million, representing expected PRP expenditures for the next 12 months. We report these estimates on an undiscounted basis. If the recorded liability for PRP had been higher or lower by $10 million, Atlanta Gas Light’s expected recovery would have changed by approximately $1 million.
The PRP is also an issue in the current Atlanta Gas Light rate proceeding. It is possible the Georgia Commission may alter the recovery method for the costs we incur or may disallow cost recovery while maintaining the requirement to replace the bare steel and cast iron pipe. Changes to the recovery of PRP costs could result in an impairment of our regulatory asset of $361 million at December 31, 2004, if costs are disallowed or if it is no longer probable that accrued costs would be recoverable from rate payers in the future.
Environmental Remediation Liabilities
Atlanta Gas Light historically reported estimates of future remediation costs based on probabilistic models of potential costs. We report these estimates on an undiscounted basis. As we continue to conduct the actual remediation and enter cleanup contracts, Atlanta Gas Light is increasingly able to provide conventional engineering estimates of the likely costs of many elements of its remediation program. These estimates contain various engineering uncertainties, and Atlanta Gas Light continuously attempts to refine and update these engineering estimates. In addition, Atlanta Gas Light continues to review technologies available for cleanup of its two largest sites, Savannah and Augusta, Georgia, which, if proven, could have the effect of further reducing its total future expenditures.
Our latest available estimate as of September 30, 2004December 31, 2005 for those elements of the remediation program with in-place contracts or engineering cost estimates is $36 million.$12 million for Atlanta Gas Light's sites in Georgia and Florida. This is a reduction of $30$24 million from the estimate as of September 30, 2003December 31, 2004 of projected engineering and in-place contracts, resulting from $50 million of program expenditures during the 12 months ended September 30, 2004. During this same 12-month period, Atlanta Gas Light realized increases in its future cost estimates totaling $20 million related to an increase in the contract value at Augusta, Georgia for treatment of two areas and additional deep excavation of contaminants; the addition of harbor sediment removal at St. Augustine; an increase at Savannah for the phase 2 excavation and a partially offsetting decrease in engineering and oversight costs; and an increase in program management costs due to legal matters, environmental regulatory activities and oversight costs for the extension of work at Savannah and Augusta.2005. For elements of the remediation program where Atlanta Gas Light still cannot perform engineering cost estimates, considerable variability remains in available estimates. The estimated remaining cost of future actions at these sites is $14$15 million.
Atlanta Gas Light estimates certain other costs paid directly by it pays related to administering the remediation program and remediation of sites currently in the investigation phase. Through January 2006,2007, Atlanta Gas Light estimates the administration costs to be $2$4 million. Beyond January 2006,2007, these costs are not estimable. For those sites currently in the investigation phase our estimate is $9 million, which is based on preliminary data received during 2004 with respect to the existence of contamination of those sites. Our range of estimates for these sites is from $4 million to $15 million. We have accrued the midpoint of our range, or $9 million, as this is our best estimate at this phase of the remediation process.
Atlanta Gas Light’s environmental remediation liability is included in its corresponding regulatory asset. As of December 31, 2004,2005, the regulatory asset was $166$133 million, which is a combination of the accrued remediation liability and unrecovered cash expenditures. Atlanta Gas Light’s estimate does not include other potential expenses, such as unasserted property damage, personal injury or natural resource damage claims, unbudgeted legal expenses, or other costs for which it may be held liable but with respect to which the amount cannot be reasonably forecast. Atlanta Gas Light’s estimate also does not include any potential cost savings fromrecovery of environmental remediation costs is subject to review by the new cleanup technologies referenced above.Georgia Commission which may seek to disallow the recovery of some expenses.
In New Jersey, Elizabethtown Gas is currently conducting remediation activities with oversight from the New Jersey Department of Environmental Protection. Although the actual total cost of future environmental investigation and remediation efforts cannot be estimated with precision, the range of reasonably probable costs is from $30$57 million to $116$104 million. As of December 31, 2004,2005, no value within this range is better than any other value, so we recorded a liability of $30$57 million.
The NJBPU has authorized Elizabethtown Gas’Gas to recover prudently incurred remediation costs for the New Jersey properties have been authorized by the NJBPU to be recoverable in rates through its Remediation Adjustment Clause.remediation adjustment clause. As a result, Elizabethtown Gas has recorded a regulatory asset of approximately $34$63 million, inclusive of interest, as of December 31, 2004,2005, reflecting the future recovery of both incurred costs and future remediation liabilities in the state of New Jersey. Elizabethtown Gas has also been successful in recovering a portion of remediation costs incurred in New Jersey from its insurance carriers and continues to pursue additional recovery. As of December 31, 2004,2005, the variation between the amounts of the environmental remediation cost liability recorded onin the consolidated balance sheet and the associated regulatory asset is due to expenditures for environmental investigation and remediation exceeding recoveries from ratepayers and insurance carriers.
We also own several former NUI remediation sites located outside of New Jersey. One site, in Elizabeth City, North Carolina, is subject to an order by the North Carolina Department of Energy and Natural Resources. We do not have precise estimates for the cost of investigating and remediating this site, although preliminary estimates for these costs range from $4$10 million to $16$17 million. As of December 31, 2004,2005, we have recorded a liability of $4$10 million related to this site. There is another site in North Carolina where investigation and remediation is probable, although no regulatory order exists and we do not believe costs associated with this site can be reasonably estimated. In addition, there are as many as six other sites with which NUI had some association, although no basis for liability has been asserted. We do not believe that costs to investigate and remediate these sites, if any, can be reasonably estimated at this time.
With respect to these costs, we currently pursue or intend to pursue recovery from ratepayers, former owners and operators and insurance carriers. Although we have been successful in recovering a portion of these remediation costs from our insurance carriers, we are not able to express a belief as to the success of additional recovery efforts. We are working with the regulatory agencies to prudently manage our remediation costs so as to mitigate the impact of such costs on both ratepayers and shareholders.
Revenue Recognition
Rate structures for Elizabethtown Gas, Virginia Natural Gas, Florida Gas and Chattanooga Gas include volumetric rate designs that allow recovery of costs through gas usage. These utilities recognize revenues from sales of natural gas and transportation services in the same period in which they deliver the related volumes to customers. These utilities also bill and recognize sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. In addition, they record revenues for estimated deliveries of gas, not yet billed to these customers, from the meter reading date to the end of the accounting period. We include these revenues in our consolidated balance sheets as unbilled revenue. Furthermore, included in the rates charged by Elizabethtown Gas, Virginia Natural Gas and Chattanooga Gas is a WNA factor, which offsets the impact of unusually cold or warm weather on operating margins.
Purchase Price Allocation
During 2004, we completed two significant acquisitions, Jefferson Island and NUI. We purchased Jefferson Island for an adjusted price of $90 million, which included approximately $9 million of working gas inventory. We purchased NUI for $225 million in cash plus the assumption of NUI’s outstanding net debt. At closing, NUI had $709 million in debt and approximately $109 million of cash on its balance sheet, bringing the net value of the transaction to approximately $825 million.
In accordance with SFAS No. 141, "Business Combinations" (SFAS 141), the purchase price of Jefferson Island and NUI should be allocated to the various assets and liabilities acquired at their estimated fair value. Estimating fair values can be complex and can require significant applications of judgment. It most commonly affects nonregulated property, plant and equipment, nonregulated assets and liabilities, and intangible assets, including those with indefinite lives. Our evaluation of NUI’s identifiable assets acquired and liabilities assumed is a preliminary valuation based on currently available information and is subject to final adjustments. The valuations are considered preliminary since they are based on limited information available to management and independent appraisers. Generally, we have, if necessary, up to one year from the acquisition date to finalize the purchase price allocation. Any changes in estimates used in the allocation of the purchase price that are made after the one-year-look back period would be recognized in earnings during the period in which the change in estimate is made.
We expect to record goodwill associated with the acquisitions of Jefferson Island and NUI that will be required to be tested for impairment at least annually in accordance with the requirements of SFAS 142. The goodwill associated with the acquisition of NUI is expected to be allocated to our distribution operations segment. Based on our annual assessment at December 31, 2004, no impairment of goodwill is indicated, and our calculation indicates that the estimated fair value of this segment exceeds the carrying value, including goodwill, by a significant amount. For more information on our methodology used to test goodwill for impairment, see Note 1.
Derivatives and Hedging Activities
SFAS 133, as updated by SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149), established accounting and reporting standards which require that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. However, if the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from the fair value accounting treatment of SFAS 133, as updated by SFAS 149, and is accounted for using traditional accrual accounting.
SFAS 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, SFAS 133 allows a derivative’s gains and losses to offset related results on the hedged item in the income statement in the case of a fair value hedge, or to record the gains and losses in other comprehensive income (OCI) until maturity in the case of a cash flow hedge. Additionally, SFAS 133 requires that a company formally designate a derivative as a hedge as well as document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting treatment. Two areas where SFAS 133 applies are interest rate swaps and gas commodity contracts at both Sequent and SouthStar. Our derivative and hedging activities are described in further detail in Note 4.
Interest rate swapsRate Swaps We designate our interest rate swaps as fair value hedges as defined by SFAS 133, which allows us to designate derivatives that hedge exposure to changes in the fair value of a recognized asset or liability. We record the gain or loss on fair value hedges in earnings in the period of change, together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The effect of this accounting is to reflect in earnings only that portion of the hedge that is not effective in achieving offsetting changes in fair value.
Commodity-related derivative instrumentsDerivative Instruments We are exposed to risks associated with changes in the market price of natural gas. Elizabethtown Gas utilizes certain derivatives for nontrading purposes to hedge the impact of market fluctuations on assets, liabilities and other contractual commitments. Pursuant to SFAS 133, such derivative products are marked-to-marketmarked to market each reporting period. Pursuant to regulatory requirements, realized gains and losses related to such derivatives are reflected in purchased gas costs and included in billings to customers. Unrealized gains and losses are reflected as a regulatory asset (loss) or liability (gain), as appropriate, onin the consolidated balance sheet. Through Sequent and SouthStar, we use derivative instruments to reduce our exposure to the risk of changes in the pricesprice of natural gas. Sequent recognizes the change in value of derivative instruments as an unrealized gain or loss in revenues in the period when the market value of the portfolio changes. This is primarily due to newly originated transactions and the effect of priceinstrument changes. Sequent recognizes cash inflows and outflows associated with the settlement of theseits risk management activities in operating cash flows, and reports these settlements as receivables and payables in the balance sheet separately from the risk management activities in the balance sheetreported as energy marketing receivables and trade payables.
Under our risk management policy, we attempt to mitigate substantially all our commodity price risk associated with Sequent’s natural gas storage gas portfolio and lockinlock in the economic margin at the time we enter into gas purchase transactions for our stored natural gas. We purchase natural gas for storage when the current market price we pay for gas plus the cost to store the gasstorage costs is less than the market price we could receive in the futurefuture. We lock in the economic margin by selling NYMEX futures contracts or other over-the-counter derivatives in the forward months resulting in a positive net profit margin.corresponding with our withdrawal periods. We use contracts to sell natural gas at that future price to substantially lockinlock-in the profit margin we will ultimately realize when the stored natural gas is actually sold. These contracts meet the definition of a derivative under SFAS 133.
The purchase, storage and sale of natural gas are accounted for differently from the derivatives we use to mitigate the commodity price risk associated with our storage portfolio. The difference in accounting can result in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated. We do not currently use hedge accounting under SFAS 133 to account for this activity.
GasNatural gas that we purchase and inject into storage is accounted for on an accrual basis, at the lower of average cost or market, classified as inventory in our consolidated balance sheets andsheets; it is no longer marked to market following our implementation of the accounting guidance in EITF 02-03. Under current accounting guidance, we would recognize a loss in any period when the market price for natural gas is lower than the carrying amount of our purchased natural gas inventory. Costs to store the natural gas are recognized in the period the costs are incurred. We recognize revenues and cost of natural gas sold in our statement of consolidated income in the period we sell gas and it is delivered out of the storage facility.
The derivatives we use to mitigate commodity price risk and substantially lock in the margin upon the sale of stored natural gas are accounted for at fair value and marked to market each period, with changes in fair value recognized as unrealized gains or losses in the period of change. This difference in accounting, the accrual basis for our gas storage inventory versus mark-to-market accounting for the derivatives used to mitigate commodity price risk, can result in volatility in our reported net income. Based on Sequent’s storage positions at December 31, 2004, a $0.10 forward NYMEX change would result in a $0.3 million impact to Sequent’s EBIT.
Over time, gains or losses on the sale of gas storage inventory will be offset by losses or gains on the derivatives, resulting in realization of the economic profit margin we expected when we entered into the transactions. This accounting difference causes Sequent’s earnings on its storage gas positions to be affected by natural gas price changes, even though the economic profits remain essentially unchanged. Sequent manages underground storage for our utilities and holds certain capacity rights on its own behalf. The underground storage is of two types:
· | reservoir storage, where supplies are generally injected and withdrawn on a seasonal basis |
· | salt dome high-deliverability storage, where supplies may be periodically injected and withdrawn on relatively short notice |
SouthStar also uses derivative instruments to manage exposures arising from changing commodity prices. SouthStar’s objective for holding these derivatives is to minimize this risk using the most effective methods to reduce or eliminate the impacts of these exposures.volatility in wholesale commodity natural gas prices. A significant portion of SouthStar’s derivative transactions are designated as cash flow hedges under SFAS 133. Derivative gains or losses arising from cash flow hedges are recorded in other comprehensive income (OCI)OCI and are reclassified into earnings in the same period as the settlement of the underlying hedged item.item is reflected in the income statement. As of December 31, 2005, the ending balance in OCI for derivative transactions designated as cash flow hedges under SFAS 133 was $(0.8) million. Any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not perfectly offset the losses or gains on the hedged item, is recorded into earnings in the period in which it occurs. SouthStar currently has minimal hedge ineffectiveness. SouthStar’s remaining derivative instruments doare not meet the hedge criteriadesignated as hedges under SFAS 133. Therefore, changes in their fair value are recorded in earnings in the period of change.
Weather derivative contractsContingenciesSouthStar enters into weather derivative contracts, from time to time, for hedging purposes in order to preserve margins in the event of warmer-than-normal weather in the winter months. SouthStar accounts for these contracts using the intrinsic value method under the guidelines of EITF 99-02, “Accounting for Weather Derivatives.” There were no weather derivative contracts outstanding as of December 31, 2004 and 2003.
Accounting for Contingencies
Our accounting policies for contingencies cover a variety of business activities, including contingencies for potentially uncollectible receivables, rate matters, and legal and environmental exposures. We accrue for these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be reasonably estimated in accordance with SFAS No. 5, “Accounting for Contingencies�� (SFAS 5).Contingencies.” We base our estimates for these liabilities on currently available facts and our estimates of the ultimate outcome or resolution of the liability in the future. Actual results may differ from estimates, and estimates can be, and often are, revised either negatively or positively, depending on actual outcomes or changes in the facts or expectations surrounding each potential exposure.
Allowance for Doubtful Accounts
Accounting for Pension Benefits
We have a defined benefit pension plan for the benefit of substantially all full-time employees and qualified retirees. We use several statistical and other factors that attempt to anticipate future eventspostretirement plans Our pension and to calculateother postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the expense and liability related tomarket value of plan assets, estimates of the plan. These factors include our assumptions about the discount rate, expected return on plan assets, assumed discount rates and current demographic and actuarial mortality data. We annually review the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities. The assumed discount rate and the expected return on plan assets are the assumptions that generally have the most significant impact on our pension costs and liabilities.
The assumed discount rate, the assumed health care cost trend rate and assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.
The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net pension and postretirement cost. When establishing our discount rate, we consider absolute high quality corporate bond rates based on Moody’s Corporate AA long-term bond rate of future compensation increases. In addition,5.41% and the Citigroup Pension Liability rate of 5.51% at December 31, 2005. We further use these market indices as a comparision to a single equivalent discount rate derived with the assistance of our actuarial consultants use subjective factors such as withdrawal and mortality rates to estimate the projected benefit obligation. advisors.
The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense recorded in future periods.
The expected long-term rate of return on assets is utilized in calculating the expected return on plan assets component of our annual pension and postretirement plan cost. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that year’s annual pension or postretirement plan cost is not affected. Rather, this gain or loss reduces or increases future pension or postretirement plan costs.
Prior to 2006, we estimated the assumed health care cost trend rate used in determining our postretirement net expense based upon our actual health care cost experience, the effects of recently enacted legislation and general economic conditions. However, starting in 2006, our postretirement plans have been capped at 2.5% for increases in health care costs. Consequently, a one percentage point increase or decrease in the assumed health care trend rate does not materially affect our periodic benefit cost for our postretirement plans. A one percentage point increase in the assumed health care cost trend rate would increase our accumulated projected benefit obligation by $6 million. A one point percentage point decrease in the assumed health care cost trend rate would decrease our accumulated projected benefit obligation by $5 million. Our assumed rate of retirement is estimated based upon our annual review of our participant census information as of the measurement date.
At December 31, 2004,2005, we increasedhad an increase in our minimum pension liability by approximately $18$8 million, resulting in an aftertax loss to other comprehensive income (OCI) of $11 million. At December 31, 2003, we reduced our minimum pension liability by approximately $14 million, which resulted in an aftertax gain to OCI of $8$5 million. These adjustments reflectThis adjustment reflected our funding contributions to the plan and updated valuations for the projected benefit obligation and plan assets. To the extent that our future expenses and contributions increase as a result of the additional minimum pension liability, we believe that such increases are recoverable in whole or in part under future rate proceedings or mechanisms.
Equity market performance and corporate bond rates have a significant effect on our reported unfunded accumulated benefit obligation (ABO), as the primary factors that drive the value of our unfunded ABO are the assumed discount rate and the actual return on plan assets. Additionally, equity market performance has a significant effect on our market-related value of plan assets (MRVPA), which is a calculated value and differs from the actual market value of plan assets. The MRVPA recognizes the differences between the actual market value and expected market value of our plan assets and is determined by our actuaries using a five-year moving weighted average methodology. Gains and losses on plan assets are spread through the MRVPA based on the five-year moving weighted average methodology, which affects the expected return on plan assets component of pension expense.
A one-percentage-point increase in the assumed discount rate would decrease the AGL Resources Inc. Retirement Plan’s ABO by approximately $37$39 million and would decrease annual pension expense by approximately $4 million. A one-percentage-point decrease in the assumed discount rate would increase the AGL Resources Inc. Retirement Plan’s ABO by approximately $46$44 million and would increase annual pension expense by approximately $4 million. Additionally, a one-percentage-point increase or decrease in the expected return on assets would decrease or increase the AGL Resources Inc. Retirement Plan’s annual pension expense by approximately $3 million.
Additionally, in 2004 we have recorded a $36 million liability for the amount of NUI’s projected benefit obligation in excess of the fair value of pension plan assets at the date of our acquisition of NUI. The acquisition will impactAt December 31, 2005 our pension plan expensesaccrued liability for NUI’s projected obligation is $31 million, reflecting $9 million in adjustments for terminations and liabilities.settlement of liabilities affected by the NUI purchase transaction offset by net periodic benefit cost of $3 million in 2005. A one-percentage-point increase in the assumed discount rate would decrease the NUI Corporation Retirement Plan’s ABO ofby approximately $12$14 million wouldand decrease the annual benefit cost by approximately $0.1$2 million. A one-percentage-point decrease in the assumed discount rate would increase the NUI Corporation Retirement Plan’s ABO ofby approximately $13$17 million and increase our annual pension expense by approximately $0.1$1 million. In addition, a one-percentage-point increase or decrease in the NUI Corporation Retirement Plan’s expected return on assets would decrease or increase ourannual pension expensesexpense by approximately $0.1$1 million.
As of December 31, 2004,2005, the market value of the pension assets was $390$371 million compared to a market value of $259$390 million as of December 31, 2003.2004. The net increasedecrease of $131$19 million resulted from
· | contributions of $13$5 million in April 2004August 2005 |
· | contributions of $1 million in 20042005 to our supplemental retirement plan |
· | an actual return on plan assets of $26$27 million less benefits paid of $19 million |
· | the acquisition of NUI assets of $111$52 million |
Our $13$5 million in contributions to the pension plan in 20042005 reduced annual pension expense by approximately $1$0.4 million in 2004.2005. The actual return on plan assets compared to the expected return on plan assets will have an impact on our benefit obligation as of December 31, 2004,2005 and our pension expense for 2005.2006. We are unable to determine how this actual return on plan assets will affect future benefit obligation and pension expense, as actuarial assumptions and differences between actual and expected returns on plan assets are determined at the time we complete our actuarial evaluation as of December 31, 2004.2005. Our actual returns may also be positively or negatively impacted as a result of future performance in the equity and bond markets.
For information regarding accounting developments, see Note 3.
The following are some of the factors that could affect our future performance or could cause actual results to differ materially from those expressed or implied in our forward-looking statements. We cannot predict every event and circumstance that may adversely affect our business, and thereforebut the risks and uncertainties described below may not beare the only ones we face. Additional risks and uncertaintiesmost significant factors that we are unaware of, or that we currently deem immaterial, also may become important factors that cause serious damage to our business in the future.have identified at this time.
Risks Related to the NUI Acquisition
We may encounter difficulties integrating NUI into our business and may not fully attain or retain, or achieve within a reasonable time frame, expected strategic objectives, cost savings and other benefits of the acquisition.
We expect to realize strategic and other benefits as a result of our acquisition of NUI. Our ability to realize these benefits or successfully integrate NUI’s businesses, however, is subject to certain risks and uncertainties, including
· | The costs of integrating NUI and upgrading and enhancing its operations may be higher than we expect and may require more resources, capital expenditures and management attention than anticipated. |
· | Employees important to NUI’s operations may decide not to continue employment with us. |
· | We may be required to allocate some of the cost savings achieved through the integration of NUI to our existing regulated utilities, which could prevent us from retaining some of the benefits achieved if the allocated cost savings result in rate reductions in future rate proceedings. |
· | We may be unable to maintain and enhance our relationship with NUI’s existing customers and regulators. |
· | We may be unable to anticipate or manage risks that are unique to NUI’s business, including those related to its workforce, customer demographics, regulatory environment, information systems and diverse geography. |
· | We may be unable to appropriately and in a timely manner adapt to both existing and changing economic, regulatory and competitive conditions. |
· | The financial results of operations we acquired are subject to many of the same factors that have historically affected our financial condition and results of operations, including weather sensitivity, extensive federal, state and local regulation, increasing gas costs, competition and market risks, and national, regional and local economic conditions. |
Our failure to manage these risks, or other risks related to the acquisition that are not presently known to us, could prevent us from realizing the expected benefits of the acquisition and also may have a material adverse effect on our results of operations and financial condition following the transaction.
NUI has certain liabilities and obligations related to its pre-acquisition activities that may result in unanticipated costs and expenses to us.
NUI has been, and continues to be, the subject of various lawsuits, regulatory audits, investigations and settlements related to certain of its and its affiliates’ business practices prior to the date of the acquisition agreement. We will bear the costs of any liability, expense or obligation related to ongoing or new lawsuits, regulatory audits, investigations or claims related to these pre-acquisition activities. Additionally, management of these claims and liabilities may require a disproportionate amount of our management’s time and attention. A failure to manage these risks could negatively affect our results of operations, our financial condition and our reputation in the industry, and may reduce the anticipated benefits of the acquisition.
NUI has material weaknesses in its internal controls that may force us to incur unanticipated costs to resolve after closing.
NUI’s external and internal auditors performed audits during its fiscal 2003 and 2004 years that identified material weaknesses in NUI’s internal controls. Additional internal control issues and deficiencies were identified in the focused audit of NUI and its affiliates that was conducted at the request of the NJBPU. We have initiated our efforts to assess the systems of internal control related to NUI’s business in order to comply with the requirements of SOX 404. At this time, however, we believe these operations continue to have material deficiencies in their internal controls that we will be required to address and resolve. We cannot make any assurance that our systems of internal and disclosure controls and procedures will be able to detect or prevent all errors or fraud or ensure that all material information regarding weaknesses in controls will be made known to management in the near term. We may incur significant additional costs to resolve these internal control and disclosure issues.
Risks related to the regulation of our businesses could affect the rates we are able to charge, our costs and our profitability.
Our businesses are subject to regulation by federal, state and local regulatory authorities. In particular, at the federal level our distribution businesses arehave been regulated by the SEC under the PUHCA and, effective February 8, 2006 will be regulated by the FERC under the PUHCA 2005. At the state level, our distribution businesses are regulated by the Georgia Commission, the Tennessee Authority, the NJBPU, the Florida Commission, the Virginia Commission and the Maryland Commission. These authorities regulate many aspects of our distribution operations, including construction and maintenance of facilities, operations, safety, rates that we can charge customers, rates of return, the authorized cost of capital, recovery of pipeline replacement and environmental remediation costs, carrying costs we charge Marketers for gas held in storage for their customer accounts and relationships with our affiliates. Our ability to obtain rate increases and rate supplements to maintain our current rates of return depends on regulatory discretion, and there can be no assurance that we will be able to obtain rate increases or rate supplements or continue receiving our currently authorized rates of return.
Deregulation in the natural gas industry is the separation of the provision and pricing of local distribution gas services into discrete components. Deregulation typically focuses on the separation of the gas distribution business from the gas sales business and is intended to cause the opening of the formerly regulated sales business to alternative unregulated suppliers of gas sales services.
In 1997, the Georgia legislature enacted the Natural Gas Competition and Deregulation Act. To date, Georgia is the only state in the nation that has fully deregulated gas distribution operations, which ultimately resulted in Atlanta Gas Light exiting the retail natural gas sales business while retaining its gas distribution operations. Gas marketers then assumed the retail gas sales responsibility at deregulated prices. The deregulation process required Atlanta Gas Light to completely reorganize its operations and personnel at significant expense. It is possible that the legislature could reverse the deregulation process and require or permit Atlanta Gas Light to provide retail gas sales service once again or require SouthStar to change the nature of how it provides natural gas to certain customers. In addition, the Georgia Commission has statutory authority on an emergency basis to order Atlanta Gas Light to temporarily provide the same retail gas service that it provided prior to deregulation. If any of these events were to occur, we would incur costs to reverse the restructuring process or potentially lose the earnings opportunity embedded within the current marketing framework. Furthermore, the Georgia Commission has authority to change the terms under which we charge Marketers for certain supply-related services, which could also affect our future earnings.
We have a concentration of credit risk in Georgia, which could expose a significant portion of our accounts receivable to collection risks.
We have a concentration of credit risk related to the provision of natural gas services to Georgia’sGeorgia Marketers. At September 30, 1998 (prior to deregulation), Atlanta Gas Light had approximately 1.4 million end-use customers in Georgia. In contrast, at December 31, 2004,2005, Atlanta Gas Light had only 10 certificated and active Marketers in Georgia, four of which (based on customer count and including SouthStar) accounted for approximately 46%33% of our totalconsolidated operating margin for 2004.2005. As a result, Atlanta Gas Light now depends on a concentrated number of customers for revenues. The failure of these Marketers to pay Atlanta Gas Light could adversely affect Atlanta Gas Light’s business and results of operations and expose it to difficulties in collecting Atlanta Gas Light’s accounts receivable. Additionally, SouthStar markets directly to end-use customers and has periodically experienced credit losses as a result of cold weather, variable prices and customers’ inability to pay.
Our revenues, operating results and financial condition may fluctuate with the economy and its corresponding impact on our customers.
Our business is influenced by fluctuations in the economy. As a result, adverse changes in the economy can have negative effects on our revenues, operating results and financial condition. The level of economic and population growth in our regulated operations’ service territories, particularly new housing starts, directly affects our potential for growing our revenues.
The cost of providing pension and postretirement health care benefits to eligible former employees is subject to changes in pension fund values and changing demographics and may have a material adverse effect on our financial results.
We have a defined benefit pension plan for the benefit of substantially all full-time employees and qualified retirees. See “Critical Accounting Policies.” The cost of providing these benefits to eligible current and former employees is subject to changes in the market value of our pension fund assets and changing demographics, including longer life expectancy of beneficiaries and an expected increase in the number of eligible former employees over the next five years.
We believe thatAny sustained declines in equity markets and reductions in bond yields have had and may continue to have a material adverse effect on the value of our pension funds. In these circumstances, we may be required to recognize an increased pension expense or a charge to our statement of consolidated income to the extent that the pension fund values are less than the total anticipated liability under the plans.
We face increasing competition, and if we are unable to compete effectively, our revenues, operating results and financial condition will be adversely affected.
The natural gas business is highly competitive, and we are facing increasing competition from other companies that supply energy, including electric companies, oil and propane providers and, in some cases, energy marketing and trading companies. In particular, the success of our investment in SouthStar is affected by the competition SouthStar faces from other energy marketers providing retail natural gas services in the Southeast. Natural gas competes with other forms of energy. The primary competitive factor is price. Changes in the price or availability of natural gas relative to other forms of energy and the ability of end-users to convert to alternative fuels affect the demand for natural gas. In the case of commercial, industrial and agricultural customers, adverse economic conditions, including higher gas costs, could also cause these customers to bypass our systems in favor of special competitive contracts with lower per unit costs.per-unit costs or disconnect from our system.
Our wholesale services segment competes with larger, full-service energy providers, which may limit our ability to grow our business.
WholesaleOur wholesale services segment competes with national and regional full-service energy providers, energy merchants, and producers and pipelines for sales based on our ability to aggregate competitively priced commodities with transportation and storage capacity. Some of our competitors are larger and better capitalized than we are and have more national and global exposure than we do. The consolidation of this industry and the pricing to gain market share may affect our margins. We expect this trend to continue in the near term, and the increasing competition for asset management deals could result in downward pressure on the volume of transactions and the related margins available in this portion of Sequent’s business.
Our asset management arrangements between Sequent and theour affiliated local distribution companies and between Sequent and its nonaffiliated customers may not be renewed or may be renewed at lower levels, which could have a significant impact on Sequent’s business.
Sequent currently manages the storage and transportation assets of our affiliates Atlanta Gas Light, Elizabethtown Gas, Virginia Natural Gas, Florida City Gas and Chattanooga Gas and shares profits it earns from the management of those assets with those customers and their customers.customers, except at Elizabethtown Gas and Elkton Gas where Sequent is assessed an annual fixed fee payment. In addition, Sequent has asset management agreements with certain nonaffiliated customers. On April 1, 2005, Sequent plansEntry into and renewal of these agreements are subject to commence asset management responsibilities for Elizabethtown Gas, Florida Gas and Elkton Gas. The contract terms are currently being negotiated.regulatory approval. Sequent’s results could be significantly impacted if these agreements are not renewed or are amended or renewed with less favorable terms.
Our profitability may decline if the counterparties to ourSequent’s asset management transactions fail to perform in accordance with ourSequent’s agreements.
Wholesale servicesSequent focuses on capturing the value from idle or underutilized energy assets, typically by executing transactions that balance the needs of various markets and time horizons. Wholesale servicesSequent is exposed to the risk that counterparties to our transactions will not perform their obligations. Should the counterparties to these arrangements fail to perform, we might be forced to enter into alternative hedging arrangements, honor the underlying commitment at then-current market prices or return a significant portion of the consideration received for gas under a long-term contract. In such events, we might incur additional losses to the extent of amounts, if any, already paid to or received from counterparties.
We have a concentration of credit risk at Sequent that could expose us to collection risks.
We often extend credit to our counterparties. Despite performing credit analysisanalyses prior to extending credit and seeking to effectuate netting agreements, we are exposed to the risk that we may not be able to collect amounts owed to us. If the counterparty to such a transaction fails to perform and any collateral we have secured is inadequate, we could experience material financial losses.
We have a concentration of credit risk at Sequent, which could expose a significant portion of our credit exposure to collection risks. Approximately 57%52% of Sequent’s credit exposure is concentrated in 20 counterparties. Although most of this concentration is with counterparties that are either load-serving utilities or end-use customers and that have supplied some level of credit support, default by any of these counterparties in their obligations to pay amounts due Sequent could result in credit losses that would negatively impact our wholesale services segment.
We are exposed to market risk and may incur losses in wholesale services.
The commodity, storage and transportation portfolios at Sequent consist of contracts to buy and sell natural gas commodities, including contracts that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that we do not anticipate, we could experience financial losses from our trading activities. Value at risk (VaR) is defined as the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. Based on a 95% confidence interval and employing a 1-day and a 10-day holding period for all positions, Sequent’s portfolio of positions as of December 31, 20042005 had a 1-day holding period VaR of $0.1$0.6 million and 10-day holding period VaR of $0.2$1.9 million.
Our accounting results may not be indicative of the risks we are taking or the economic results we expect due to changes in accounting for wholesale services.
Although Sequent enters into various contracts to hedge the value of our energy assets and operations, the timing of the recognition of profits or losses on the hedges does not always match up with the profits or losses on the item being hedged. ThisThe difference in accounting can result in volatility in Sequent’s reported earningsresults, even though the expected profit margin is essentially unchanged from one period to the next that does not exist from an economic standpoint overdate the full life of the hedge and the hedged item.transactions were consummated.
Our business is subject to environmental regulation in all jurisdictions in which we operate and our costs to comply are significant, and any changes in existing environmental regulation could negatively affect our results of operations and financial condition.
Our operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Such environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Our current costs to comply with these laws and regulations are significant to our results of operations and financial condition. Failure to comply with these laws and regulations and failure to obtain any required permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations.
In addition, claims against us under environmental laws and regulations could result in material costs and liabilities. Existing environmental regulations could also be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur. With the trend toward stricter standards, greater regulation, more extensive permit requirements and an increase in the number and types of assets operated by us subject to environmental regulation, our environmental expenditures could increase in the future, particularly if those costs are not fully recoverable from our customers. Additionally, the discovery of presently unknown environmental conditions could give rise to expenditures and liabilities, including fines or penalties, which could have a material adverse effect on our business, results of operations or financial condition.
We could incur additional material costs for the environmental condition of some of our assets, including former manufactured gas plants.
We are generally responsible for all on-site and certain off-site liabilities associated with the environmental condition of the natural gas assets that we have operated, acquired or developed, regardless of when the liabilities arose and whether they are or were known or unknown. In addition, in connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Before natural gas was widely available in the Southeast, we manufactured gas from coal and other fuels. Those manufacturing operations were known as manufactured gas plants, or MGPs, which we ceased operating in the 1950s.
We have identified 10 sites in Georgia and 3 in Florida where we, or our predecessors, own or owned all or part of ana MGP site. We are required to investigate possible environmental contamination at those MGP sites and, if necessary, clean up any contamination. To date, cleanup has been completed at these sites, and as of December 31, 2004,2005, the soil and sediment remediation program was approximately 78% complete.complete for all Georgia sites, although groundwater cleanup continues. As of December 31, 2004,2005, projected costs associated with the MGP sites were $56$31 million. For elements of the MGP program where we still cannot performprovide engineering cost estimates, considerable variability remains in available future cost estimates.
In addition, NUI iswe are associated with as many as 6 former sites in New Jersey, North Carolina and 10 former sitesother states that we assumed with our acquisition of NUI in other states.November 2004. Material cleanups of these sites have not been completed nor are precise estimates available for future cleanup costs. For the New Jersey sites, cleanup cost estimates range from $30$57 million to $116$104 million. Costs have been estimated for only one1 of the ten non-New Jersey sites, for which current estimates range from $4$10 million to $16$17 million.
The success of our telecommunications business strategy may be adversely affected by uncertain market conditions.
The current strategy of our telecommunications business is based upon our ability to lease telecommunications conduit and dark fiber in the Atlanta, Georgia and Phoenix, Arizona metropolitan areas. The market for these services, like the telecommunications industry in general, is very competitive, rapidly changing and currently suffering from lack of market commitments. We cannot be certain that growth in demand for these services will occur as expected. If the market for these services fails to grow as anticipated or becomes saturated with competitors, including competitors using alternative technologies, our investment in the telecommunications business may be adversely affected.
Future acquisitions and expansions, if any, may affect our business by increasing the level of our indebtedness and contingent liabilities and creating integration difficulties.
From time to time, we may evaluate and acquire assets or businesses or enter into joint venture arrangements that we believe complement our existing businesses and related assets. As a result, the relative makeup of our business is subject to change. These acquisitions and joint ventures may require substantial capital or the incurrence of additional indebtedness. Further, acquired operations or joint ventures may not achieve levels of revenues, operating income or productivity comparable to those of our existing operations or may not otherwise perform as expected. Realization of the anticipated benefits of acquisitions or other transactions could take longer than expected. Acquisitions or joint ventures may also involve a number of risks, including
· | our inability to integrate operations, systems and procedures |
· | the assumption of unknown risks and liabilities |
· | diversion of management’s attention and resources |
· | difficulty retaining and training acquired key personnel |
Our ability to successfully make strategic acquisitions and investments will depend on
· | the extent to which acquisitions and investment opportunities become available |
· | our success in bidding for the opportunities that do become available |
· | regulatory approval, if required, of the acquisitions on favorable terms |
· | our access to capital and the terms upon which we obtain capital |
· | if we are unable to make strategic investments and acquisitions, we may be unable to grow |
Our growth may be restricted by the capital intensivecapital-intensive nature of our business.
In order to maintain our historic growth, weWe must construct additions to our natural gas distribution system each year.year to continue the expansion of our customer base. The cost of this construction may be affected by the cost of obtaining government approvals, development project delays or changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost of a project. Our cash flows are not fully adequate to finance the cost of this construction. As a result, we must fund a portion of our cash needs through borrowings and the issuance of common stock. Our ability to finance the cost of constructing additions to our system depends onThis may limit our ability to borrow funds or sellincrease infrastructure to connect customers due to limits on the amount we can economically invest, which shifts costs to potential customers. This may make it uneconomical for these potential customers to connect to our common stock.distribution systems.
Changes in weather conditions may affect our earnings.
Weather conditions and other natural phenomena can have a large impact on our earnings. Severe weather conditions can impact our suppliers and the pipelines that deliver gas to our distribution system. Extended mild weather, during either during the winter period or summer period, can have a significant impact on demand for and the cost of natural gas.
We have a WNA mechanism for Elizabethtown Gas, Chattanooga Gas and Virginia Natural Gas that partially offsets the impact thatof unusually cold or warm weather has on residential and commercial customer billings and margin. The WNA is most effective in a reasonable temperature range relative to normal weather using historical averages. The protection afforded by the WNA depends uponon continued regulatory approval. The loss of this continued regulatory approval could make us more susceptible to weather-related earnings fluctuations.
Inflation and increased gas costs could adversely impact our customer base and customer collections and increase our level of indebtedness.
Inflation has caused increases in certain operating expenses and has required us to replace assets at higher costs. We have a process in place to continually review the adequacy of our utility gas rates in relation to the increasing cost of providing service and the inherent regulatory lag in adjusting those gas rates. Historically, we have been able to budget and control operating expenses and investments within the amounts authorized to be collected in rates and intend to continue to do so. The ability to control expenses is an important factor that will influence future results.
Rapid increases in the price of purchased gas which occurred in some prior years, cause us to experience a significant increase in short-term debt because we must pay suppliers for gas when it is purchased, which can be significantly in advance of when these costs may be recovered through the collection of monthly customer bills for gas delivered. Increases in purchased gas costs also slow our utility collection efforts as customers are more likely to delay the payment of their gas bills, leading to higher-than-normal accounts receivable. This situation also results in higher short-term debt levels and increased bad debt expense. Should the price of purchased gas increase significantly in the upcoming heating season, we would expect increases in our short-term debt, accounts receivable and bad debt expense during 2005.2006.
Finally, higher costs of natural gas in recent years have already caused many of our utility customers to conserve in the use of our gas services and could lead to even more customers utilizing such conservation methods.methods or switching to other more efficient competing products. The higher costs have also allowed products utilizing energy sources other than natural gas for applications that have traditionally used natural gas to be in more competitive position, encouraging some customers to move away from natural gas fired equipment to equipment fueled by other energy sources.
A decrease in the availability of adequate pipeline transportation capacity could reduce our revenues and profits.
Our gas supply depends uponon the availability of adequate pipeline transportation and storage capacity. We purchase a substantial portion of our gas supply from interstate sources. Interstate pipeline companies transport the gas to our system. A decrease in interstate pipeline capacity available to us or an increase in competition for interstate pipeline transportation and storage service could reduce our normal interstate supply of gas.
Risks Related to Our Corporate and Financial Structure
If we breach any of the material financial covenants under our various indentures, credit facilities or guarantees, our debt service obligations could be accelerated.
Our existing debt and the debt of certain of our subsidiaries contain a number of significant financial covenants. If we or any of these subsidiaries breach any of the financial covenants under these agreements, our debt repayment obligations under them could be accelerated. In such event, we may not be able to refinance or repay all our indebtedness, which would result in a material adverse effect on our business, results of operations and financial condition.
As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.
Our Credit Facility and the indenture under which Atlanta Gas Light’s outstanding Medium-Termmedium-term notes were issued contain cross-default provisions. Accordingly, should an event of default occur under some of our debt agreements, we face the prospect of being in default under other of our debt agreements, obliged in such instance to satisfy a large portion of our outstanding indebtedness and unable to satisfy all of our outstanding obligations simultaneously.
We depend on our ability to successfully access the capital markets. Any inability to access the capital or financial markets may limit our ability to execute our business plan or pursue improvements that we may rely on for future growth.
We rely on access to both short-term money markets (in the form of commercial paper)paper and lines of credit) and long-term capital markets as a source of liquidity for capital and operating requirements not satisfied by the cash flow from our operations. If we are not able to access financial markets at competitive rates, our ability to implement our business plan and strategy will be affected. Certain market disruptions may increase our cost of borrowing or affect our ability to access one or more financial markets. Such market disruptions could result from
· | adverse economic conditions |
· | adverse general capital market conditions |
· | poor performance and health of the utility industry in general |
· | bankruptcy or financial distress of unrelated energy companies or Marketers in Georgia |
· | decreasessignificant decrease in the market price of and demand for natural gas |
· | adverse regulatory actions that affect our local gas distribution companies |
· | terrorist attacks on our facilities or our suppliers |
Increases in our leverage could adversely affect our competitive position and financial condition.
An increase in our debt relative to our total capitalization could adversely affect us by
· | increasing the cost of future debt financing |
· | limiting our ability to obtain additional financing, if we need it, for working capital, acquisitions, debt service requirements or other purposes |
· | making it more difficult for us to satisfy our existing financial obligations |
· | requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes |
· | prohibiting the payment of dividends on our common stock or adversely impacting our ability to pay such dividends at the current rate |
· | increasing our vulnerability to adverse economic and industryextreme weather conditions |
· | limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete |
Changing rating agency requirements could negatively affect our growth and business strategy, and aA downgrade in our credit rating could negatively affect our ability to access capital.
S&P, Moody’s and Fitch have recently implemented new requirements for various ratings levels. In order to maintain our current credit ratings in light of these or future new requirements, we may need to take steps or change our business plans in ways that may affect our growth and earnings per share. S&P, Moody’s and Fitch currently assign our senior unsecured debt a rating of BBB+, Baa1 and A,A-, respectively. Our commercial paper currently is rated A-2, P-2 and F-2 by S&P, Moody’s and Fitch, respectively. If the rating agencies downgrade our ratings, particularly below investment grade, it may significantly limit our access to the commercial paper market and our borrowing costs would increase. In addition, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources would likely decrease.
Additionally, if our credit rating by either S&P or Moody’s falls to non-investment grade status, we will be required to provide additional support for certain customers of our wholesale business. As of December 31, 2004,2005, if our credit rating had fallen below investment grade, we would have been required to provide collateral of approximately $20$51 million to continue conducting our wholesale services business with certain counterparties.
The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations.
We use derivatives, including futures, forwards and swaps, to manage our commodity and financial market risks. We could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could adversely affect the value of the reported fair value of these contracts.
We depend on cash flow from our operations to pay dividends on our common stock.
We depend on dividends or other distributions of funds from our subsidiaries to pay dividends on our common stock. Payments of our dividends will depend on our subsidiaries’ earnings and other business considerations and may be subject to statutory or contractual obligations. Additionally, payment of dividends on our common stock is at the sole discretion of our Board of Directors.
We are vulnerable to interest rate risk with respect to our debt, which could lead to changes in interest expense.
We are subject to interest rate risk in connection with the issuance of fixed-rate and variable-rate debt. In order to maintain our desired mix of fixed-rate and variable-rate debt, we use interest rate swap agreements and exchange fixed-rate and variable-rate interest payment obligations over the life of the arrangements, without exchange of the underlying principal amounts. See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.” We cannot ensure you that we will be successful in structuring such swap agreements to effectively manage our risks. If we are unable to do so, our earnings may be reduced. In addition, higher interest rates, all other things equal, reduce the earnings that we derive from transactions where we capture the difference between authorized returns and short-term borrowings.
Our tax rate may be increased and/or tax laws affecting us can change that may have an adverse impact on our cash flows and profitability.
The rates of federal, state and local taxes applicable to the industries in which we operate, which often fluctuate, could be increased by the respective taxing authorities. In addition, the tax laws, rules and regulations that affect our business could change. Any such increase or change could adversely impact our cash flows and profitability.
Risks Related to Our Industry
Transporting and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs.
Our gas distribution activities involve a variety of inherent hazards and operating risks, such as leaks, accidents and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution and impairment of our operations, which in turn could lead to substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The location of pipelines and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events not fully covered by insurance could adversely affect our financial position and results of operations.
Natural disasters, terrorist activities and the potential for military and other actions could adversely affect our businesses.
Natural disasters may damage our assets. The threat of terrorism and the impact of retaliatory military and other action by the United States and its allies may lead to increased political, economic and financial market instability and volatility in the price of natural gas that could affect our operations. In addition, future acts of terrorism could be directed against companies operating in the United States, and companies in the energy industry may face a heightened risk of exposure to acts of terrorism. These developments have subjected our operations to increased risks. The insurance industry has also been disrupted by these events. As a result, the availability of insurance covering risks against which we and our competitors typically insure may be limited. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.
Recent investigations and events involving the energy markets have resulted in an increased level of public and regulatory scrutiny in the energy industry and in the capital markets, resulting in increased regulation and new accounting standards.
As a result of the bankruptcy and adverse financial condition affecting several entities, particularly the bankruptcy filing by Enron, recently discovered accounting irregularities of various public companies and investigations by governmental authorities into energy trading activities, public companies, including particularly those in the energy industry, have been under an increased amount of public and regulatory scrutiny. Recently discovered practices and accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. New laws, such as the Sarbanes-Oxley Act of 2002, and regulations to address these concerns have been and continue to be adopted, and capital markets and rating agencies have increased their level of scrutiny. Costs related to increased scrutiny may have an adverse effect on our business, financial condition and access to capital markets. In addition, the FASB or the SEC could enact new accounting standards that could impact the way we are required to record revenues, assets and liabilities. These changes in accounting standards could lead to negative impacts on our reported earnings or increases in our liabilities.
We are exposed to risks associated with commodity prices, interest rates and credit. Commodity price risk is defined as the potential loss that we may incur as a result of changes in the fair value of a particular instrument or commodity. Interest rate risk results from our portfolio of debt and equity instruments that we issue to provide financing and liquidity for our business. Credit risk results from the extension of credit throughout all aspects of our business but is particularly concentrated at Atlanta Gas Light in distribution operations and in wholesale services.
Our Risk Management Committee (RMC) is responsible for establishing the overall establishment of risk management policies and the monitoring of compliance with, and adherence to, the terms within these policies, including approval and authorization levels and delegation of these levels. Our RMC consists of senior executives who monitor commodity price risk positions, corporate exposures, credit exposures and overall results of our risk management activities, andactivities. It is chaired by our chief risk officer, who is responsible for ensuring that appropriate reporting mechanisms exist for the RMC to perform its monitoring functions. Our risk management activities and related accounting treatments are described in further detail in Note 4.
Commodity Price Risk
Wholesale ServicesRetail Energy Operations This segment routinely utilizes various typesSouthStar’s use of financial and other instruments to mitigate certain commodity price risks inherent in the natural gas industry. These instruments includederivatives is governed by a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, option contracts and financial swap agreements. The following table includes the fair values and average values of our energy marketing and risk management assetspolicy, created and liabilities as of December 31, 2004 and 2003. We base the average values on monthly averages for the 12 months ended December 31, 2004 and 2003.
| | Asset | |
| | Average 12-Month Values | | Value at: | |
In millions | | 2004 | | 2003 | | Dec. 31, 2004 | | Dec. 31, 2003 | |
Natural gas contracts | | $ | 28 | | $ | 14 | | $ | 36 | | $ | 13 | |
| | Liability | |
| | Average 12-Month Values | | Value at: | |
In millions | | 2004 | | 2003 | | Dec. 31, 2004 | | Dec. 31, 2003 | |
Natural gas contracts | | $ | 21 | | $ | 14 | | $ | 19 | | $ | 18 | |
We employ a systematic approach to the evaluation and management of the risks associated with our contracts related to wholesale marketing andmonitored by its risk management including VaR. VaR is defined ascommittee, which prohibits the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degreeuse of probability. We use a 1-day and a 10-day holding period and aderivatives for speculative purposes. A 95% confidence interval is used to evaluate our VaR exposure. A 95% confidence interval means there is a 5% probability that the actual change in portfolio value will be greater than the calculated VaR value over the holding period. We calculate VaR based on the variance-covariance technique. This technique requires several assumptions for the basis of the calculation, such as price volatility, confidence interval and holding period. Our VaR may not be comparable to a similarly titled measure of another company because, although VaR is a common metric in the energy industry, there is no established industry standard for calculating VaR or for the assumptions underlying such calculations. The following table provides more information on SouthStar’s 1-day and 10-day holding period VaR.
OurIn millions | | 1-day | | 10-day | |
2005 period end | | $ | 0.3 | | $ | 0.8 | |
SouthStar generates operating margin from the active management of storage positions through a variety of hedging transactions and derivative instruments aimed at managing exposures arising from changing commodity prices. SouthStar uses these hedging instruments to lock in economic margins (as spreads between wholesale and retail commodity prices widen between periods) and thereby minimize its exposure to declining operating margins.
Wholesale Services This segment routinely utilizes various types of financial and other instruments to mitigate certain commodity price risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts and financial swap agreements. The following table includes the fair values and average values of our energy marketing and risk management assets and liabilities as of December 31, 2005 and 2004. We base the average values on monthly averages for the 12 months ended December 31, 2005 and 2004.
| |
| | Average values at December 31, | |
In millions | | 2005 | | 2004 | |
Asset | | $ | 83 | | $ | 28 | |
Liability | | | 102 | | | 21 | �� |
| | Value at December 31, | |
In millions | | 2005 | | 2004 | |
Asset | | $ | 97 | | $ | 36 | |
Liability | | | 110 | | | 19 | |
We employ a systematic approach to evaluating and managing the risks associated with our contracts related to wholesale marketing and risk management, including VaR. Similar to SouthStar, Sequent uses a 1-day and a 10-day holding period and a 95% confidence interval to evaluate its VaR exposure.
Sequent’s open exposure is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management, including the chief risk officer. Because weSequent generally managemanages physical gas assets and economically protect ourprotects its positions by hedging in the futures markets, ourits open exposure is generally minimal, permitting usSequent to operate within relatively low VaR limits. We employSequent employs daily risk testing, using both VaR and stress testing, to evaluate the risks of ourits open positions.
OurSequent’s management actively monitors open commodity positions and the resulting VaR. We continueSequent continues to maintain a relatively matched book, where ourits total buy volume is close to sell volume, with minimal open commodity risk. Based on a 95% confidence interval and employing a 1-day and a 10-day holding period for all positions, ourSequent’s portfolio of positions for the 12 months ended December 31, 2005, 2004 and 2003 had the following 1-day and 10-day holding period VaRs:VaRs.
2004 | | | | | | |
In millions | | 1-day | | 10-day | | | 1-day | | 10-day | |
2005 | | | | | | |
Period end | | $ | 0.1 | | $ | 0.2 | | | $ | 0.6 | | $ | 1.9 | |
12-month average | | | 0.1 | | | 0.3 | | | | 0.4 | | | 1.2 | |
High | | | 0.4 | | | 1.3 | | | | 1.1 | | | 3.5 | |
Low(1) | | | 0.0 | | | 0.0 | | |
Low (1) | | | | 0.0 | | | 0.0 | |
2003 | | | | | | |
In millions | | 1-day | | 10-day | | |
2004 | | | | | | |
Period end | | $ | 0.3 | | $ | 1.0 | | | $ | 0.1 | | $ | 0.2 | |
12-month average | | | 0.1 | | | 0.3 | | | | 0.1 | | | 0.3 | |
High | | | 2.5 | | | 4.7 | | | | 0.4 | | | 1.3 | |
Low(1) | | | 0.0 | | | 0.0 | | |
Low (1) | | | | 0.0 | | | 0.0 | |
2003 | | | | | |
Period end | | $ | 0.3 | | $ | 1.0 | |
12-month average | | | 0.1 | | | 0.3 | |
High | | | 2.5 | | | 4.7 | |
Low (1) | | | 0.0 | | | 0.0 | |
(1) | $0.0 values represent amounts less than $0.1 million. |
Energy Investments SouthStar’s use of derivatives is governedDuring 2005 Sequent experienced increases in its high, 12-month average and period end 1-day and 10-day VaR amounts. These increases were directly associated with the market impacts and related price volatility created by a risk management policy createdthe Gulf Coast hurricanes during the third quarter and monitored by its risk management committee which prohibits the use of derivatives for speculative purposes. This policy also establishes VaR limits of $0.5 million on a 1-day holding period and $0.7 million on a 10-day holding period. A 95% confidence interval is used to evaluate VaR exposure. The maximum VaR experienced during 2004 was less than $0.2 million for the 1-day holding period and $0.5 million for the 10-day holding period.lingering effects through year end.
Interest Rate Risk
Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. To facilitate the achievement of desired fixedfixed-rate to variable-rate debt ratios, AGL Capital entered into interest rate swaps whereby it agreed to exchange, at specified intervals, the difference between fixed and variable amounts calculated by reference to agreed-uponagreed-on notional principal amounts. These swaps are designated to hedge the fair values of $100 million of the $300 million senior notes due 2011, andSenior Notes Due 2011.
At the beginning of 2005, we had $75 million of the $150 million principal amount of notes payable to Trusts due in 2041. In March 2004, we adjusted our fixed-to variable-rate debt obligations and terminated anoutstanding interest rate swap on $100agreements associated with our note payable at AGL Capital Trust II. On September 7, 2005, we terminated these interest rate swap agreements. We received a payment of $1 million related to this termination, which included accrued interest and the fair value of these interest rate swap agreements at the $225 million principal amount of Senior Notes due 2013. More information about our interest swaps are shown in the following table:termination date.
| | Market Value of Interest Rate Swap Derivatives | |
Dollars in millions | | | | | | Market Value as of: | |
Notional Amount | | Fixed-Rate | | Effective Variable Rate(1) | | Maturity | | Dec. 31, 2004 | | Dec. 31, 2003 | |
$75 | | | 8.0 | % | | 3.6 | % | | May 15, 2041 | | $ | 3 | | $ | 3 | |
100 | | | 7.1 | | | 5.2 | | | January 14, 2011 | | | (2 | ) | | (2 | ) |
100 | | | 4.5 | | | - | | | April 15, 2013(2 | ) | | - | | | (5 | ) |
(1) | As of December 31, 2004. |
(2) | Terminated in March 2004. |
In September 2005, we also executed five treasury-lock agreements totaling $125 million to hedge the interest rate risk associated with an anticipated 2006 financing. The agreements will result in a 4.11% interest rate on the 10-year United States Treasury bond against which we will be measured in issuing our own debt instruments and were designated as cash flow hedges against the future interest payments on the anticipated financing.
Credit Risk
Distribution Operations Atlanta Gas Light has a concentration of credit risk because it bills only ten10 Marketers in Georgia for its services. The credit risk exposure to Marketers varies with the time of the year, with exposure at its lowest in the nonpeak summer months and highest in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. These retail functions include customer service, billing, collections, and the purchase and sale of the natural gas commodity. These Marketers, in turn, bill end-use customers. The provisions of Atlanta Gas Light’s tariff allow Atlanta Gas Light to obtain security support in an amount equal to a minimum of two times a Marketer’s highest month’s estimated bill from Atlanta Gas Light. For 2004,2005, the four4 largest Marketers based on customer count, one of which was SouthStar, accounted for approximately 46%33% of our consolidated operating margin and 61%45% of distribution operations’ operating margin.
Several factors are designed to mitigate our risks from the increased concentration of credit that has resulted from deregulation. In addition to the security support described above, Atlanta Gas Light bills intrastate delivery service to Marketers in advance rather than in arrears. We accept credit support in the form of cash deposits, letters of credit/surety bonds from acceptable issuers and corporate guarantees from investment-grade entities. The RMC reviews on a monthly basis the adequacy of credit support coverage, credit rating profiles of credit support providers and payment status of each Marketer on a monthly basis.Marketer. We believe that adequate policies and procedures have been put in place to properly quantify, manage and report on Atlanta Gas Light’s credit risk exposure to Marketers.
Atlanta Gas Light also faces potential credit risk in connection with assignments to Marketers of interstate pipeline transportation and storage capacity. Although Atlanta Gas Light assigns this capacity to Marketers, in the event that a Marketer fails to pay the interstate pipelines for the capacity, the interstate pipelines would in all likelihood seek repayment from Atlanta Gas Light. The fact that some of the interstate pipelines require Marketers to maintain security for their obligations to the interstate pipelines arising out of the assigned capacity somewhat mitigates this risk.
Retail Energy Operations SouthStar credit-scores firm residential and small commercial customers using a national credit reporting agency and enrolls, without security, only those customers that meet or exceed SouthStar’s credit threshold. The average credit score of SouthStar’s Georgia customers has increased 9% since 2003.
SouthStar investigates potential interruptible and large commercial customers through reference checks, review of publicly available financial statements and review of commercially available credit reports. Prior to entering into a physical transaction, SouthStar also assigns physical wholesale counterparties an internal credit rating and credit limit based on their Moody’s, S&P and Fitch ratings, commercially available credit reports and audited financial statements.
Wholesale Services Sequent has established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. Sequent also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When we areSequent is engaged in more than one outstanding derivative transaction with the same counterparty and weit also havehas a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of ourSequent’s credit risk. Sequent also uses other netting agreements with certain counterparties with whom we conductit conducts significant transactions.
Master netting agreements enable Sequent to net certain assets and liabilities by counterparty. Sequent also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. Additionally, Sequent may require counterparties to pledge additional collateral when deemed necessary. We conductSequent conducts credit evaluations and obtainobtains appropriate internal approvals for ourits counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, we requireSequent requires credit enhancements by way of guaranty, cash deposit or letter of credit for transaction counterparties that do not meet the minimum ratings threshold.
Sequent, which provides services to Marketers and utility and industrial customers, also has a concentration of credit risk as measured by its 30-day receivable exposure plus forward exposure. As of December 31, 2004,2005, Sequent’s top 20 counterparties represented approximately 57%52% of the total counterparty exposure of $328$554 million, derived by adding together the top 20 counterparties’ exposures dividedand dividing by the total of Sequent’s counterparties’ exposures.
As of December 31, 2004,2005, Sequent’s counterparties, or the counterparties’ guarantors, had a weighted average S&P equivalent credit rating of A- compared to BBB at December 31, 2003., which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody’s and 1 being D or Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios of that counterparty.
To arrive at the weighted average credit rating, each counterparty’s assigned internal rating is multiplied by the counterparty’s credit exposure and summed for all counterparties. That sum is divided by the aggregate total counterparties’ exposures, and this numeric value is then converted to an S&P equivalent. The following tables show Sequent’s commodity receivable and payable positions as of December 31, 20042005 and 2003:2004.
| | As of: | |
| | December 31, | |
In millions | | 2005 | | 2004 | |
Gross receivables | | | | | |
Receivables with netting agreements in place: | | | | | | | |
Counterparty is investment grade | | $ | 462 | | $378 |
Counterparty is non-investment grade | | | 66 | | 36 |
Counterparty has no external rating | | | 113 | | 78 |
Receivables without netting agreements in place: | | | | | |
Counterparty is investment grade | | | 34 | | 16 |
Counterparty is non-investment grade | | | - | | 6 |
Counterparty has no external rating | | | - | | - |
Amount recorded on balance sheet | | $ | 675 | | $514 |
Gross payables | | | | | |
Payables with netting agreements in place: | | | | | | | |
Counterparty is investment grade | | $ | 456 | | $ | 291 | |
Counterparty is non-investment grade | | | 56 | | | 45 | |
Counterparty has no external rating | | | 255 | | | 139 | |
Payables without netting agreements in place: | | | | | | | |
Counterparty is investment grade | | | 4 | | | 40 | |
Counterparty is non-investment grade | | | - | | | 6 | |
Counterparty has no external rating | | | 4 | | | - | |
Amount recorded on balance sheet | | $ | 775 | | $ | 521 | |
Sequent has certain trade and credit contracts that have explicit rating trigger events in case of a credit rating downgrade. These rating triggers typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, Sequent would need to post collateral to continue transacting business with some of its counterparties. Posting collateral would have a negative effect on our liquidity. If such collateral were not posted, Sequent’s ability to continue transacting business with these counterparties would be impaired. If at December 31, 2005 Sequent’s credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $51 million.
Gross receivables | | As of: | | | |
In millions | | Dec. 31, 2004 | | Dec. 31, 2003 | | Change | |
Receivables with netting agreements in place: | | | | | | | | | | |
Counterparty is investment grade | | $ | 378 | | $ | 282 | | $ | 96 | |
Counterparty is non-investment grade | | | 36 | | | 13 | | | 23 | |
Counterparty has no external rating | | | 78 | | | 9 | | | 69 | |
| | | | | | | | | | |
Receivables without netting agreements in place: | | | | | | | | | | |
Counterparty is investment grade | | | 16 | | | 15 | | | 1 | |
Counterparty is non-investment grade | | | 6 | | | - | | | 6 | |
Counterparty has no external rating | | | - | | | - | | | - | |
Amount recorded on balance sheet | | $ | 514 | | $ | 319 | | $ | 195 | |
Gross payables | | As of: | | | |
In millions | | Dec. 31, 2004 | | Dec. 31, 2003 | | Change | |
Payables with netting agreements in place: | | | | | | | | | | |
Counterparty is investment grade | | $ | 291 | | $ | 206 | | $ | 85 | |
Counterparty is non-investment grade | | | 45 | | | 31 | | | 14 | |
Counterparty has no external rating | | | 139 | | | 45 | | | 94 | |
| | | | | | | | | | |
Payables without netting agreements in place: | | | | | | | | | | |
Counterparty is investment grade | | | 40 | | | 29 | | | 11 | |
Counterparty is non-investment grade | | | 6 | | | 3 | | | 3 | |
Counterparty has no external rating | | | - | | | 15 | | | (15 | ) |
Amount recorded on balance sheet | | $ | 521 | | $ | 329 | | $ | 192 | |
Energy Investments SouthStar has established the following credit guidelines and risk management practices for each customer type
· | SouthStar scores firm residential and small commercial customers using a national reporting agency and enrolls, without security, only those customers that meet or exceed SouthStar’s credit threshold. |
· | SouthStar investigates potential interruptible and large commercial customers through reference checks, review of publicly available financial statements and review of commercially available credit reports. |
· | SouthStar assigns physical wholesale counterparties an internal credit rating and credit limit prior to entering into a physical transaction based on their Moody’s, S&P and Fitch rating, commercially available credit reports and audited financial statements. |
Consolidated Balance Sheets - Assets
| | As of: | | | As of: | |
In millions | | December 31, 2004 | | December 31, 2003 | | | December 31, 2005 | | December 31, 2004 | |
Current assets | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 49 | | $ | 17 | | | $ | 30 | | $ | 49 | |
Receivables | | | | | | | | | | | | | | |
Energy marketing | | | 514 | | | 319 | | | | 675 | | | 514 | |
Gas | | | 217 | | | 65 | | | | 303 | | | 180 | |
Unbilled revenues | | | | 246 | | | 189 | |
Other | | | 21 | | | 12 | | | | 11 | | | 21 | |
Less allowance for uncollectible accounts | | | (15 | ) | | (2 | ) | | | (15 | ) | | (15 | ) |
Total receivables | | | 737 | | | 394 | | | | 1,220 | | | 889 | |
Income tax receivable | | | 29 | | | - | | |
Unbilled revenues | | | 152 | | | 40 | | |
Inventories | | | | | | | | | | | | | | |
Natural gas stored underground | | | 320 | | | 198 | | | | 509 | | | 320 | |
Other | | | 12 | | | 12 | | | | 34 | | | 12 | |
Total inventories | | | 332 | | | 210 | | | | 543 | | | 332 | |
Energy marketing and risk management assets | | | 38 | | | 13 | | | | 103 | | | 44 | |
Unrecovered environmental remediation costs - current portion | | | 27 | | | 24 | | | | 31 | | | 27 | |
Unrecovered pipeline replacement program costs - current portion | | | 24 | | | 22 | | | | 27 | | | 24 | |
Unrecovered seasonal rates | | | 11 | | | 11 | | |
Other current assets | | | 58 | | | 11 | | | | 78 | | | 89 | |
Total current assets | | | 1,457 | | | 742 | | | | 2,032 | | | 1,454 | |
Property, plant and equipment | | | | | | | | | | | | | | |
Property, plant and equipment | | | 4,615 | | | 3,390 | | | | 4,791 | | | 4,615 | |
Less accumulated depreciation | | | 1,437 | | | 1,045 | | | | 1,520 | | | 1,437 | |
Property, plant and equipment-net | | | 3,178 | | | 2,345 | | |
Property, plant and equipment -- net | | | | 3,271 | | | 3,178 | |
Deferred debits and other assets | | | | | | | | | | | | | | |
Goodwill | | | 354 | | | 184 | | | | 422 | | | 354 | |
Unrecovered pipeline replacement program costs | | | 337 | | | 410 | | | | 276 | | | 337 | |
Unrecovered environmental remediation costs | | | 173 | | | 155 | | | | 165 | | | 173 | |
Investments in equity interests | | | 14 | | | 101 | | |
Unrecovered postretirement benefit costs | | | 14 | | | 9 | | |
Other | | | 113 | | | 26 | | | | 85 | | | 141 | |
Total deferred debits and other assets | | | 1,005 | | | 885 | | | | 948 | | | 1,005 | |
Total assets | | $ | 5,640 | | $ | 3,972 | | | $ | 6,251 | | $ | 5,637 | |
See Notes to Consolidated Financial Statements.
AGL Resources Inc.
Consolidated Balance Sheets - Liabilities and Capitalization
| | As of: | | | As of: | |
In million, except share amounts | | December 31, 2004 | | December 31, 2003 | | |
In millions, except share amounts | | | December 31, 2005 | | December 31, 2004 | |
Current liabilities | | | | | | | | | | |
Energy marketing trade payable | | $ | 521 | | $ | 329 | | | $ | 775 | | $ | 521 | |
Short-term debt | | | 334 | | | 306 | | | | 522 | | | 334 | |
Accounts payable-trade | | | 207 | | | 74 | | |
Accounts payable - trade | | | | 264 | | | 207 | |
Energy marketing and risk management liabilities - current portion | | | | 101 | | | 15 | |
Customer deposits | | | | 42 | | | 50 | |
Accrued wages and salaries | | | | 43 | | | 49 | |
Accrued interest | | | | 32 | | | 28 | |
Deferred purchased gas adjustment | | | | 36 | | | 60 | |
Accrued pipeline replacement program costs - current portion | | | 85 | | | 82 | | | | 30 | | | 85 | |
Customer deposits | | | 50 | | | 19 | | |
Deferred purchased gas adjustment | | | 37 | | | 30 | | |
Accrued interest | | | 28 | | | 21 | | |
Accrued environmental remediation costs - current portion | | | 27 | | | 40 | | | | 13 | | | 27 | |
Accrued wages and salaries | | | 23 | | | 18 | | |
Energy marketing and risk management liabilities - current portion | | | 15 | | | 17 | | |
Accrued taxes | | | 14 | | | 15 | | |
Current portion of long-term debt | | | - | | | 77 | | |
Other current liabilities | | | 136 | | | 20 | | | | 81 | | | 98 | |
Total current liabilities | | | 1,477 | | | 1,048 | | | | 1,939 | | | 1,474 | |
Accumulated deferred income taxes | | | 437 | | | 376 | | | | 423 | | | 437 | |
Long-term liabilities | | | | | | | | | | | | | | |
Accrued pipeline replacement program costs | | | 242 | | | 323 | | | | 235 | | | 242 | |
Accrued postretirement benefit costs | | | 58 | | | 51 | | | | 54 | | | 58 | |
Accumulated removal costs | | | 94 | | | 102 | | | | 94 | | | 94 | |
Accrued environmental remediation costs | | | 63 | | | 43 | | | | 84 | | | 63 | |
Accrued pension obligations | | | 84 | | | 39 | | | | 88 | | | 84 | |
Accrued pipeline demand charges | | | 38 | | | - | | |
Other long-term liabilities | | | 30 | | | 11 | | | | 182 | | | 141 | |
Total long-term liabilities | | | 609 | | | 569 | | | | 737 | | | 682 | |
Deferred credits | | | | | | | | |
Unamortized investment tax credit | | | 20 | | | 19 | | |
Regulatory tax liability | | | 12 | | | 12 | | |
Other deferred credits | | | 41 | | | 47 | | |
Total deferred credits | | | 73 | | | 78 | | |
Commitments and contingencies(see Note 10) | | | | | | | | | | | | | | |
Minority interest | | | 36 | | | - | | | | 38 | | | 36 | |
Capitalization | | | | | | | | | | | | | | |
Long-term debt | | | 1,623 | | | 956 | | | | 1,615 | | | 1,623 | |
Common shareholders’ equity, $5 par value; 750,000,000 shares authorized (see accompanying statements of consolidated common shareholders’ equity) | | | 1,385 | | | 945 | | |
Common shareholders’ equity, $5 par value; 750 million shares authorized; 77.7 million and 76.7 million shares outstanding at December 31, 2005 and 2004 | | | | 1,499 | | | 1,385 | |
Total capitalization | | | 3,008 | | | 1,901 | | | | 3,114 | | | 3,008 | |
Total liabilities and capitalization | | $ | 5,640 | | $ | 3,972 | | | $ | 6,251 | | $ | 5,637 | |
See Notes to Consolidated Financial Statements.
Statements of Consolidated Income
| | Years ended December 31, | | | Years ended December 31, | |
In millions, except per share amounts | | 2004 | | 2003 | | 2002 | | | 2005 | | 2004 | | 2003 | |
Operating revenues | | $ | 1,832 | | $ | 983 | | $ | 877 | | | $ | 2,718 | | $ | 1,832 | | $ | 983 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | |
Cost of gas | | | 994 | | | 339 | | | 268 | | | | 1,626 | | | 995 | | | 339 | |
Operation and maintenance | | | 377 | | | 283 | | | 274 | | | | 477 | | | 377 | | | 283 | |
Depreciation and amortization | | | 99 | | | 91 | | | 89 | | | | 133 | | | 99 | | | 91 | |
Taxes other than income taxes | | | 30 | | | 28 | | | 29 | | | | 40 | | | 29 | | | 28 | |
Total operating expenses | | | 1,500 | | | 741 | | | 660 | | | | 2,276 | | | 1,500 | | | 741 | |
Gain on sale of Caroline Street campus | | | - | | | 16 | | | - | | | | - | | | - | | | 16 | |
Operating income | | | 332 | | | 258 | | | 217 | | | | 442 | | | 332 | | | 258 | |
Equity in earnings of SouthStar | | | - | | | 46 | | | 27 | | |
Other (loss) income | | | - | | | (6 | ) | | 3 | | |
Equity in earnings of SouthStar Energy Services LLC | | | | - | | | - | | | 46 | |
Other losses | | | | (1 | ) | | - | | | (6 | ) |
Minority interest | | | (18 | ) | | - | | | - | | | | (22 | ) | | (18 | ) | | - | |
Interest expense | | | (71 | ) | | (75 | ) | | (86 | ) | | | (109 | ) | | (71 | ) | | (75 | ) |
Earnings before income taxes | | | 243 | | | 223 | | | 161 | | | | 310 | | | 243 | | | 223 | |
Income taxes | | | 90 | | | 87 | | | 58 | | | | 117 | | | 90 | | | 87 | |
Income before cumulative effect of change in accounting principle | | | 153 | | | 136 | | | 103 | | | | 193 | | | 153 | | | 136 | |
Cumulative effect of change in accounting principle, net of $5 in taxes | | | - | | | (8 | ) | | - | | | | - | | | - | | | (8 | ) |
Net income | | $ | 153 | | $ | 128 | | $ | 103 | | | $ | 193 | | $ | 153 | | $ | 128 | |
| | | | | | | | | | | |
Basic earnings per common share: | | | | | | | | | | | |
Per Common Share Data | | | | | | | | | | | |
Basic | | | | | | | | | | | |
Income before cumulative effect of change in accounting principle | | $ | 2.30 | | $ | 2.15 | | $ | 1.84 | | | $ | 2.50 | | $ | 2.30 | | $ | 2.15 | |
Cumulative effect of change in accounting principle | | | - | | | (0.12 | ) | | - | | | | - | | | - | | | (0.12 | ) |
Basic earnings per common share | | $ | 2.30 | | $ | 2.03 | | $ | 1.84 | | | $ | 2.50 | | $ | 2.30 | | $ | 2.03 | |
| | | | | | | | | | | |
Fully diluted earnings per common share: | | | | | | | | | | | |
Fully diluted | | | | | | | | | | | |
Income before cumulative effect of change in accounting principle | | $ | 2.28 | | $ | 2.13 | | $ | 1.82 | | | $ | 2.48 | | $ | 2.28 | | $ | 2.13 | |
Cumulative effect of change in accounting principle | | | - | | | (0.12 | ) | | - | | | | - | | | - | | | (0.12 | ) |
Fully diluted earnings per common share | | $ | 2.28 | | $ | 2.01 | | $ | 1.82 | | | $ | 2.48 | | $ | 2.28 | | $ | 2.01 | |
| | | | | | | | | | | |
Weighted average number of common shares outstanding: | | | | | | | | | | | |
Cash dividends paid per common share | | | $ | 1.30 | | $ | 1.15 | | $ | 1.11 | |
Weighted average number of common shares outstanding | | | | | | | | | | | |
Basic | | | 66.3 | | | 63.1 | | | 56.1 | | | | 77.3 | | | 66.3 | | | 63.1 | |
Fully diluted | | | 67.0 | | | 63.7 | | | 56.6 | | | | 77.8 | | | 67.0 | | | 63.7 | |
See Notes to Consolidated Financial Statements.
Statements of Consolidated Common Shareholders’ Equity
| | | | | | | | | | Other | | Shares Held | | | |
| | Common Stock | | Premium on | | Earnings | | Comprehensive | | in Treasury | | | |
In millions, except per share amounts | | Shares | | Amount | | Common Stock | | Reinvested | | Income | | and Trust | | Total | |
Balance as of December 31, 2001 | | | 57.8 | | $ | 289 | | $ | 204 | | $ | 237 | | | ($1 | ) | | ($39 | ) | $ | 690 | |
Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | |
Net income | | | - | | | - | | | - | | | 103 | | | - | | | - | | | 103 | |
Other comprehensive income (OCI) - loss resulting from unfunded pension obligation (net of tax benefit of $31) | | | - | | | - | | | - | | | - | | | (48 | ) | | - | | | (48 | ) |
Total comprehensive income | | | | | | | | | | | | | | | | | | | | | 55 | |
Dividends on common stock($1.08 per share) | | | - | | | - | | | - | | | (61 | ) | | - | | | - | | | (61 | ) |
Benefit, stock compensation, dividend reinvestment and stock purchase plans (net of tax benefit of $1) | | | - | | | - | | | 6 | | | - | | | - | | | 20 | | | 26 | |
Balance as of December 31, 2002 | | | 57.8 | | | 289 | | | 210 | | | 279 | | | (49 | ) | | (19 | ) | | 710 | |
Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | |
Net income | | | - | | | - | | | - | | | 128 | | | - | | | - | | | 128 | |
OCI - Gain resulting from unfunded pension obligation (net of tax of $6) | | | - | | | - | | | - | | | - | | | 8 | | | - | | | 8 | |
Unrealized gain from equity investments hedging activities (net of tax ) | | | - | | | - | | | - | | | - | | | 1 | | | - | | | 1 | |
Total comprehensive income | | | | | | | | | | | | | | | | | | | | | 137 | |
Dividends on common stock ($1.11 per share) | | | - | | | - | | | - | | | (70 | ) | | - | | | - | | | (70 | ) |
Issuance of common shares: | | | | | | | | | | | | | | | | | | | | | | |
Equity offering on February 14, 2003 | | | 6.7 | | | 32 | | | 105 | | | - | | | - | | | - | | | 137 | |
Benefit, stock compensation, dividend reinvestment and stock purchase plans (net of tax benefit of $2) | | | - | | | 1 | | | 11 | | | - | | | - | | | 19 | | | 31 | |
Balance as of December 31, 2003 | | | 64.5 | | | 322 | | | 326 | | | 337 | | | (40 | ) | | - | | | 945 | |
Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | |
Net income | | | - | | | - | | | - | | | 153 | | | - | | | - | | | 153 | |
OCI - Loss resulting from unfunded pension obligation (net of tax benefit of $7) | | | - | | | - | | | - | | | - | | | (11 | ) | | - | | | (11 | ) |
Unrealized gain from hedging activities (net of tax of $2) | | | - | | | - | | | - | | | - | | | 4 | | | - | | | 4 | |
Other | | | - | | | - | | | - | | | - | | | 1 | | | - | | | 1 | |
Total comprehensive income | | | | | | | | | | | | | | | | | | | | | 147 | |
Dividends on common stock ($1.15 per share) | | | - | | | - | | | - | | | (75 | ) | | - | | | - | | | (75 | ) |
Issuance of common shares: | | | | | | | | | | | | | | | | | | | | | | |
Equity offering on November 24, 2004 | | | 11.0 | | | 55 | | | 277 | | | - | | | - | | | - | | | 332 | |
Benefit, stock compensation, dividend reinvestment and stock purchase plans (net of tax benefit of $5) | | | 1.2 | | | 7 | | | 29 | | | - | | | - | | | - | | | 36 | |
Balance as of December 31, 2004 | | | 76.7 | | $ | 384 | | $ | 632 | | $ | 415 | | | ($46 | ) | $ | - | | $ | 1,385 | |
| | | | | | | | | | Other | | Shares Held | | | |
| | Common Stock | | Premium on | | Earnings | | Comprehensive | | in Treasury | | | |
In millions, except per share amounts | | Shares | | Amount | | Common Stock | | Reinvested | | Income | | and Trust | | Total | |
Balance as of December 31, 2002 | | | 57.8 | | $ | 289 | | $ | 210 | | $ | 279 | | $ | (49 | ) | $ | (19 | ) | $ | 710 | |
Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | |
Net income | | | - | | | - | | | - | | | 128 | | | - | | | - | | | 128 | |
Other comprehensive income (OCI) - gain resulting from unfunded pension obligation (net of tax of $6) | | | - | | | - | | | - | | | - | | | 8 | | | - | | | 8 | |
Unrealized gain from equity investment hedging activities (net of tax ) | | | - | | | - | | | - | | | - | | | 1 | | | - | | | 1 | |
Total comprehensive income | | | | | | | | | | | | | | | | | | | | | 137 | |
Dividends on common stock ($1.11 per share) | | | - | | | - | | | - | | | (70 | ) | | - | | | - | | | (70 | ) |
Issuance of common shares: | | | | | | | | | | | | | | | | | | | | | | |
Equity offering on February 14, 2003 | | | 6.7 | | | 32 | | | 105 | | | - | | | - | | | - | | | 137 | |
Benefit, stock compensation, dividend reinvestment and stock purchase plans (net of tax benefit of $2) | | | - | | | 1 | | | 11 | | | - | | | - | | | 19 | | | 31 | |
Balance as of December 31, 2003 | | | 64.5 | | | 322 | | | 326 | | | 337 | | | (40 | ) | | - | | | 945 | |
Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | |
Net income | | | - | | | - | | | - | | | 153 | | | - | | | - | | | 153 | |
OCI - loss resulting from unfunded pension obligation (net of tax benefit of $7) | | | - | | | - | | | - | | | - | | | (11 | ) | | - | | | (11 | ) |
Unrealized gain from hedging activities (net of tax of $2) | | | - | | | - | | | - | | | - | | | 4 | | | - | | | 4 | |
Other | | | - | | | - | | | - | | | - | | | 1 | | | - | | | 1 | |
Total comprehensive income | | | | | | | | | | | | | | | | | | | | | 147 | |
Dividends on common stock ($1.15 per share) | | | - | | | - | | | - | | | (75 | ) | | - | | | - | | | (75 | ) |
Issuance of common shares: | | | | | | | | | | | | | | | | | | | | | | |
Equity offering on November 24, 2004 | | | 11.0 | | | 55 | | | 277 | | | - | | | - | | | - | | | 332 | |
Benefit, stock compensation, dividend reinvestment and stock purchase plans (net of tax benefit of $5) | | | 1.2 | | | 7 | | | 29 | | | - | | | - | | | - | | | 36 | |
Balance as of December 31, 2004 | | | 76.7 | | | 384 | | | 632 | | | 415 | | | (46 | ) | | - | | | 1,385 | |
Comprehensive income: | | | | | | | | | | | | | | | | | | | | | | |
Net income | | | - | | | - | | | - | | | 193 | | | - | | | - | | | 193 | |
OCI - loss resulting from unfunded pension obligation (net of tax benefit of $3) | | | - | | | - | | | - | | | - | | | (5 | ) | | - | | | (5 | ) |
Unrealized loss from hedging activities (net of tax benefit of $1) | | | - | | | - | | | - | | | - | | | (2 | ) | | - | | | (2 | ) |
Total comprehensive income | | | | | | | | | | | | | | | | | | | | | 186 | |
Dividends on common stock ($1.30 per share) | | | - | | | - | | | - | | | (100 | ) | | - | | | - | | | (100 | ) |
Issuance of common shares: | | | | | | | | | | | | | | | | | | | | | | |
Benefit, stock compensation, dividend reinvestment and stock purchase plans (net of tax benefit of $9) | | | 1.1 | | | 5 | | | 23 | | | - | | | - | | | - | | | 28 | |
Balance as of December 31, 2005 | | | 77.8 | | $ | 389 | | $ | 655 | | $ | 508 | | $ | (53 | ) | $ | - | | $ | 1,499 | |
See Notes to Consolidated Financial Statements.
Statements of Consolidated Cash Flows
| | Years ended December 31, | | | Years ended December 31, | |
In millions | | 2004 | | 2003 | | 2002 | | | 2005 | | 2004 | | 2003 | |
Cash flows from operating activities | | | | | | | | | | | | | | |
Net income | | $ | 153 | | $ | 128 | | $ | 103 | | | $ | 193 | | $ | 153 | | $ | 128 | |
Adjustments to reconcile net income to net cash flow provided by operating activities | | | | | | | | | | | | | | | | | | | | |
Depreciation and amortization | | | 99 | | | 91 | | | 89 | | | | 133 | | | 99 | | | 91 | |
Minority interest | | | | 22 | | | 18 | | | - | |
Change in risk management assets and liabilities | | | | 27 | | | (32 | ) | | (1 | ) |
Deferred income taxes | | | 81 | | | 55 | | | 82 | | | | 17 | | | 65 | | | 55 | |
Cumulative effect of change in accounting principle | | | - | | | 13 | | | - | | | | - | | | - | | | 13 | |
Cash received from equity interests | | | - | | | 40 | | | - | | | | - | | | - | | | 40 | |
Equity in earnings of unconsolidated subsidiaries | | | (2 | ) | | (47 | ) | | (27 | ) | | | - | | | (2 | ) | | (47 | ) |
Gain on sale of Caroline Street campus | | | - | | | (16 | ) | | - | | | | - | | | - | | | (16 | ) |
Change in risk management assets and liabilities | | | (27 | ) | | (1 | ) | | (3 | ) | |
Other non cash adjustments | | | | 12 | | | 11 | | | 10 | |
Changes in certain assets and liabilities | | | | | | | | | | | | | | | | | | | | |
Payables | | | 247 | | | 61 | | | 244 | | | | 311 | | | 247 | | | 61 | |
ERC - net | | | (13 | ) | | (6 | ) | | (18 | ) | |
Inventories | | | (28 | ) | | (91 | ) | | 42 | | | | (211 | ) | | (28 | ) | | (91 | ) |
Receivables | | | (264 | ) | | (67 | ) | | (269 | ) | | | (338 | ) | | (264 | ) | | (67 | ) |
Other - net | | | 41 | | | (38 | ) | | 43 | | | | (88 | ) | | 20 | | | (54 | ) |
Net cash flow provided by operating activities | | | 287 | | | 122 | | | 286 | | | | 78 | | | 287 | | | 122 | |
Cash flows from investing activities | | | | | | | | | | | | | | | | | | | | |
Acquisition of NUI, net of cash acquired | | | (116 | ) | | - | | | - | | |
Property, plant and equipment expenditures | | | (264 | ) | | (158 | ) | | (187 | ) | |
Acquisition of Jefferson Island | | | (90 | ) | | - | | | - | | |
Purchase of Dynegy’s 20% ownership interest in SouthStar | | | - | | | (20 | ) | | - | | |
Expenditures for property, plant and equipment | | | | (267 | ) | | (264 | ) | | (158 | ) |
Sale of Saltville Gas Storage Company, LLC | | | | 66 | | | - | | | - | |
Acquisition of NUI Corporation, net of cash acquired | | | | - | | | (116 | ) | | - | |
Acquisition of Jefferson Island Storage & Hub, LLC | | | | - | | | (90 | ) | | - | |
Purchase of Dynegy Inc.’s 20% ownership interest in SouthStar Energy Services LLC | | | | - | | | - | | | (20 | ) |
Cash received from sale of Caroline Street campus | | | - | | | 23 | | | - | | | | - | | | - | | | 23 | |
Sale of US Propane | | | 31 | | | - | | | - | | |
Cash received from equity interests | | | - | | | 2 | | | 27 | | |
Sale of US Propane LP | | | | - | | | 31 | | | - | |
Other | | | 17 | | | 8 | | | (1 | ) | | | 7 | | | 17 | | | 10 | |
Net cash flow used in investing activities | | | (422 | ) | | (145 | ) | | (161 | ) | | | (194 | ) | | (422 | ) | | (145 | ) |
Cash flows from financing activities | | | | | | | | | | | | | | | | | | | | |
Issuances of Senior Notes | | | 450 | | | 225 | | | - | | |
Net payments and borrowings of short-term debt | | | | 188 | | | (480 | ) | | (82 | ) |
Sale of common stock | | | | 28 | | | 36 | | | 12 | |
Distribution to minority interest | | | | (19 | ) | | (14 | ) | | - | |
Dividends paid on common shares | | | | (100 | ) | | (75 | ) | | (70 | ) |
Issuances of senior notes | | | | - | | | 450 | | | 225 | |
Equity offering | | | 332 | | | 137 | | | - | | | | - | | | 332 | | | 137 | |
Sale of treasury shares | | | - | | | 19 | | | 20 | | | | - | | | - | | | 19 | |
Sale of common stock | | | 36 | | | 12 | | | 6 | | |
Dividends paid on common shares | | | (75 | ) | | (70 | ) | | (53 | ) | |
Net payments and borrowings of short-term debt | | | (480 | ) | | (82 | ) | | 4 | | |
Distribution to minority interest | | | (14 | ) | | - | | | - | | |
Payments of Medium-Term notes | | | (82 | ) | | (207 | ) | | (93 | ) | |
Payments of medium-term notes | | | | - | | | (82 | ) | | (207 | ) |
Other | | | - | | | (3 | ) | | (8 | ) | | | - | | | - | | | (3 | ) |
Net cash flow provided by (used in) financing activities | | | 167 | | | 31 | | | (124 | ) | |
Net increase in cash and cash equivalents | | | 32 | | | 8 | | | 1 | | |
Net cash flow provided by financing activities | | | | 97 | | | 167 | | | 31 | |
Net (decrease) increase in cash and cash equivalents | | | | (19 | ) | | 32 | | | 8 | |
Cash and cash equivalents at beginning of period | | | 17 | | | 9 | | | 8 | | | | 49 | | | 17 | | | 9 | |
Cash and cash equivalents at end of period | | $ | 49 | | $ | 17 | | $ | 9 | | | $ | 30 | | $ | 49 | | $ | 17 | |
Cash paid during the period for | | | | | | | | | | | | | | | | | | | | |
Interest (net of allowance for funds used during construction) | | $ | 50 | | $ | 60 | | $ | 73 | | |
Interest (net of allowance for funds used during construction of $2 million for the years ended December 31, 2005, 2004 and 2003, respectively) | | | $ | 89 | | $ | 50 | | $ | 60 | |
Income taxes | | | 27 | | | 23 | | | 15 | | | | 89 | | | 27 | | | 23 | |
See Notes to Consolidated Financial Statements.
> Note 1
Accounting Policies and Methods of Application
General
AGL Resources Inc. is an energy services holding company that conducts substantially all of its operations through its subsidiaries. Unless the context requires otherwise, references to “we,” “us,” “our” or the “company” are intended to mean consolidated AGL Resources Inc. and its subsidiaries (AGL Resources). We have prepared the accompanying consolidated financial statements under the rules of the Securities and Exchange Commission (SEC).
Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies, including state public service commissions and the SEC. Furthermore, For a substantial portion of our consolidated assets, earnings and cash flow is derived from the operation of regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. On April 1, 2004, we received approval from the SEC, under the Public Utility Holding Company Act of 1935 (PUHCA), for the renewal of our financing authority to issue securities through April 2007. For aglossary of key terms andreferenced accounting standards, see pages 4-5.page 4.
Basis of Presentation
Our consolidated financial statements as of and for the periods ended December 31, 20042005 include our accounts, the accounts of our majority-owned and controlled subsidiaries and the accounts of variable interest entities for which we are the primary beneficiary. This means that our accounts are combined with the subsidiaries’ accounts. CertainWe have reclassified certain amounts from prior periods have been reclassified to conform to the current-period presentation. AnyWe have eliminated any intercompany profits and transactions between segments have been eliminated in consolidation; however, we have not eliminated intercompany profits are not eliminated when such amounts are probable of recovery under the affiliates’ rate regulation process. On November 30, 2004, we completed our acquisition of NUI Corporation (NUI); for more information see Note 2.
As of January 1, 2004, our consolidated financial statements include the accounts of SouthStar Energy Services LLC (SouthStar), a variable interest entity of which we are the primary beneficiary. Prior to January 1, 2004, we accounted for our 70% noncontrolling financial ownership interest in SouthStar usingWe use the equity method of accounting. Under the equity method, our ownershipwhen we have a 20% to 50% voting interest in SouthStar was reported as an investment within our consolidated balance sheets, and our share of SouthStar’s earnings was reported in our consolidated statements of income as a component of other income. We utilize the equity method to account for and report investments wherewhen we exercise significant influence but do not control and wherewhen we are not the primary beneficiary as defined by Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). FIN 46 was revisedrequires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities.
We currently own a noncontrolling 70% financial interest in SouthStar, and Piedmont Natural Gas Company (Piedmont) owns the remaining 30%. Our 70% interest is noncontrolling because all significant management decisions require approval by both owners. Prior to 2004, we accounted for our 70% noncontrolling financial ownership interest in SouthStar using the equity method of accounting because SouthStar did not meet the definition of a variable interest entity under FIN 46. Under the equity method, we reported our ownership interest in SouthStar as an investment in our consolidated balance sheets, and we reported our share of SouthStar’s earnings based on our ownership percentage in our statements of consolidated income as a component of other income. However, because SouthStar’s results of operations and financial condition were material to our financial results in 2003, we present below the summarized amounts for 100% of SouthStar. These results are not comparable with our reported earnings or losses from SouthStar in 2003.
In millions | | 2003 | |
Revenues | | $ | 746 | |
Operating margin | | | 124 | |
Operating income | | | 63 | |
Net income from continuing operations | | | 63 | |
In December 2003, the FASB revised FIN 46 (FIN 46R); consequently, to add the following conditions for determining whether an entity is a variable interest entity:
· | the voting rights of some investors are not proportional to their obligations to absorb the expected losses of the entity, their rights to receive the expected residual returns of the entity, or both |
· | substantially all the entity’s activities (for example, purchasing products and additional capital) either involve or are conducted on behalf of an investor that has disproportionately fewer voting rights |
In 2004, we determined that SouthStar was a variable interest entity as defined in FIN 46R because our equal voting rights with Piedmont are not proportional to our economic obligation to absorb 75% of any losses or residual returns from SouthStar. In addition, SouthStar obtains substantially all its transportation capacity for delivery of natural gas through our wholly owned subsidiary, Atlanta Gas Light Company (Atlanta Gas Light).
As of January 1, 2004, we adopted FIN 46R and consolidated all SouthStar’s accounts with our subsidiaries’ accounts and eliminated any intercompany balances between segments. For more discussionWe recorded Piedmont’s portion of FIN 46R and the impact of its adoption onSouthStar’s earnings as a minority interest in our consolidated financial statements see Note 3.of income, and we recorded Piedmont’s portion of SouthStar’s capital as a minority interest in our consolidated balance sheet.
Our equity method investments generally include entities where we have a 20%
Prior to 50% voting interest. In 2004, our investments in equity interests was composedsale of our 50% ownership in Saltville Gas Storage Company, LLC (Saltville) in August 2005, we used the equity method to account for and report our 50% interest in Saltville. Saltville was a joint venture with a subsidiary of Duke Energy Corporation to develop a high-deliverability natural gas storage facility in Saltville, Virginia. We used the equity method because we exercised significant influence over but did not control the entity and because we were not the primary beneficiary as defined by FIN 46R.
Cash and Cash Equivalents
Our cash and cash equivalents consist primarily of cash on deposit, money market accounts and certificates of deposit with original maturities of three months or less.
Receivables and allowanceAllowance for uncollectible accountsUncollectible Accounts
Our receivables consist of natural gas sales and transportation services billed to residential, commercial, industrial and other customers. Customers are billedWe bill customers monthly, and accounts receivable are due within 30 days. For the majority of our receivables, we establish an allowance for doubtful accounts based on our collection experience. On certain other receivables where we are aware of a specific customer’s inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be different. Circumstances that could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are writtenWe write off accounts once they are deemedwe deem them to be uncollectible.
Inventories
OurFor our regulated subsidiaries, we record natural gas inventories are accountedstored underground at weighted average costs, except for usinggas stored by Atlanta Gas Light on behalf of SouthStar. For our nonregulated subsidiaries, primarily Sequent Energy Management, L.P. (Sequent), SouthStar and Pivotal Jefferson Island, L.P. (Pivotal Jefferson Island), we account for natural gas inventory at the lower of weighted average cost method.or market. For volumes of gas stored by Sequent under park and loan arrangements that are payable or to be repaid at predetermined dates to third parties, we record the inventory at fair value. Materials and supplies inventories are stated at the lower of average cost or market. At December 31, 2004, Sequent’s natural gas inventory for reservoir and salt dome storage was recorded on an accrual basis. At December 31, 2004, Sequent’s inventory held under park and loan arrangements was recorded at the lower of average cost or market. However, for those park and loan arrangements that are payable or to be repaid at determinable dates to third parties, the inventory was recorded at fair value.
In Georgia’s competitive environment, Marketers—that is, marketers who are certificated by the Georgia Public Service Commission (Georgia Commission) to sell retail natural gas in Georgia—Georgia — including SouthStar, the marketing affiliate of Atlanta Gas Light marketing affiliate SouthStar,— began selling natural gas in 1998 to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation that provides for this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. Atlanta Gas Light assigns, on a monthly basis, the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory.
Property, Plant and Equipment
A summary of our property, plant and equipment (PP&E) by classification as of December 31, 2005 and 2004 is indicated in the following table.
In millions | | 2005 | | 2004 | |
Transmission & distribution | | $ | 3,867 | | $ | 3,731 | |
Storage | | | 209 | | | 206 | |
Other | | | 476 | | | 418 | |
Construction work in progress | | | 239 | | | 260 | |
Total gross PP&E | | | 4,791 | | | 4,615 | |
Accumulated depreciation | | | (1,520 | ) | | (1,437 | ) |
Total net PP&E | | $ | 3,271 | | $ | 3,178 | |
Distribution Operations Property, plant and equipment expenditures consist of property and equipment that is in use, being held for future use and under construction. It is reportedWe report it at its original cost, which includes
· | construction overhead costs |
· | an allowance for funds used during construction which represents the estimated cost of funds used to finance the construction of major projects and are capitalized in the rate base for ratemaking purposes when the completed projects are placed in service |
PropertyWe charge property retired or otherwise disposed of is charged to accumulated depreciation.depreciation since such costs are recovered in rates.
Retail Energy Operations, Wholesale Services, Energy Investments and Corporate Property, plant and equipment expenditures include property that is in use and under construction, and is reportedwe report it at cost. AWe record a gain or loss is recorded for retired or otherwise disposed of property.
Depreciation Expense
We compute depreciation expense for distribution operations by applying composite, straight-line rates (approved by the state regulatory agencies) to the investment in depreciable property. The composite straight-line depreciation rate for depreciable property excluding transportation equipment for Atlanta Gas Light, Virginia Natural Gas, Inc. (Virginia Natural Gas) and Chattanooga Gas Company (Chattanooga Gas) was approximately 2.6% during 2005, 2.6% during 2004 and 2.7% during 2003. The composite, straight-line rate for Elizabethtown Gas, Florida City Gas and Elkton Gas was approximately 3.1% during 2005 and was 3.25% for December 2004. We depreciate transportation equipment on a straight-line basis over a period of 5 to 10 years. We compute depreciation expense for other segments on a straight-line basis over a period of 1 to 35 years.
Allowance for Funds Used During Construction (AFUDC)
The applicable state regulatory agencies authorize Atlanta Gas Light, Elizabethtown Gas and Chattanooga Gas to record the cost of debt and equity funds as part of the cost of construction projects in our consolidated balance sheets and as AFUDC in the statements of consolidated income. The Georgia Commission has authorized a rate of 8.53%, and the Tennessee Regulatory Authority has authorized a rate of 7.43%. The New Jersey Board of Public Utilities (NJBPU) has authorized a variable rate based on the FERC method of accounting for AFUDC. At December 31, 2005 the rate was 4.33%. The capital expenditures of our other regulated utilities do not qualify for AFUDC treatment.
Goodwill
We adopted SFASStatement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” (SFAS 142), effective October 1, 2001. Under SFAS 142, goodwill iswe no longer amortized.amortize goodwill. SFAS 142 further requires us to perform an initial goodwill impairment assessment in the year of adoption and annual impairment tests thereafter. We have included $354$422 million of goodwill in our consolidated balance sheets, of which $157$231 million is related to our acquisition of NUI Corporation (NUI) in November 2004 (see Note 2 for further details), $176; $170 million is related to our acquisition of Virginia Natural Gas Inc. (Virginia Natural Gas) in 2000, a decrease of $6 million from last year due to a deferred income tax adjustment made in 2005; $14 million is related to our acquisition of Jefferson Island Storage & Hub, LLC in October 20042004; and $7 million is related to our acquisition of Chattanooga Natural Gas Company in 1988.
We annually assess goodwill for impairment as of our fiscal year end at a reporting unit level which generally equates to our operating segments as discussed in Note 14, and have not recognized any impairment charges for the years ended December 31, 2005, 2004 2003 and 2002.2003. We also assess goodwill for impairment if events or changes in circumstances may indicate an impairment of goodwill exists. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded. We conduct this assessment principally through a review of financial results, changes in state and federal legislation and regulation, and the periodic regulatory filings for our regulated utilities.
Accumulated Deferred Income Taxes
The reporting of our assets and liabilities for financial accounting purposes differs from the reporting for income tax purposes. The principal differences between net income and taxable income relate to the timing of deductions, primarily due to the benefits of tax depreciation since assets arewe generally depreciateddepreciate assets for tax purposes over a shorter period of time than for book purposes. TheWe report the tax effects of depreciation and other differences in those items are reported as deferred income tax assets or liabilities in our consolidated balance sheets. Investment tax credits of approximately $20$19 million previously deducted for income tax purposes for Atlanta Gas Light, Chattanooga Gas and Elizabethtown Gas and have been deferred for financial accounting purposes and are being amortized as credits to income over the estimated lives of the related properties in accordance with regulatory requirements.
Revenues
Distribution Operations Revenues are recordedWe record revenues when services are provided to customers. Those revenues are based on rates approved by the regulatory state commissions of our utilities.
As required by the Georgia Commission, in July 1998, Atlanta Gas Light began billing Marketers in equal monthly installments for each residential, commercial and industrial customer’s distribution costs in equal monthly installments.costs. As required by the Georgia Commission, effective February 1, 2001, Atlanta Gas Light implemented a seasonal rate design for the calculation of each residential customer’s annual straight-fixed-variable (SFV) capacity charge, which is billed to Marketers and reflects the historic volumetric usage pattern for the entire residential class. Generally, this change results in residential customers being billed by Marketers for a higher capacity charge in the winter months and a lower charge in the summer months. This requirement has an operating cash flow impact but does not change revenue recognition. As a result, Atlanta Gas Light continues to recognize its residential SFV capacity revenues for financial reporting purposes in equal monthly installments.
Any difference between the billings under the seasonal rate design and the SFV revenue recognized is deferred and reconciled to actual billings on an annual basis. Atlanta Gas Light had unrecovered seasonal rates of approximately $11 million as of December 31, 20042005 and 20032004 (included as current assets in the consolidated balance sheets), related to the difference between the billings under the seasonal rate design and the SFV revenue recognized.
The Elizabethtown Gas, Virginia Natural Gas, Florida City Gas, Chattanooga Gas and ChattanoogaElkton Gas rate structures include volumetric rate designs that allow recovery of costs through gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Virginia Natural Gas and Chattanooga Gas recognize salesSales revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. In addition, revenues are recorded for estimated deliveries of gas, not yet billed to these customers, from the meter reading date to the end of the accounting period. These are included in the consolidated balance sheets as unbilled revenue. For other commercial and industrial customers and all wholesale customers, revenues are based uponon actual deliveries to the end of the period.
The tariffs for Elizabethtown Gas, Virginia Natural Gas and Chattanooga Gas contain weather normalization adjustments (WNA) that largely mitigate the impact of unusually cold or warm weather on customer billings and operating margin. The WNA’s purpose is to reduce the effect of weather on customer bills by reducing bills when winter weather is colder than normal and increasing bills when weather is warmer than normal.
Wholesale ServicesWholesale services’ revenues are recorded when services are provided to customers. Intercompany profits from sales between segments are eliminated in the corporate segment and are recognized as goods or services sold to end-use customers. Transactions that qualify as derivatives under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), are recorded at fair value with changes in fair value recorded as revenues in our statements of income.
Prior to 2003, in accordance with SFAS 133, we accounted for nonderivative energy and energy-related activities in accordance with Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10). Under these methods, we recorded energy commodity contracts (including physical transactions and financial instruments) at fair value and reflected unrealized gains and/or losses in earnings in the period of change. Effective January 1, 2003, we adopted EITF 02-03, “Issues Involved in Accounting for Contracts under EITF Issue No. 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities’” (EITF 02-03), which rescinded the provisions of EITF 98-10 and reached two general conclusions:
· | contracts that do not meet the definition of a derivative under SFAS 133 should not be marked to fair market value |
· | revenues should be shown in the statement of consolidated income net of costs associated with trading activities, whether or not the trades are physically settled |
As a result of our adoption of EITF 02-03, we adjusted the carrying value of our nonderivative trading instruments (principally storage capacity contracts) to zero and now account for them using the accrual method of accounting. In addition, we adjusted the value of our natural gas inventories used in wholesale services to the lower of average cost or market (they were previously recorded at fair value). This resulted in the cumulative effect of a change in accounting principle in our statements of consolidated income of $13 million ($8 million net of taxes). We also began reporting our trading activity on a net basis (revenues net of associated costs). This reclassification had no impact on our previously reported net income or shareholders’ equity.
Cost of Gas
WeExcluding Atlanta Gas Light, we charge our utility customers for the natural gas they consume using purchased gas adjustment (PGA) mechanisms set by the state regulatory agencies. Under the PGA, we defer (that is, include as a current asset or liability in the consolidated balance sheets and exclude from the statements of consolidated income) the difference between the actual cost of gas and what is collected from or billed to customers in a given period. The deferred amount is either billed or refunded to our customers.
customers prospectively through adjustments to the commodity rate.
Stock-based Compensation
We have several stock-based employee compensation plans and account for these plans under the recognition and measurement principles ofAccountingof Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25), and related interpretations. For our stock option plans, we generally do not reflect stock-based employee compensation cost in net income, as options for those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. For our stock appreciation rights, we reflect stock-based employee compensation cost based on the fair value of our common stock at the balance sheet date since these awards constitute a variable plan under APB 25. The following table illustrates the effect on our net income and earnings per share had we applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS 123):
In millions, except per share amounts | | 2004 | | 2003 | | 2002 | |
Net income, as reported | | $ | 153 | | $ | 128 | | $ | 103 | |
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect | | | (1 | ) | | (1 | ) | | (2 | ) |
Pro forma net income | | $ | 152 | | $ | 127 | | $ | 101 | |
| | | | | | | | | | |
Earnings per share: | | | | | | | | | | |
Basic-as reported | | $ | 2.30 | | $ | 2.03 | | $ | 1.84 | |
Basic-pro forma | | $ | 2.28 | | $ | 2.02 | | $ | 1.80 | |
| | | | | | | | | | |
Fully diluted-as reported | | $ | 2.28 | | $ | 2.01 | | $ | 1.82 | |
Fully diluted-pro forma | | $ | 2.26 | | $ | 2.00 | | $ | 1.79 | |
Depreciation Expense.
Depreciation expense for distribution operations is computed by applying composite, straight-line rates (approved by the state regulatory agencies) to the investment of depreciable property. Excluding the utilities acquired from NUI, distribution operations’ composite straight-line depreciation rate for depreciable property excluding transportation equipment was approximately 2.6% during 2004, 2.7% during 2003 and 2.8% during 2002. The composite, straight-line rate for the utilities acquired from NUI was 3.25%. As of May 1, 2002, the Georgia Commission required a decrease of depreciation rates for Atlanta Gas Light, which decreased depreciation expense by $6 million in 2002 and approximately $10 million annually on a going forward basis. We depreciate transportation equipment on a straight-line basis over a period of 5 to 10 years. We compute depreciation expense for other segments on a straight-line basis over a period of 1 to 35 years.
Allowance for Funds Used During Construction (AFUDC)
The applicable state regulatory agencies authorize Atlanta Gas Light, Elizabethtown Gas and Chattanooga Gas to record the cost of debt and equity funds as part of the cost of construction projects in our consolidated balance sheets and as AFUDC in the statements of consolidated income. The Georgia Commission has authorized a rate of 9.16%, the New Jersey Board of Public Utilities (NJBPU) has authorized a rate of 7.60% and the Tennessee Regulatory Authority (Tennessee Authority) has authorized a rate of 9.08%. The capital expenditures of our other regulated utilities do not qualify for AFUDC treatment.In millions, except per share amounts | | 2005 | | 2004 | | 2003 | |
Net income, as reported | | $ | 193 | | $ | 153 | | $ | 128 | |
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect | | | (1 | ) | | (1 | ) | | (1 | ) |
Pro-forma net income | | $ | 192 | | $ | 152 | | $ | 127 | |
| | | | | | | | | | |
Earnings per share: | | | | | | | | | | |
Basic - as reported | | $ | 2.50 | | $ | 2.30 | | $ | 2.03 | |
Basic - pro-forma | | $ | 2.48 | | $ | 2.28 | | $ | 2.02 | |
| | | | | | | | | | |
Fully diluted - as reported | | $ | 2.48 | | $ | 2.28 | | $ | 2.01 | |
Fully diluted - pro-forma | | $ | 2.47 | | $ | 2.26 | | $ | 2.00 | |
Comprehensive Income
Our comprehensive income includes net income plus other comprehensive income (OCI), which includes other gains and losses affecting shareholders’ equity that accounting principles generally accepted in the United States of America (GAAP) excludeexcludes from net income. Such items consist primarily of unrealized gains and losses on certain derivatives and minimum pension liability adjustments.
In 2004, our OCI decreased $6 million as a result of an $11 million increase in our unfunded pension obligation, net of a $7 million income tax benefit, which was offset by changes in the fair value of derivatives designated as cash flow hedges at SouthStar of $4 million. For more information on SouthStar’s derivative financial instruments, see Note 4.and minimum pension liability adjustments. The following table illustrates our OCI activity for the years ended December 31, 2005, 2004 and 2003.
In 2003, our OCI increased $9 million as a result of an $8 million decrease in our unfunded pension obligation and $1 million for our 70% ownership interest in SouthStar’s unrealized gain associated with its cash flow hedges. In 2002, our OCI decreased by $48 million, net of income tax benefit of $31 million, as a result of a increase in our unfunded pension obligation.In millions | | 2005 | | 2004 | | 2003 | |
Cash flow hedges: | | | | | | | | | | |
Net derivative unrealized gains (losses) arising during the period (net of $3, $3 and $1 in taxes) | | $ | 5 | | $ | 6 | | $ | (1 | ) |
Less reclassification of realized (gains) losses included in income (net of $4, $1 and $2 in taxes) | | | (7 | ) | | (2 | ) | | 2 | |
Unfunded pension obligation (net of $3, $7 and $6 in taxes) | | | (5 | ) | | (11 | ) | | 8 | |
Other (net of tax) | | | - | | | 1 | | | - | |
Total | | $ | (7 | ) | $ | (6 | ) | $ | 9 | |
Earnings perPer Common Share
We compute basic earnings per common share by dividing our income available to common shareholders by the daily weighted average number of common shares outstanding. Fully diluted earnings per common share reflect the potential reduction in earnings per common share that could occur when potentially dilutive common shares are added to common shares outstanding.
We derive our potentially dilutive common shares by calculating the number of shares issuable under performance units and stock options. The future issuance of shares underlying the performance units depends on the satisfaction of certain performance criteria. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. No items are antidilutive. The following table shows the calculation of our fully diluted earnings per share for the periods presented if performance units currently earned under the plan ultimately vest and if stock options currently exercisable at prices below the average market prices are exercised:exercised.
In millions | | 2004 | | 2003 | | 2002 | | | 2005 | | 2004 | | 2003 | |
Denominator for basic earnings per share(1) | | | 66.3 | | | 63.1 | | | 56.1 | | |
Denominator for basic earnings per share (1) | | | | 77.3 | | | 66.3 | | | 63.1 | |
Assumed exercise of potential common shares | | | 0.7 | | | 0.6 | | | 0.5 | | | | 0.5 | | | 0.7 | | | 0.6 | |
Denominator for fully diluted earnings per share | | | 67.0 | | | 63.7 | | | 56.6 | | | | 77.8 | | | 67.0 | | | 63.7 | |
(1) | Daily weighted average shares outstanding. |
Use of Accounting Estimates
The preparation of our financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The most significant estimates include our regulatory accounting, the allowance for doubtful accounts, allowance for contingencies, pipeline replacement program (PRP) accruals, environmental liability accruals, unbilled revenue recognition, pension and postretirement obligations, derivative and hedging activities, and purchase price allocations. Actual results could differ from those estimates.
Acquisitions
Acquisition of NUI Corporation
On November 30, 2004, we acquired all the outstanding shares of NUI for approximately $218$825 million, incurred $7 millionincluding the assumption of transaction costs and repaid $500 million of NUI's outstanding short-term debt. At closing, NUI had $709 million in debt and approximately $109 million of cash on its balance sheet (including the return of an interest escrow balance), bringing the net value of the acquisition to approximately $825 million. In connection with the acquisition, we incurred $23 million in employee-related restructuring charges, which include $16 million in severance costs, $4 million in change in control payments to certain NUI executives and the NUI Board of Directors, and $3 million of employee retention and relocation costs.debt. The acquisition significantly expands our existing natural gas utilities, storage and pipeline businesses. During 2005, we adjusted our purchase price allocation by $74 million for additional known items, including adjustments related to pension obligations; severance; lease obligations related to NUI’s former corporate offices; environmental remediation liabilities; income tax liabilities; and asset sales. In connection with the acquisition, we incurred $25 million in employee-related restructuring charges. As of December 31, 2005, $5 million of these payments remained to be paid. Our purchase price allocation as of December 31, 2004 and 2005 and the goodwill adjustments are indicated in the following table.
We funded the purchase price with a portion of the proceeds from our November 2004 common stock offering and proceeds from short-term borrowings under our commercial paper program. Additionally, NUI Utilities, Inc., a wholly owned subsidiary of NUI, had outstanding, at closing, $199 million of indebtedness pursuant to Gas Facility Revenue Bonds and $10 million in capital leases. | | Dec. 31, | | Adjust- | | Dec. 31, | |
In millions | | 2004 | | ments | | 2005 | |
Purchase price | | $ | 825 | | $ | - | | $ | 825 | |
Current assets | | | 299 | | | (1 | ) | | 298 | |
Property, plant and equipment | | | 612 | | | (15 | ) | | 597 | |
Other long-term assets | | | 117 | | | (21 | ) | | 96 | |
Goodwill | | | 157 | | | 74 | | | 231 | |
Current liabilities excluding debt | | | (108 | ) | | (4 | ) | | (112 | ) |
Short-term debt and capital leases | | | (502 | ) | | - | | | (502 | ) |
Long-term debt and capital leases | | | (207 | ) | | - | | | (207 | ) |
Other long-term liabilities | | | (143 | ) | | (31 | ) | | (174 | ) |
Equity | | | 225 | | | 2 | | | 227 | |
Our allocation of the purchase price is preliminary and is subject to change. The preliminary nature is a result of the timing of the acquisition, which occurred late in our fourth quarter. The amount currently allocated to property, plant and equipment represents our estimate of the fair value of the assets acquired. We based that estimate on a preliminary independent valuation counselor’s report, which is expected to be finalized during the first quarter of 2005. The following table summarizes the fair values of the assets acquired and liabilities assumed on November 30, 2004:
In millions | | Preliminary Fair Value | |
Purchase price | | $ | 825 | |
Current assets | | | 299 | |
Property, plant and equipment | | | 612 | |
Other long term assets | | | 117 | |
Goodwill | | | 157 | |
Current liabilities excluding debt | | | (108 | ) |
Short-term debt and capital leases | | | (502 | ) |
Long-term debt and capital leases | | | (207 | ) |
Other long-term liabilities | | | (143 | ) |
Equity | | | 225 | |
The excess of the purchase price over the fair value of the identifiable net assets acquired of $157 million was allocated to goodwill. We believe the acquisition resulted in the recognition of goodwill primarily because of the strength of NUI’s underlying assets and the synergies and opportunities in the regulated utilities. Goodwill is not deductible for income tax purposes.
The table below reflects the unaudited pro forma results of AGL Resources and NUI for the years ended December 31, 2004 and 2003 as if the acquisition and related financing had taken place on January 1.The1. The pro-forma results are not necessarily indicative of the results that would have occurred if the acquisition had been in effect for the periods presented. In addition, the pro-forma results are not intended to be a projection of future results and do not reflect any synergies that might be achieved from combining the operations or eliminating significant expenses that NUI incurred in its last year of operations. Our results of operations for 2004 include one month of the acquired operations of NUI.
In millions, except per share amounts | | 2004 | | 2003 | |
Operating revenue | | $ | 2,343 | | $ | 1,630 | |
Income before cumulative effect of change in accounting principle | | | 105 | | | 88 | |
Net income | | | 105 | | | 74 | |
Net income per fully diluted share | | | 1.44 | | | 1.05 | |
Sale of Saltville In August 2005, we sold our 50% interest in Saltville and associated subsidiaries (Virginia Gas Pipeline and Virginia Gas Storage) to a subsidiary of Duke Energy Corporation, the other 50% partner in the Saltville joint venture. We acquired these assets as part of our purchase of NUI. We received $66 million in cash at closing, which included $4 million in working capital adjustments, and used the proceeds to repay debt and for other general corporate purposes. The transaction was reflected as a decrease of $4 million in goodwill associated with the NUI acquisition.
Jefferson Island Storage & Hub, LLC (Jefferson Island)Sale of Other NUI Assets In 2005, we sold an appliance business in Florida and Virginia Gas Distribution Company for proceeds totaling $7 million, which approximated their amounts on our consolidated balance sheets and have been recorded as adjustments to goodwill.
We acquired Jefferson Island from American Electric Power in October 2004 for $90 million, which included approximately $9 million of working gas inventory. We funded the acquisition with a portion of the net proceeds we received from our November 2004 common stock offering and borrowings.
Recent Accounting Pronouncements
Adopted in 2004
FIN 46
FIN 46 requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities.
In December 2003, the FASB revised FIN 46, delaying the effective dates for certain entities created before February 1, 2003, and making other amendments to clarify application of the guidance. For potential variable interest entities other than any special purpose entities, the FASB required FIN 46R to be applied no later than the end of the first fiscal year or interim reporting period ending after March 15, 2004. FIN 46R also requires certain disclosures of an entity’s relationship with variable interest entities. We adopted FIN 46R effective January 1, 2004, resulting in the consolidation of SouthStar’s accounts in our consolidated financial statements and the deconsolidation of the accounts related to our Trust Preferred Securities. FIN 46R also requires certain disclosures of an entity’s relationship with variable interest entities.
Notes Payable to Trusts and Trust Preferred SecuritiesSFAS 123(R) In June 1997 and March 2001, we established AGL Capital Trust I and AGL Capital Trust II (Trusts) to issue our Trust Preferred Securities. The Trusts are considered to be special purpose entities under FIN 46 and FIN 46R since
· | our equity in the Trusts is not considered to be sufficient to allow the Trusts to finance their own activities |
· | our equity investment is not considered to be at risk since the equity amounts were financed by the Trusts |
Under FIN 46 (prior to the revision in FIN 46R), we concluded that we were the primary beneficiary of the Trusts because the Trust Preferred Securities are publicly traded and widely held, and no one party would absorb a majority of any expected losses of the Trusts. In addition, our loan agreements with the Trusts include call options that capture declining interest rates by enabling us to call the preferred securities at par and thereby capturing the majority of the residual returns in the Trusts. Accordingly, at December 31, 2003, the accounts of the Trusts were included in our consolidated financial statements.
The revisions in FIN 46R included specific guidance that instruments such as the call options included in our loan agreements with the Trusts do not constitute variable interests and should not be considered in the determination of the primary beneficiary. As a result, as of January 1, 2004 (when we adopted FIN 46R), we were required to exclude the accounts of the Trusts from our consolidated financial statements and to classify amounts payable to the Trusts as “Notes payable to Trusts” within long-term debt in our consolidated balance sheets as of December 31, 2004.
Due to deconsolidation of the Trusts, we included in our consolidated balance sheets at December 31, 2004, an asset of approximately$10 million representing our investment in the Trusts and a note payable to the Trusts totaling approximately$235 million, net of an interest rate swap of$3 million. We also removed $222 million related to the Trust Preferred Securities issued by the Trusts. The notes payable represent the loan payable to fund our investments in the Trusts of $10 million and the amounts due to the Trusts from the proceeds received from their issuances of Trust Preferred Securities of $222 million.
Consolidation of SouthStarIn 1998 a joint venture, SouthStar, was formed by our wholly owned subsidiary, Georgia Natural Gas Company, Piedmont Natural Gas Company, Inc. (Piedmont) and Dynegy Inc. (Dynegy) to market natural gas and related services to retail customers, principally in Georgia. SouthStar, which operates under the trade name Georgia Natural Gas, competes with other energy marketers, including Marketers in Georgia, to provide natural gas and related services to customers in Georgia and the Southeast. In March 2003, we purchased Dynegy’s 20% ownership interest in a transaction that for accounting purposes had an effective date of February 18, 2003. We currently own a noncontrolling 70% financial interest in SouthStar and Piedmont owns the remaining 30%. Our 70% interest is noncontrolling because all significant management decisions require approval by both owners.
In March 2004, we executed an amended and restated partnership agreement with Piedmont that calls for SouthStar’s earnings starting in 2004 to be allocated 75% to our subsidiary and 25% to Piedmont. Consequently, as of January 1, 2004 we consolidated all SouthStar’s accounts with our subsidiaries’ accounts and eliminated any intercompany balances between segments. We recorded Piedmont’s portion of SouthStar’s earnings as a minority interest in our consolidated statements of income, and we recorded Piedmont’s portion of SouthStar’s capital as a minority interest in our consolidated balance sheet. For all periods prior to February 18, 2003, SouthStar’s earnings were allocated based on our 50% ownership interests in those periods. We determined that SouthStar is a variable interest entity as defined in FIN 46R because
· | Our equal voting rights with Piedmont are not proportional to our economic obligation to absorb 75% of any losses or residual returns from SouthStar. |
· | SouthStar obtains substantially all its transportation capacity for delivery of natural gas through our wholly owned subsidiary, Atlanta Gas Light. |
As of December 31, 2003, we did not consolidate SouthStar in our financial statements because it did not meet the definition of a variable interest entity under FIN 46. FIN 46R added the following conditions for determining whether an entity was a variable interest entity:
· | the voting rights of some investors are not proportional to their obligations to absorb the expected losses of the entity, their rights to receive the expected residual returns of the entity, or both |
· | substantially all the entity’s activities (for example, purchasing products and additional capital) either involve or are conducted on behalf of an investor that has disproportionately fewer voting rights |
However, as SouthStar’s results of operations and financial condition were material in 2002 and 2003 to our financial results, we present below the summarized amounts for 100% of SouthStar. These results are not comparable with our earnings or losses from SouthStar in those prior periods, which we reported as other income (loss) in our statements of consolidated income, as those amounts were reported based on our ownership percentage.
| |
In millions | | Dec. 31, 2003 | | | |
Balance Sheet | | | | | |
Current assets | | $ | 174 | | | | |
Noncurrent assets | | | 2 | | | | |
Current liabilities | | | 75 | | | | |
Noncurrent liabilities | | | - | | | | |
| | | | | | | |
In millions | | | 2003 | | | 2002 | |
Income Statement | | | | | | | |
Revenues | | $ | 746 | | $ | 630 | |
Operating margin | | | 124 | | | 115 | |
Operating income | | | 63 | | | 41 | |
Net income from continuing operations | | | 63 | | | 42 | |
Issued but Not Yet Adopted in 2004
In December 2004, the FASB issued SFAS No 123(R), “Accounting for Stock Based Compensation” (SFAS 123R). SFAS 123R revises the guidance in SFAS No. 123 and supercedessupersedes APB 25 and its related implementation guidance. SFAS 123R focuses primarily on the accounting for share-based payments to employees in exchange for services, and it requires a public entity to measure and recognize compensation cost for these payments. Our share-based payments are typically in the form of stock option and restricted stockperformance unit awards. The primary change in accounting under SFAS 123R is related to the requirement to recognize compensation cost for stock option awards that was not recognized under APB 25.
Compensation SFAS 123R requires compensation cost willto be measured based on the fair value of the equity or liability instruments issued. For stock option awards, fair value would be estimated using an option pricing model such as the Black-Scholes model.
SFAS 123R becomesis effective as of the first interim or annual reporting period that beginsfor equity compensation expense in fiscal years beginning after JuneDecember 15, 2005, and therefore we will adopt it prospectively on January 1, 2006. We have assessed the impact SFAS 123R inwill have on our consolidated financial statements, and we believe the third quarterpro-forma effects on our earnings of 2005. We expect to recognize approximately $1 million ofrecognizing compensation cost during the last six months of 2005expense related to our stock option awards. Forawards, contained in Note 1, serves as a discussionreasonable proxy for the impact of our stock-based compensation plansthis statement (approximately $1 million net of income taxes for 2006 and agreements, see Note 7.2007 based on unvested stock options as of December 31, 2005).
FIN 47 In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (FIN 47). Asset retirement obligations (AROs) are legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of a long-lived asset, except for certain obligations of lessees. FIN 47 clarifies that liabilities associated with asset retirement obligations whose timing or settlement method are conditional on future events should be recorded at fair value as soon as fair value is reasonably estimable. FIN 47 also provides guidance on the information required to reasonably estimate the fair value of the liability. FIN 47 is intended to result in
· | more consistent recognition of liabilities relating to AROs among companies |
· | more information about expected future cash outflows associated with those obligations stemming from the retirement of the asset(s) |
· | more information about investments in long-lived assets because additional asset retirement costs will be recognized by increasing the carrying amounts of the assets identified to be retired |
FIN 47 is effective for fiscal years ending after December 15, 2005. We adopted the provisions of FIN 47 during the fourth quarter of 2005. The impact of adoption was not material.
Risk Management
Our risk management activities are monitored by our Risk Management Committee (RMC). The RMC consists of senior management and is charged with the reviewreviewing and enforcement ofenforcing our risk management activities. Our risk management policies limit the use of derivative financial instruments and physical transactions within predefined risk tolerances associated with pre-existing or anticipated physical natural gas sales and purchases and system use and storage. We use the following derivative financial instruments and physical transactions to manage commodity price risks:
· | storage and transportation capacity transactions |
Interest Rate Swaps
To maintain an effective capital structure, it is our policy to borrow funds using a mix of fixed-rate debt and variable-rate debt. We have entered into interest rate swap agreements through our wholly owned subsidiary, AGL Capital Corporation (AGL Capital), for the purpose of hedgingmanaging the interest rate risk associated with our fixed-rate and variable-rate debt obligations. We designated these interest rate swaps as fair value hedges and accounted for them using the “shortcut” methodas prescribed by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), which allows us to designate derivatives that hedge exposure to changes in the fair value of a recognized asset or liability. We record the gain or loss on fair value hedges in earnings in the period of change, together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The effect of this accounting is to reflect in the interest expense line item in the statement of consolidated income, only that portion of the hedge that is ineffective in achieving offsetting changes in fair value.
Accordingly, weWe adjust the carrying value of each interest rate swap to its fair value at the end of each period, with an offsetting and equal adjustment to the carrying value of the debt securities whose fair value is being hedged. Consequently, our earnings are not affected negatively or positively withby changes in the fair value of the interest swaps each quarter.
In March 2004, we adjusted our fixed-to variable-rate obligations and terminated an interest rate swap on $100 million of the principal amount of our 4.45% Senior Notes due 2013. Additionally, as of March 31, 2004 and in connection with the deconsolidation of the Trusts, we redesignated the interest rate swaps on the Trust Preferred Securities as a fair value hedge of our notes payable to the Trusts.swaps.
As of December 31, 2004,2005, a notional principal amount of $175$100 million of these interest rate swap agreements effectively converted the interest expense associated with a portion of our senior notes and notes payable to the Trusts from fixed rates to variable rates based on an interest rate equal to the London Interbank Offered Rate (LIBOR), plus a spread determined at the swap date. The floating rate swap range for our interest rate swaps for the year ended December 31, 2005 was 7.21%.
At the beginning of 2005, we had $75 million of outstanding interest rate swap agreements associated with our Note Payable at AGL Capital Trust II. On September 7, 2005, we terminated these interest rate swap agreements. We received a payment of $1 million related to this termination, which included accrued interest and the fair value of these interest rate swapsswap agreements at the termination date.
In September 2005, we also executed five treasury-lock agreements totaling $125 million to hedge the interest rate risk associated with an anticipated 2006 financing. The agreements will result in a 4.11% interest rate on the 10-year United States Treasury bond against which we will be measured in issuing our own debt securities and the agreements were designated as cash flow hedges against the future interest payments on the anticipated financing. The fair value of this agreement was recorded as an asset of $1$3 million at December 31, 2004 and2005, with the increase in the fair value included as a liability of $4 million at December 31, 2003. For more information on the effective rates and maturity dates of our interest rate swaps, see Note 8.credit to OCI.
Commodity-related derivative instrumentsDerivative Instruments
Elizabethtown GasCertain derivatives are utilizedA program mandated by the NJBPU requires Elizabethtown Gas for nontrading purposesto utilize certain derivatives to hedge the impact of market fluctuations on assets, liabilities and other contractual commitments.in natural gas prices. Pursuant to SFAS 133, such derivative products are marked-to-marketmarked to market each reporting period. Pursuant toIn accordance with regulatory requirements, realized gains and losses related to suchthese derivatives are reflected in purchased gas costs and ultimately included in billings to customers. Unrealized gains and losses are reflected as a regulatory asset (loss) or liability (gain), as appropriate, on the consolidated balance sheet. As of December 31, 2004,2005, Elizabethtown Gas had entered into New York Mercantile Exchange (NYMEX) futures contracts to purchase 9.7approximately 8.3 billion cubic feet (Bcf) of natural gas at equivalent prices ranging from $3.609 to $8.291 per thousand cubic feet.and the fair values of these derivatives were reflected in our consolidated financial statements as an asset of $17 million and a liability of $21 million. Approximately 84%81% of these contracts have a duration of one-yearone year or less, and none of these contracts extendextends beyond October 2006.2007.
Sequent We are exposed to risks associated with changes in the market price of natural gas. Sequent uses derivative financial instruments to reduce our exposure to the risk of changes in the prices of natural gas. The fair value of these derivative financial instruments reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We use external market quotes and indices to value substantially all the financial instruments we utilize.use.
We attempt to mitigate substantially all the commodity price risk associated with Sequent’s storagenatural gas portfolio by locking in the economic margin at the time we enter into natural gas purchase transactions for our storagestored natural gas. We purchase natural gas for storage when the difference in the current market price we pay to buy and transport natural gas plus the cost to store the natural gas is less than the market price we couldcan receive in the future, resulting in a positive net profit margin. We use NYMEX futures NYMEX contracts and other over-the-counter derivatives to sell natural gas at that future price to substantially lock in the profit margin we will ultimately realize when the stored gas is actually sold. These futures contracts meet the definition of a derivativederivatives under SFAS 133, and are recorded at fair value and are marked to market in our consolidated balance sheets, with changes in fair value recorded in earnings in the period of change. The purchase, transportation, storage and sale of natural gas are accounted for on an accruala weighted average basis rather than on the mark-to-market basis we utilize for the derivatives used to mitigate the commodity price risk associated with our storage portfolio. This difference in accounting willcan result in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated.
At December 31, 2004, our2005, Sequent’s commodity-related derivative financial instruments represented purchases (long) of 521411 Bcf and sales (short) of 550464 Bcf, with approximately 93%94% of these scheduled to mature in less than two years and the remaining 7%6% in three to nine years. At December 31, 2005, the fair values of these derivatives were reflected in our consolidated financial statements as an asset of $80 million and a liability of $97 million. Excluding the cumulative effect of a change in accounting principle in 2003, our unrealized loss was $30 million in 2005, and we had unrealized gains wereof $22 million in 2004 and $1 million in 2003 and $4 million in 2002.2003.
SouthStar The commodity-related derivative financial instruments (futures, options and swaps) used by SouthStar manage exposures arising from changing commodity prices. SouthStar’s objective for holding these derivatives is to utilize the most effective methodsmethod to reduce or eliminate the impactsimpact of changing commodity prices. A significantthis exposure. We have designated a portion of SouthStar’s derivative transactions are designated as cash flow hedges under SFAS 133. DerivativeWe record derivative gains or losses arising from cash flow hedges are recorded in OCI and are reclassifiedreclassify them into earnings in the same period as the settlement of the underlying hedged item. AnyWe record any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not perfectly offset and are greater than the losses or gains on the hedged item, is recorded in our cost of gas onin our statement of consolidated income statement in the period in which it occurs. SouthStar currently has only minimal hedge ineffectiveness.
We have not designated the remainder of SouthStar’s remaining derivative instruments do not meet the hedge criteriaas hedges under SFAS 133; therefore,133 and, accordingly, we record changes in thetheir fair value of these derivatives are recorded in earnings in the period of change.
At December 31, 2004,2005, the fair values of these derivatives were reflected in our consolidated financial statements as an asset of $9$7 million and a liability of $2$4 million. The maximum maturity of open positions is less than one year and represents purchases and sales of 83.2 Bcf.
SouthStar also enters both exchange and over-the-counter derivative transactions to hedge commodity price risk. Credit risk is mitigated for exchange transactions through the backing of the NYMEX’s member firms. For over-the-counter transactions, SouthStar utilizes master netting arrangements to reduce overall credit risk. As of December 31, 2005, SouthStar’s maximum exposure to any single over-the-counter counterparty was $2 million.
Concentration of Credit Risk
Atlanta Gas Light Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 10 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the nonpeak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. These retail functions include customer service, billing, collections, and the purchase and sale of natural gas. Atlanta Gas Light’s tariff allows it to obtain security support in an amount equal to a minimum of two times a Marketer’s highest monthly invoice.month's estimated bill from Atlanta Gas Light.
SequentWholesale Services ASequent has a concentration of credit risk exists at Sequent for amounts billed for services it provides to marketers and to utility and industrial customers. This credit risk is measured by 30-day receivable exposure plus forward exposure, which is highlygenerally concentrated in 20 of its customers. Sequent evaluates the credit risk of its counterpartiescustomers using the S&Pa Standard & Poor’s Ratings Services (S&P) equivalent credit rating, which is determined by a process of converting the lower of the Standard & Poor’s Rating Services (S&P)S&P or Moody’s Investors Service (Moody’s) rating to an internal rating ranging from 9.00 to 1.00, with 9.00 being equivalent to AAA/Aaa by S&P and Moody’s and 1.00 being equivalent to D or Default by S&P and Moody’s. A counterpartycustomer that does not have an external rating is assigned an internal rating based on Sequent’s analysis of the strength of its financial ratios. At December 31, 2005, Sequent’s top 20 customers represented approximately 52% of the total credit exposure of $554 million, derived by adding together the top 20 customers’ exposures and dividing by the total of Sequent’s counterparties' exposures. Sequent’s customers or the customers’ guarantors had a weighted average S&P equivalent rating of A- at December 31, 2005.
The weighted average credit rating is obtained by multiplying each counterparty’scustomer’s assigned internal rating by the counterparty’sits credit exposure and then adding the individual results are then summed for all counterparties. That total is divided by the aggregate total counterparties’ exposure. This numeric value is converted to an S&P equivalent. At December 31, 2004, Sequent’s top 20 counterparties represented approximately 57% of the total counterparty exposure of $328 million, derived by adding the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures. Sequent’s counterparties or the counterparties’ guarantors had a weighted average Standard & Poor’s Rating Services equivalent of an A- rating at December 31, 2004.
Sequent has established credit policies to determine and monitor the creditworthiness of counterparties, including requirements for posting of collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment grade financial institution, but may also include cash or U.S. Government Securities held by a trustee. When we areSequent is engaged in more than one outstanding derivative transaction with the same counterparty and weit also havehas a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of ourSequent’s credit risk. Sequent also uses other netting agreements with certain counterparties with whom we conductwhich it conducts significant transactions.
Regulatory Assets and Liabilities
We have recorded regulatory assets and liabilities in our consolidated balance sheets in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). Our regulatory assets and liabilities, and associated liabilities for our unrecovered pipeline replacement program (PRP)PRP costs and unrecovered environmental remediation costs (ERC), are summarized in the table below:below.
| | | December 31, | |
In millions | | Dec. 31, 2004 | | Dec.31, 2003 | | | 2005 | | 2004 | |
Regulatory assets | | | | | | | | | | |
Unrecovered PRP costs | | $ | 361 | | $ | 432 | | | $ | 303 | | $ | 361 | |
Unrecovered environmental remediation costs | | | 200 | | | 179 | | |
Unrecovered ERC | | | | 196 | | | 200 | |
Unrealized loss on hedging derivatives | | | | 17 | | | 6 | |
Unrecovered postretirement benefit costs | | | 14 | | | 9 | | | | 14 | | | 14 | |
Unrecovered seasonal rates | | | 11 | | | 11 | | | | 11 | | | 11 | |
Unrecovered PGA | | | 5 | | | - | | | | 8 | | | 2 | |
Regulatory tax asset | | | 2 | | | 3 | | | | 1 | | | 2 | |
Other | | | 20 | | | 5 | | | | 9 | | | 20 | |
Total regulatory assets | | $ | 613 | | $ | 639 | | | $ | 559 | | $ | 616 | |
Regulatory liabilities | | | | | | | | | | | | | | |
Accumulated removal costs | | $ | 94 | | $ | 102 | | | $ | 94 | | $ | 94 | |
Unrealized gain on hedging derivatives | | | | 21 | | | 6 | |
Unamortized investment tax credit | | | 20 | | | 19 | | | | 19 | | | 20 | |
Deferred PGA | | | 37 | | | 30 | | | | 36 | | | 60 | |
Regulatory tax liability | | | 14 | | | 15 | | | | 15 | | | 14 | |
Other | | | 18 | | | 3 | | | | 6 | | | 12 | |
Total regulatory liabilities | | | 183 | | | 169 | | | | 191 | | | 206 | |
Associated liabilities | | | | | | | | | | | | | | |
PRP costs | | | 327 | | | 405 | | | | 265 | | | 327 | |
Environmental remediation costs | | | 90 | | | 83 | | |
ERC | | | | 97 | | | 90 | |
Total associated liabilities | | | 417 | | | 488 | | | | 362 | | | 417 | |
Total regulatory and associated liabilities | | $ | 600 | | $ | 657 | | | $ | 553 | | $ | 623 | |
Our regulatory assets are recoverable through either rate riders or base rates specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period rates are in effect. As such, all our regulatory assets are subject to review by the respective state regulatory commission during any future rate proceedings.Inproceedings. In the event that the provisions of SFAS 71 were no longer applicable, we would recognize a write-off of net regulatory assets (regulatory assets less regulatory liabilities) that would result in a charge to net income, which would be classified as an extraordinary item. However, although the natural gas distribution industry is becoming increasingly competitive, our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under SFAS 71 remains appropriate.Itappropriate. It is also our opinion that all regulatory assets are recoverable in future rate proceedings, and therefore we have not recorded any regulatory assets that are recoverable but are not yet included in base rates or contemplated in a rate rider.
All the regulatory assets included in the table above are included in base rates except for the unrecovered PRP costs, unrecovered environmental remediation costsERC and deferred PGA, which are recovered through specific rate riders. The rate riders that authorize recovery of unrecovered PRP costs and the deferred PGA include both a recovery of costs and a return on investment during the recovery period. We have two rate riders that authorize the recovery of unrecovered environmental remediation costs.ERC. The environmental remediation costERC rate rider for Atlanta Gas Light only allows for recovery of the costs incurred and the recovery period occurs over the five years after the expense is incurred. Environmental remediation costsERC associated with the investigation and remediation of Elizabethtown Gas’Gas remediation sites located in the state of New Jersey are recovered under a Remediation Adjustment Clauseremediation adjustment clause and include the carrying cost on unrecovered amounts not currently in rates.
The regulatory liabilities are refunded to ratepayers through a rate rider or base rates. If the regulatory liability is included in base rates, the amount is reflected as a reduction to the rate base in setting rates.
Pipeline Replacement Program
The PRP, ordered by the Georgia Commission to be administered by Atlanta Gas Light, requires, among other things, that itAtlanta Gas Light replace all bare steel and cast iron pipe in its system in the state of Georgia within a 10-year period beginning October 1, 1998. Atlanta Gas Light identified, and provided notice to the Georgia Commission of 2,312 miles of pipe to be replaced. Atlanta Gas Light has subsequently identified an additional 188320 miles of pipe subject to replacement under this program. If Atlanta Gas Light does not perform in accordance with this order, it will be assessed certain nonperformance penalties. October 1, 20042005 marked the beginning of the seventheighth year of the 10-year PRP.
The order also provides for recovery of all prudent costs incurred in the performance of the program, which Atlanta Gas Light has recorded as a regulatory asset. Atlanta Gas Light will recover from end-use customers, through billings to Marketers, the costs related to the program net of any cost savings from the program. All such amounts will be recovered through a combination of SFV rates and a pipeline replacement revenue rider. The regulatory asset has two components:
· | the costs incurred to date that have not yet been recovered through the rate rider |
· | the future expected costs to be recovered through the rate rider |
On June 10, 2005, Atlanta Gas Light and the Georgia Commission entered into a Settlement Agreement that, among other things, extends Atlanta Gas Light’s PRP by five years to require that all replacements be completed by December 2013. The timing of replacements was subsequently specified in an amendment to the PRP stipulation. This amendment, which was approved by the Georgia Commission on December 20, 2005, requires Atlanta Gas Light to replace all cast iron pipe and 70% of all bare steel pipe by December 2010. The remaining 30% of bare steel pipe is required to be replaced by December 2013. The amendment requires an evaluation by Atlanta Gas Light and the Georgia Commission staff of 22 miles of 24 inch pipe in Atlanta by December 2010 to determine if such pipe requires replacement. If replacement of this pipe is required, the pipe must be replaced by December 2013. The additional cost to replace this pipe is projected to be approximately $37 million.
Under the Settlement Agreement, base rates charged to customers will remain unchanged through April 30, 2010, but Atlanta Gas Light will recognize reduced base rate revenues of $5 million on an annual basis through April 30, 2010. The five-year total reduction in recognized base rate revenues of $25 million will be applied to the allowed amount of costs incurred to replace pipe, which will reduce the amounts recovered from customers under the PRP rider. The Settlement Agreement also set the per customer PRP rate that Atlanta Gas Light will charge a fixed rate at $1.29 per customer per month from May 2005 through September 2008 and at $1.95 from October 2008 through December 2013 and includes a provision that allows for a true-up of any over- or under-recovery of PRP revenues that may result from a difference between PRP charges collected through fixed rates and actual PRP revenues recognized through the remainder of the program.
The Settlement Agreement also allows Atlanta Gas Light to recover through the PRP $4 million of the $32 million capital costs associated with its purchase of 250 miles of pipeline in central Georgia from Southern Natural Gas Company, a subsidiary of El Paso Corporation. The remaining capital costs are included in Atlanta Gas Light’s rate base and collected through base rates.
Atlanta Gas Light has recorded a long-term regulatory asset of $337$276 million, which represents the expected future collection of both expenditures already incurred and expected future capital expenditures to be incurred through the remainder of the program. Atlanta Gas Light has also recorded a current asset of $24$27 million, which represents the expected amount to be collected from customers over the next 12 months. The amounts recovered from the pipeline replacement revenue rider during the last three years were
As of December 31, 2004,2005, Atlanta Gas Light had recorded a current liability of $85$30 million, representing expected program expenditures for the next 12 months. Atlanta Gas Light anticipates that its capitalmonths and a long-term liability of $235 million, representing.expected program expenditures forfrom 2007 through the PRP will end by June 30, 2008, unless we agree with the Georgia Commission to an extension of the program.program in 2013.
Atlanta Gas Light capitalizes and depreciates the capital expenditure costs incurred from the PRP over the life of the assets. Operation and maintenance costs are expensed as incurred. Recoveries, which are recorded as revenue, are based on a formula that allows Atlanta Gas Light to recover operation and maintenance costs in excess of those included in its current base rates, depreciation expense and an allowed rate of return on capital expenditures. In the near term, the primary financial impact to Atlanta Gas Light from the PRP is reduced cash flow from operating and investing activities, as the timing related to cost recovery does not match the timing of when costs are incurred. However, Atlanta Gas Light is allowed the recovery of carrying costs on the under-recovered balance resulting from the timing difference.
Environmental Remediation Costs
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites.
Atlanta Gas Light The presence of coal tar and certain other by-productsbyproducts of a natural gas manufacturing process used to produce natural gas prior to the 1950s havehas been identified at or near 1310 former Atlanta Gas Light operating sites in Georgia and at 3 sites of predecessor companies in Florida. Atlanta Gas Light has active environmental remediation or monitoring programs in effect at 10 of these sites. Two of three sites in Florida are currently in the investigation or preliminary engineering design phase, and one Georgia site are currently in the preliminary investigation or engineering design phase. The required soil remediation at our Georgia sites is scheduled to be completed by June 2005. As of December 31, 2004, Atlanta Gas Light’s remediation program was approximately 78% complete.has been deemed compliant with state standards.
Atlanta Gas Light has historicallycustomarily reported estimates of future remediation costs for these former sites based on probabilistic models of potential costs. These estimates are reported on an undiscounted basis. As cleanup options and plans mature and cleanup contracts are entered into, Atlanta Gas Light is increasinglybetter able to provide conventional engineering estimates of the likely costs of many elementsremediation at its former sites. These estimates contain various engineering uncertainties, andbut Atlanta Gas Light continuously attempts to refine and update these engineering estimates.
OurAtlanta Gas Light’s current engineering estimate projects costs associated with Atlanta Gas Light’s engineering estimatesof $12 million to complete site remediation in Georgia and in-place contracts to be $36 million.Florida, excluding monitoring. This is a reduction of $30$24 million from last year’s estimate, of projected engineering and in-place contracts, resultedresulting primarily from $50 million of program expenditures incurred in the year ended September 30, 2004.expenditures. During the same 12-month period Atlanta Gas Light realized increaseschanges in its future cost estimates totaling $20$6 million related to
· | an increase in the contract value at its Augusta, Georgia site for treatment of two areas and additional deep excavationa reduction of contaminants$2 million in groundwater costs related to active treatment system operations |
· | the addition of harbor sediment removala decrease at its St. Augustine, FloridaSavannah, Georgia site of $4 million for groundwater treatment costs and contractual liability |
· | an increasea decrease of $1 million at its Savannah,Griffin, Georgia site for phase 2 excavation and a partially offsetting decrease in engineering and oversightgroundwater treatment costs |
· | an increase of $1 million for additional remediation and investigative costs at its various sites in the program management costs due to legal matters, environmental regulatory activitiesGeorgia and oversight costs for the extension of work at the Savannah and Augusta sitesFlorida |
The engineering estimate was $66 million in 2003, which was a reduction of $43 million from the 2002 estimate. The decrease was a result of $37 million of program expenditures incurred in the year ended September 30, 2003 and a $6 million reduction in future cost estimates. For those remaining elements of Atlanta Gas Light’s environmental remediation program where it is unable to perform engineering cost estimates at the current state of investigation, considerable variability remains in the estimates for future remediation costs. For these elements, the estimate for the remaining cost of future actions at these former operating sites is $14 million.$15 million, which may change depending on whether future measures for groundwater will be required. Atlanta Gas Light estimates certain other costs related to administering the remediation program, and remediation of sites currently in the investigation phase. Through January 2006, Atlanta Gas Light estimates theincluding administrative costs, to be $2$4 million.
For those sites currently in the investigation phase, Atlanta Gas Light’s estimate for remediation is $9 million. This estimate is based on preliminary data received during 2004 with respect to the existence
The liability doesThese liabilities do not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, unbudgeted legal expenses or other costs for which Atlanta Gas Light may be held liable but with respect to which it cannot reasonably estimate thean amount. The liability also does not include certain potential cost savings as described above. As of December 31, 2004,2005, the remediation expenditures expected to be incurred over the next 12 months are reflected as a current liability of $27$10 million. Atlanta Gas Light’s environmental remediation cost liability is composed of the following elements:
In millions | | Dec. 31, 2004 | | Dec. 31, 2003 | | 2004 vs. 2003 | |
Projected engineering estimates and in-place contracts(1) | | $ | 36 | | $ | 67 | | | ($31 | ) |
Estimated future remediation costs(1) | | | 14 | | | 15 | | | (1 | ) |
Administrative expenses(2) | | | 2 | | | 3 | | | (1 | ) |
Other expenses(2) | | | 9 | | | 9 | | | - | |
Cash payments for cleanup expenditures (3) | | | (5 | ) | | (11 | ) | | 6 | |
Environmental remediation cost liability | | $ | 56 | | $ | 83 | | | ($27 | ) |
(1) As of September 30, 2004 and September 30, 2003.
(2) For the respective calendar years.
(3) Expenditures during the three months ended December 31, 2004 and December 31, 2003.
The environmental remediation costERC liability is included inas a corresponding regulatory asset, which is a combination of accrued environmental remediation costsERC and unrecovered cash expenditures for investigation and cleanup costs.Atlantacosts. Atlanta Gas Light has three ways of recovering investigation and cleanup costs. First, the Georgia Commission has approved an environmental remediation costERC recovery rider. It allows recovery of the costs of investigation, testing, cleanup and litigation. Because of that rider, these actual and projected future costs related to investigation and cleanup to be recovered from customers in future years are included in our regulatory assets. The environmental remediation costERC recovery mechanism allows for recovery of expenditures over a five-year period subsequent to the period in which the expenditures are incurred. Atlanta Gas Light expects to collect $27$29 million in revenues over the next 12 months under the environmental remediation costERC recovery rider, which is reflected as a current asset. The amounts recovered from the ERC recovery rider during the last three years were
The second way to recover costs is by exercising the legal rights Atlanta Gas Light believes it has to recover a share of its costs from other potentially responsible parties, typically former owners or operators of these sites. There were no material recoveries from potentially responsible parties during 2005, 2004 2003 or 2002.
2003. The third way to recover costs is from the receipt of net profits from the sale of remediated property. In June 2004, a residential and retail development located in Savannah, Georgia and adjacent to a former remediation site was sold, resulting in a gain of $6 million. All gains onThere were no sales of remediated property are required to be shared 70% with ratepayers through a reduction to the regulatory asset. Consequently, the unrecovered environmental remediation costs were reduced by approximately $4 million.during 2005.
Elizabethtown Gas In New Jersey, Elizabethtown Gas is currently conducting remedialremediation activities with oversight from the New Jersey Department of Environmental Protection. Although we cannot estimate the actual total cost of future environmental investigation and remediation efforts cannot be estimated with precision, based on probabilistic models similar to those used at Atlanta Gas Light’s former operating sites, the range of reasonably probable costs is from $30$57 million to $116$104 million. As of December 31, 2004,2005, no value within this range was a better estimate than any other value, so we have recorded a liability equal to the low end of $30 million, as this is the best estimate at this phase of the remediation process.that range, or $57 million.
Elizabethtown Gas’ prudentlyPrudently incurred remediation costs for the New Jersey properties have been authorized by the NJBPU to be recoverable in rates through its Remediation Adjustment Clause.a remediation adjustment clause. As a result, Elizabethtown Gas has recorded a regulatory asset of approximately $34$63 million, inclusive of interest, as of December 31, 2004,2005, reflecting the future recovery of both incurred costs and future remediation liabilities in the state of New Jersey.accrued carrying charges. Elizabethtown Gas has also been successful in recovering a portion of remediation costs incurred in New Jersey from its insurance carriers and continues to pursue additional recovery. As of December 31, 2004, the variation between the amounts of the environmental remediation cost liability recorded on the consolidated balance sheet and the associated regulatory asset result from expenditures for environmental investigation and remediation exceeding recoveries from ratepayers and insurance carriers.
OtherSites in North Carolina We also own a former NUI remediation site in Elizabeth City, North Carolina whichthat is subject to ana remediation order by the North Carolina Department of Energy and Natural Resources. We do notcurrently have preciseonly partial information regarding environmental impacts at the Elizabeth City site, and therefore we can make quantitative cost estimates only for the costlimited components of investigating and remediatinga site cleanup. However, experience at other similar sites suggests that costs for remediation of this site although preliminary estimates for these costswill likely range from $4$10 million to $16$17 million. As of December 31, 2004,2005, we have recorded a liability of $4$10 million related to this site.
There is anotherone other site in North Carolina where investigation and remediation is probable,likely, although no regulatoryremediation order exists and we do not believe costs associated with this site can be reasonably estimated. In addition, there are as many as six other sites with which NUI had some association, although no basis for liability has been asserted. We doasserted, and accordingly we have not believe that costs to investigate and remediate these sites, ifaccrued any can be reasonably estimated at this time.
With respect to these costs weremediation liability. There are currently pursuing or intend to pursueno cost recovery from ratepayers, former owners and operators and insurance carriers. Although we have been successfulmechanisms for the environmental remediation sites in recovering a portion of these remediation costs from our insurance carriers, we are not able to express a belief as to the success of additional recovery efforts. We are working with the regulatory agencies to prudently manage our remediation costs so as to mitigate the impact of such costs on both ratepayers and shareholders.North Carolina.
Employee Benefit Plans
Pension Benefits
We sponsor two tax-qualified defined benefit retirement plans (Retirement Plan) for our eligible employees, the AGL Resources Inc. Retirement Plan (AGL Retirement Plan) and the NUI Corporation Retirement Plan (NUI Retirement Plan). A defined benefit plan specifies the amount of benefits an eligible participant eventually will receive using information about the participant.
We generally calculate the benefits under the AGL Retirement Plan based on age, years of service and pay. The benefit formula for the AGL Retirement Plan is a career average earnings formula, except for participants other than those participants who were employees as of July 1, 2000 and who were at least 50 years of age as of that date. We utilizeFor those participants, we use a final average earnings benefit formula, for participants who were both employees and over age 50 as of July 1, 2000, and will continue to utilize the final average earningsuse this benefit formula for such participants until June 2010, at which time weany of those participants who are still active will convert those Retirement Plan participants to aaccrue future benefits under the career average earnings formula.
The NUI hasRetirement Plan is a qualified noncontributingnoncontributory defined benefit retirement plan that covers substantially all of itsNUI’s employees other thanexcept Florida City Gas Company union employees, who participate in a union sponsored multi-employerunion-sponsored multiemployer plan. Pension benefits are based on the number of years of credited service and on final average compensation.
Effective with our acquisition of NUI in November 2004, we now administer the NUI Retirement Plan. Throughout 2005, we will maintainmaintained existing benefits for NUI employees, including participation in the NUI Retirement Plan. Beginning in 2006, eligible non-union participants in the NUI Retirement Plan will become eligible to participate in the AGL Resources Retirement Plan. Currently,Plan and the benefits of those participants under the NUI Retirement Plan were frozen as of December 31, 2005, resulting in a $15 million reduction to the NUI Retirement Plan’s projected benefit obligation as of December 31, 2005. Participants in the NUI Retirement Plan have the option of receiving a lump sum distribution upon retirement whichfor all benefits earned through December 31, 2005. This option is not permitted under the AGL Retirement Plan. However, the option to receive a lump sum payment will be provided for all benefits earned through December 31, 2005. The following tables present details about our pension plans:
| | AGL Retirement Plan | | NUI Retirement Plan | |
In millions | | Dec. 31, 2004 | | Dec. 31, 2003 | | Dec. 31, 2004 | |
Change in benefit obligation | | | | | | | |
Benefit obligation at beginning of year | | $ | 314 | | $ | 290 | | $ | 144 | |
Service cost | | | 5 | | | 4 | | | - | |
Interest cost | | | 19 | | | 19 | | | 1 | |
Actuarial loss | | | 21 | | | 20 | | | - | |
Benefits paid | | | (19 | ) | | (19 | ) | | (1 | ) |
Benefit obligation at end of year | | $ | 340 | | $ | 314 | | $ | 144 | |
Change in plan assets | | | | | | | | | | |
Fair value of plan assets at beginning of year | | $ | 259 | | $ | 208 | | $ | 108 | |
Actual return on plan assets | | | 26 | | | 48 | | | 4 | |
Employer contribution | | | 13 | | | 22 | | | - | |
Benefits paid | | | (19 | ) | | (19 | ) | | (1 | ) |
Fair value of plan assets at end of year | | $ | 279 | | $ | 259 | | $ | 111 | |
Funded status | | | | | | | | | | |
Plan assets less than benefit obligation at end of year | | | ($61 | ) | | ($55 | ) | | ($33 | ) |
Unrecognized net loss | | | 108 | | | 95 | | | - | |
Unrecognized prior service benefit | | | (11 | ) | | (12 | ) | | (3 | ) |
Accrued pension cost | | $ | 36 | | $ | 28 | | | ($36 | ) |
Amounts recognized in the statement of financial position consist of | | | | | | | | | | |
Prepaid benefit cost | | $ | 43 | | $ | 34 | | $ | - | |
Accrued benefit liability | | | (7 | ) | | (7 | ) | | (36 | ) |
Accumulated OCI | | | (84 | ) | | (66 | ) | | - | |
Net amount recognized at year end | | | ($48 | ) | | ($39 | ) | | ($36 | ) |
plans.
| | AGL Retirement Plan | | NUI Retirement Plan | |
| | Dec, 31, 2005 | | Dec. 31, 2004 | | Dec. 31, 2005 | | Dec. 31, 2004 | |
Change in benefit obligation | | | | | | | | | |
Benefit obligation at beginning of year | | $ | 340 | | $ | 314 | | $ | 144 | | $ | 144 | |
Service cost | | | 6 | | | 5 | | | 4 | | | - | |
Interest cost | | | 19 | | | 19 | | | 8 | | | 1 | |
Plan amendments | | | - | | | - | | | (15 | ) | | - | |
Actuarial loss (gain) | | | 14 | | | 21 | | | (4 | ) | | - | |
Benefits paid | | | (20 | ) | | (19 | ) | | (32 | ) | | (1 | ) |
Benefit obligation at end of year | | $ | 359 | | $ | 340 | | $ | 105 | | $ | 144 | |
Change in plan assets | | | | | | | | | | | | | |
Fair value of plan assets at beginning of year | | $ | 279 | | $ | 259 | | $ | 111 | | $ | 108 | |
Actual return on plan assets | | | 21 | | | 26 | | | 6 | | | 4 | |
Employer contribution | | | 6 | | | 13 | | | - | | | - | |
Benefits paid | | | (20 | ) | | (19 | ) | | (32 | ) | | (1 | ) |
Fair value of plan assets at end of year | | $ | 286 | | $ | 279 | | $ | 85 | | $ | 111 | |
Funded status | | | | | | | | | | | | | |
Plan assets less than benefit obligation at end of year | | $ | (73 | ) | $ | (61 | ) | $ | (20 | ) | $ | (33 | ) |
Unrecognized net loss | | | 119 | | | 108 | | | 4 | | | - | |
Unrecognized prior service benefit | | | (10 | ) | | (11 | ) | | (15 | ) | | (3 | ) |
Accrued (prepaid) pension cost (1) | | $ | 36 | | $ | 36 | | $ | (31 | ) | $ | (36 | ) |
Amounts recognized in the statement of financial position consist of | | | | | | | | | | | | | |
Prepaid benefit cost | | $ | 42 | | $ | 43 | | $ | - | | $ | - | |
Accrued benefit liability | | | (7 | ) | | (7 | ) | | (31 | ) | | (36 | ) |
Accumulated OCI | | | (92 | ) | | (84 | ) | | - | | | - | |
Net amount recognized at year end | | $ | (57 | ) | $ | (48 | ) | $ | (31 | ) | $ | (36 | ) |
(1) The prepaid pension cost for the NUI Retirement Plan at December 31, 2005 was adjusted for terminations and settlement of liabilities for participants affected by our acquisition of NUI in November 2004. We recorded the associated $9 million reduction in our benefit obligation as a reduction to goodwill. |
The accumulated benefit obligation (ABO) for our retirement plan and other information for our pension plansthe AGL Retirement Plan and the NUI Retirement Plan are indicatedset forth in the following tables:table.
| | AGL Retirement Plan | | NUI Retirement Plan | |
| | Dec. 31, 2005 | | Dec. 31, 2004 | | Dec. 31, 2005 | | Dec. 31, 2004 | |
Projected benefit obligation | | $ | 359 | | $ | 340 | | $ | 105 | | $ | 144 | |
ABO | | | 343 | | | 327 | | | 105 | | | 118 | |
Fair value of plan assets | | | 286 | | | 279 | | | 85 | | | 111 | |
Increase in minimum liability included in OCI | | | 8 | | | 18 | | | - | | | - | |
Components of net periodic benefit cost | | | | | | | | | |
Service cost | | $ | 6 | | $ | 5 | | $ | 4 | | $ | - | |
Interest cost | | | 19 | | | 19 | | | 8 | | | 1 | |
Expected return on plan assets | | | (24 | ) | | (23 | ) | | (9 | ) | | (1 | ) |
Net amortization | | | (1 | ) | | (1 | ) | | - | | | - | |
Recognized actuarial loss | | | 7 | | | 5 | | | - | | | - | |
Net annual pension cost | | $ | 7 | | $ | 5 | | $ | 3 | | $ | - | |
| | AGL Retirement Plan | | NUI Retirement Plan | |
| | Dec. 31, 2004 | | Dec. 31, 2003 | | Dec. 31, 2004 | |
Projected benefit obligation | | $ | 340 | | $ | 314 | | $ | 144 | |
ABO | | | 327 | | | 298 | | | 118 | |
Fair value of plan assets | | | 279 | | | 259 | | | 111 | |
Increase (decrease) in minimum liability included in OCI | | | 18 | | | (14 | ) | | - | |
Components of net periodic benefit cost | | | | | | | |
Service cost | | $ | 5 | | $ | 4 | | $ | - | |
Interest cost | | | 19 | | | 19 | | | 1 | |
Expected return on plan assets | | | (23 | ) | | (22 | ) | | (1 | ) |
Net amortization | | | (1 | ) | | (1 | ) | | - | |
Recognized actuarial (gain) loss | | | 5 | | | 2 | | | - | |
Net annual pension cost | | $ | 5 | | $ | 2 | | $ | - | |
The following table indicates ourset forth the assumed weighted average assumptionsdiscount rates and rates of compensation increase used to determine benefit obligations at the balance sheet date:dates.
| | AGL Retirement Plan | | NUI Retirement Plan | | | AGL and NUI Retirement Plans | |
| | Dec. 31, 2004 | | Dec. 31, 2003 | | Dec. 31, 2004 | | | Dec. 31, 2005 | | Dec. 31, 2004 | |
Discount rate | | | 5.8 | % | | 6.3 | % | | 5.8 | % | | | 5.5 | % | | 5.8 | % |
Rate of compensation increase | | | 4.0 | % | | 4.5 | % | | 4.0 | % | | | 4.0 | % | | 4.0 | % |
We consider a number of factors in the determinationdetermining and selection of ourselecting assumptions offor the overall expected long-term rate of return on plan assets. We consider the historical long-term return experience of our assets, the current and expected allocation of our plan assets, as well asand expected long-term rates of return. We derive these expected long-term rates of return with the assistance of our investment advisors and generally base these rates on a 10-year horizon for various asset classes, our expected investments of plan assets and active asset management as opposed to investment in a passive index fund. We base our expected allocation of plan assets on a diversified portfolio consisting of domestic and international equity securities, fixed income, real estate, private equity securities and alternative asset classes.
As of December 1, 2004,The following tables present the assumed weighted average discount rate, used to determine NUI’s opening balance sheet benefit obligation was 5.8%. This discountexpected return on plan assets and rate was also utilized to determine net periodic benefit cost for the month of December 2004. The following table presents the weighted average assumptionscompensation increase used to determine net periodic benefit cost at the beginning of the period, which was January 1,1.
| | AGL Retirement Plan | |
| | Dec. 31, 2005 | | Dec. 31, 2004 | |
Discount rate | | | 5.8 | % | | 6.3 | % |
Expected return on plan assets | | | 8.8 | % | | 8.8 | % |
Rate of compensation increase | | | 4.0 | % | | 4.0 | % |
| | NUI Retirement Plan | |
| | Dec. 31, 2005 | | Dec. 31, 2004 | |
Discount rate | | | 5.8 | % | | 5.8 | % |
Expected return on plan assets | | | 8.5 | % | | 8.5 | % |
Rate of compensation increase | | | 4.0 | % | | 4.0 | % |
We consider a number of factors in determining and selecting our assumptions for the AGL Retirement Plan.
| | AGL Retirement Plan | | NUI Retirement Plan | |
| | Dec. 31, 2004 | | Dec. 31, 2003 | | Dec. 31, 2004 | |
Discount rate | | | 6.3 | % | | 6.8 | % | | 5.8 | % |
Expected return on plan assets | | | 8.8 | % | | 8.8 | % | | 8.5 | % |
Rate of compensation increase | | | 4.0 | % | | 4.5 | % | | 4.0 | % |
discount rate at December 31. We consider certain market indices, including the Moody’s Corporate AA long-term bond rate of 5.41% and the Citigroup Pension Liability rate of 5.51%, at December 31, 2005. We further use these market indices as a comparison to a single equivalent discount rate derived with the assistance of our actuarial advisors. The single equivalent discount rate is based on a yield-to-maturity regression analysis of a portfolio of corporate bonds rated AA by Moody’s and that have cash outflows consistent with payouts from our retirement plans. This analysis as of December 31, 2005 produced a single equivalent discount rate of 5.63%. Consequently, we selected a discount rate of 5.5% as of December 31, 2005, following our review of these various factors.
Our Retirement Plans’actual retirement plans’ weighted average asset allocations at December 31, 20042005 and 20032004 and our target asset allocation ranges are as follows:follows.
| | Target Range Allocation of | | AGL Retirement Plan | |
| | Assets | | 2005 | | 2004 | |
Equity | | | 40%-85 | % | | 66 | % | | 71 | % |
Fixed income | | | 25%-50 | % | | 25 | % | | 25 | % |
Real estate and other | | | 0%-10 | % | | 8 | % | | 3 | % |
Cash | | | 0%-10 | % | | 1 | % | | 1 | % |
| | | | Actual allocation on a weighted average basis | | |
| | | | AGL Resources Retirement Plan | | NUI Retirement Plan | | | Target Range Allocation of | | NUI Retirement Plan | |
| | Target Range Allocation of Assets | | 2004 | | 2003 | | 2004 | | | Assets | | 2005 | | 2004 | |
Equity | | | 40%-85 | % | | 71 | % | | 67 | % | | 72 | % | | | 40%-85 | % | | 88 | % | | 72 | % |
Fixed income | | | 25%-50 | % | | 25 | | | 30 | | | 28 | | | | 25%-50 | % | | 12 | % | | 28 | % |
Real estate and other | | | 0%-10 | % | | 3 | | | - | | | - | | | | 0%-10 | % | | - | | | - | |
Cash | | | 0%-10 | % | | 1 | | | 3 | | | - | | | | 0%-10 | % | | - | | | - | |
The Retirement Plan Investment Committee (the Committee) appointed by our Board of Directors andis responsible for overseeing the investments of the Retirement Plan.retirement plans. Further, we have an Investment Policy (the Policy) for the Retirement Plans, which has a goalretirement plans that aims to preserve the Retirement Plan’sretirement plans’ capital and maximize investment earnings in excess of inflation within acceptable levels of capital market volatility. To accomplish this goal, the Retirement Planretirement plans assets are actively managed with the objective of optimizingto optimize long-term return while maintaining a high standard of portfolio quality and proper diversification.
The Policy’s risk management strategy establishes a maximum tolerance for risk in terms of volatility to be measured at 75% of the volatility experienced by the S&P 500. We will continue to more broadly diversify the Retirement Planretirement plan investments to minimize the risk of large losses in a single asset class. The Policy’s permissible investments include domestic and international equities (including convertible securities and mutual funds), domestic and international fixed income (corporate and U.S. government obligations), cash and cash equivalents and other suitable investments. The asset mix of these permissible investments is maintained within the Policy’s target allocations as included in the table above, but the Committee can establish differentvary allocations between various classes and/or investment managers in order to better achieve expectedimprove investment results.
Equity market performance and corporate bond rates have a significant effect on our reported unfunded ABO, as the primary factors that drive the value of our unfunded ABO are the assumed discount rate and the actual return on plan assets. Additionally, equity market performance has a significant effect on our market-related value of plan assets (MRVPA), which is a calculated value and differs from the actual market value of plan assets. The MRVPA recognizes the differencesdifference between the actual market value and expected market value of our plan assets and is determined by our actuaries using a five-year moving weighted average methodology. Gains and losses on plan assets are spread through the MRVPA based on the five-year moving weighted average methodology, which affects the expected return on plan assets component of pension expense.
Our employees do not contribute to the Retirement Plans.retirement plans. We fund the planplans by contributing at least the minimum amount required by applicable regulations and as recommended by our actuary. We calculate the amount of funding using an actuarial method called the projected unit credit cost method. However, we may also fund the Retirement Planscontribute in excess of the minimum required amount. We calculate the minimum amount of funding using the projected unit credit cost method. We do not expect to make a $1 millionany contribution to the pension plans in 2005.2006.
Postretirement Benefits
We sponsor two defined benefit postretirement health care plans for our eligible employees, the AGL Resources Inc. Postretirement Health Care Plan (AGL Postretirement Plan) and the NUI Corporation Postretirement Plan Health Care Plan (NUI Postretirement Plan)., which we acquired upon our acquisition of NUI. Eligibility for these benefits is based on age and years of service.
The NUI Postretirement Plan provides certain medical and dental healthcarehealth care benefits to retirees, other than retirees of Florida City Gas, Company, depending on their age, years of service and start date. The healthcare plans areNUI Postretirement Plan is contributory, and NUI funded a portion of these future benefits through a Voluntary Employees’ Beneficiary Association. Effective July 2000, NUI no longer offersoffered postretirement benefits other than pensions for any new hires. In addition, NUI capped its share of costs at $500 per participant per month for retirees under age 65, and at $150 per participant per month for retirees over age 65. Effective with our acquisition of NUI, we acquired the NUI Postretirement Plan. Beginning in 2006, eligible participants in the NUI Postretirement Plan will become eligible to participate in the AGL Postretirement Plan.
The AGL Postretirement Plan covers all eligible AGL Resources’Resources employees who were employed as of June 30, 2002, if they reach retirement age while working for us. In addition, theThe state regulatory commissions have approved phase-ins that defer a portion of other postretirement benefits expense for future recovery. We recorded a regulatory asset for these future recoveries of $14 million as of December 31, 20042005 and $9$14 million as of December 31, 2003.2004. In addition, we recorded a regulatory liability of $3 million as of December 31, 2005 and $2 million as of December 31, 2004 and $2 million as of December 31, 2003.
for our expected expenses under the AGL Postretirement Plan.
Effective December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Prescription Drug Act) was signed into law. This act provides for a prescription drug benefit under Medicare (Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.
EffectiveOn July 1, 2004, the AGL Postretirement Plan was amended to remove prescription drug coverage for Medicare-eligible retirees effective January 1, 2006. Certain grandfathered NUI retirees participating in the NUI Postretirement Plan will continue receiving a prescription drug benefit forthrough some period of time.
The AGL Resources Postretirement Plan’s accumulated postretirement benefit obligation decreased by approximately $24 million due and net annual cost decreased by $2 million due to the elimination of prescription drug coverage for Medicare-eligible retirees. The 2004 net periodic postretirement benefit cost reflects both the plan amendment to remove prescription drug coverage under the AGL Postretirement Plan, described above, and the federal subsidy for NUI grandfathered retirees. The following tables present details about our postretirement benefits:
| | AGL Postretirement Plan | | NUI Postretirement Plan | |
In millions | | Dec. 31, 2004 | | Dec. 31, 2003 | | Dec. 31, 2004 | |
Change in benefit obligation | | | | | | | |
Benefit obligation at beginning of year | | $ | 134 | | $ | 129 | | $ | 23 | |
Service cost | | | 1 | | | 1 | | | - | |
Interest cost | | | 7 | | | 8 | | | - | |
Plan amendments | | | (24 | ) | | - | | | - | |
Actuarial loss | | | (12 | ) | | 6 | | | - | |
Benefits paid | | | (8 | ) | | (10 | ) | | - | |
Benefit obligation at end of year | | $ | 98 | | $ | 134 | | $ | 23 | |
Change in plan assets | | | | | | | | | | |
Fair value of plan assets at beginning of year | | $ | 44 | | $ | 38 | | $ | 9 | |
Actual return on plan assets | | | 5 | | | 8 | | | - | |
Employer contribution | | | 8 | | | 8 | | | - | |
Benefits paid | | | (8 | ) | | (10 | ) | | - | |
Fair value of plan assets at end of year | | $ | 49 | | $ | 44 | | $ | 9 | |
Funded status | | | | | | | | | | |
ABO in excess of plan assets | | | ($49 | ) | | ($90 | ) | | ($14 | ) |
Unrecognized loss | | | 30 | | | 44 | | | - | |
Unrecognized transition amount | | | 1 | | | 1 | | | - | |
Unrecognized prior service cost (benefit) | | | (26 | ) | | (6 | ) | | - | |
Accrued benefit cost | | | ($44 | ) | | ($51 | ) | | ($14 | ) |
Amounts recognized in the statement of financial position consist of | | | | | | | | | | |
Prepaid benefit cost | | $ | - | | $ | - | | $ | - | |
Accrued benefit liability | | | (44 | ) | | (51 | ) | | (14 | ) |
Accumulated OCI | | | - | | | - | | | - | |
Net amount recognized at year end | | | ($44 | ) | | ($51 | ) | | ($14 | ) |
benefits.
| | AGL Postretirement Plan | | NUI Postretirement Plan | |
In millions | | Dec. 31, 2005 | | Dec. 31, 2004 | | Dec, 31, 2005 | | Dec. 31, 2004 | |
Change in benefit obligation | | | | | | | | | |
Benefit obligation at beginning of year | | $ | 98 | | $ | 134 | | $ | 23 | | $ | 23 | |
Service cost | | | 1 | | | 1 | | | - | | | - | |
Interest cost | | | 5 | | | 7 | | | 1 | | | - | |
Plan amendments | | | - | | | (24 | ) | | (7 | ) | | - | |
Actuarial (gain) loss | | | (6 | ) | | (12 | ) | | 3 | | | - | |
Benefits paid | | | (9 | ) | | (8 | ) | | (2 | ) | | - | |
Benefit obligation at end of year | | $ | 89 | | $ | 98 | | $ | 18 | | $ | 23 | |
Change in plan assets | | | | | | | | | | | | | |
Fair value of plan assets at beginning of year | | $ | 49 | | $ | 44 | | $ | 9 | | $ | 9 | |
Actual return on plan assets | | | 4 | | | 5 | | | - | | | - | |
Employer contribution | | | 6 | | | 8 | | | 2 | | | - | |
Benefits paid | | | (9 | ) | | (8 | ) | | (2 | ) | | - | |
Fair value of plan assets at end of year | | $ | 50 | | $ | 49 | | $ | 9 | | $ | 9 | |
Funded status | | | | | | | | | | | | | |
ABO in excess of plan assets | | $ | (39 | ) | $ | (49 | ) | $ | (9 | ) | $ | (14 | ) |
Unrecognized loss | | | 22 | | | 30 | | | 2 | | | - | |
Unrecognized transition amount | | | 1 | | | 1 | | | - | | | - | |
Unrecognized prior service benefit | | | (23 | ) | | (26 | ) | | (6 | ) | | - | |
Accrued benefit cost | | $ | (39 | ) | $ | (44 | ) | $ | (13 | ) | $ | (14 | ) |
Amounts recognized in the statement of financial position consist of | | | | | | | | | | | | | |
Prepaid benefit cost | | $ | - | | $ | - | | $ | - | | $ | - | |
Accrued benefit liability | | | (39 | ) | | (44 | ) | | (13 | ) | | (14 | ) |
Accumulated OCI | | | - | | | - | | | - | | | - | |
Net amount recognized at year end | | $ | (39 | ) | $ | (44 | ) | $ | (13 | ) | $ | (14 | ) |
The following table presents details on the components of our net periodic benefit costscost at the balance sheet date:dates for the AGL Postretirement Plan. Amounts for the NUI Postretirement Plan were not material in 2004.
| | AGL Postretirement Plan | | NUI Postretirement Plan | | | AGL Postretirement Plan | |
In millions | | 2004 | | 2003 | | 2004 | | | 2005 | | 2004 | |
Service cost | | $ | 1 | | $ | 1 | | $ | - | | | $ | 1 | | $ | 1 | |
Interest cost | | | 7 | | | 8 | | | - | | | | 5 | | | 7 | |
Expected return on plan assets | | | (3 | ) | | (3 | ) | | - | | | | (4 | ) | | (3 | ) |
Amortization of transition amount | | | (2 | ) | | - | | | - | | |
Amortization of regulatory asset | | | 1 | | | 2 | | | - | | |
Amortization of prior service cost | | | | (3 | ) | | (2 | ) |
Recognized actuarial loss | | | | 1 | | | 1 | |
Net periodic postretirement benefit cost | | $ | 4 | | $ | 8 | | $ | - | | | $ | - | | $ | 4 | |
| |
| | NUI Postretirement Plan | |
In millions | | 2005 | |
Service cost | | $ | - | |
Interest cost | | | 1 | |
Expected return on plan assets | | | - | |
Amortization of prior service cost | | | (1 | ) |
Recognized actuarial loss | | | - | |
Net periodic postretirement benefit cost | | $ | - | |
The following table presentstables present our weighted average assumptionsassumed rates used to determine benefit obligations at the beginning of the period, which was January 1 for the AGL Postretirement Plan and December 1 for the NUI Postretirement Plan:
| | AGL Postretirement Plan | | NUI Postretirement Plan | |
| | 2004 | | 2003 | | 2004 | |
Discount rate | | | 5.8 | % | | 6.3 | % | | 5.8 | % |
The following table presents ourweightedPlan, and our weighted average assumptionsassumed rates used to determine net periodic benefit cost:
| | AGL Postretirement Plan | | NUI Postretirement Plan | |
| | 2004 | | 2003 | | 2004 | |
Discount rate | | | 6.3 | % | | 6.8 | % | | 5.8 | % |
Expected return on plan assets | | | 8.8 | % | | 8.8 | % | | 2.0 | % |
Rate of compensation increase | | | 4.0 | % | | 4.5 | % | | - | |
cost at the beginning of these same periods.
| | AGL Postretirement Plan | |
| | 2005 | | 2004 | |
Discount rate - benefit obligation | | | 5.5 | % | | 5.8 | % |
Discount rate - net periodic benefit cost | | | 5.8 | % | | 6.3 | % |
Expected return on plan assets | | | 8.8 | % | | 8.8 | % |
Rate of compensation increase | | | 4.0 | % | | 4.0 | % |
| | NUI Postretirement Plan | |
| | 2005 | | 2004 | |
Discount rate - benefit obligation | | | 5.5 | % | 5.8% |
Discount rate - net periodic benefit cost | | | 5.8 | % | 5.8% |
Expected return on plan assets | | | 3.0 | % | 2.0% |
Rate of compensation increase | | | - | | - |
For information on the discount rate assumptions used for our postretirement plans, see discussion contained in Note 6 under Pension Benefits.
We consider the same factors in the determinationdetermining and selection ofselecting our assumptions offor the overall expected long-term rate of return on plan assets as those considered in the determinationdetermining and selection ofselecting the overall expected long-term rate of return on plan assets for our Retirement Plan.retirement plans. For purposes of measuring our accumulated postretirement benefit obligation, the assumed pre-Medicare and post-Medicare health care inflation rates are as follows:follows.
| | AGL Postretirement Plan | |
| | Pre-Medicare Cost (pre-65 years old) | | Post-Medicare Cost (post-65 years old) | |
Assumed Health Care Cost Trend Rates at December 31, | | 2005 | | 2004 | | 2005 | | 2004 | |
Health care costs trend assumed for next year | | | 2.5 | % | | 11.3 | % | | 2.5 | % | | 11.3 | % |
Rate to which the cost trend rate gradually declines | | | 2.5 | % | | 2.5 | % | | 2.5 | % | | 2.5 | % |
Year that the rate reaches the ultimate trend rate | | | N/A | | | 2006 | | | N/A | | | 2006 | |
| | AGL Postretirement Plan | |
| | Pre-Medicare Cost (pre-65 years old) | | Post-Medicare Cost (post-65 years old) | |
Assumed Health Care Cost Trend Rates at December 31, | | 2004 | | 2003 | | 2004 | | 2003 | |
Health care costs trend assumed for next year | | | 11.3 | % | | 10.0 | % | | 11.3 | % | | 12.0 | % |
Rate to which the cost trend rate gradually declines | | | 2.5 | % | | 5.0 | % | | 2.5 | % | | 5.0 | % |
Year that the rate reaches the ultimate trend rate | | | 2006 | | | 2010 | | | 2006 | | | 2011 | |
| | NUI Postretirement Plan | |
Assumed Health Care Cost Trend Rates at December 31, | | 2004 | |
Health care costs trend assumed for next year | | | 9.0 | % |
Rate to which the cost trend rate gradually declines | | | 5.0 | % |
Year that the rate reaches the ultimate trend rate | | | 2008 | |
| | NUI Postretirement Plan | |
Assumed Health Care Cost Trend Rates at December 31, | | 2005 | | 2004 | |
Health care costs trend assumed for next year | | | 2.5 | % | | 9.0 | % |
Rate to which the cost trend rate gradually declines | | | 2.5 | % | | 5.0 | % |
Year that the rate reaches the ultimate trend rate | | | N/A | | | 2008 | |
Effective January 2006, our health care trend rates for both the AGL Postretirement and NUI Postretirement Plans have been capped at 2.5%. This cap limits the increase in our contributions to the annual change in the consumer price index (CPI). An annual CPI rate of 2.5% was assumed for future years.
Assumed health care cost trend rates have a significant effect onimpact the amounts reported for our health care plans. A one-percentage-point change in the assumed health care cost trend rates would have the following effects:effects for the AGL Postretirement Plan and the NUI Postretirement Plan.
| | One-Percentage-Point | |
In millions | | Increase | | Decrease | |
Effect on total of service and interest cost(1) | | $ | 1 | | | ($1 | ) |
Effect on accumulated postretirement benefit obligation(1) | | | 6 | | | (6 | ) |
| | AGL Postretirement Plan | |
| | One-Percentage-Point | |
In millions | | Increase | | Decrease | |
Effect on total of service and interest cost | | $ | - | | $ | - | |
Effect on accumulated postretirement benefit obligation | | | 4 | | | (3 | ) |
(1) | There were no material amounts for the NUI Postretirement benefit obligation or interest costs. |
| | NUI Postretirement Plan | |
| | One-Percentage-Point | |
In millions | | Increase | | Decrease | |
Effect on total of service and interest cost | | $ | - | | $ | - | |
Effect on accumulated postretirement benefit obligation | | | 2 | | | (1 | ) |
The following table presents expected benefit payments covering the periods 20052006 through 20142015 for our qualified pension plans, unqualified pension plans, and postretirement healthcarehealth care plans. There will be benefit payments under these plans beyond 2014.2015.
| | AGL Resources’ plans | | NUI’s plans | | |
For the year ended Dec. 31,(in millions) | | Pension plan | | Postretirement healthcare plans | | Pension plan | | Postretirement healthcare plans | | | AGL Retirement Plan | | AGL Postretirement Plan | |
2005 | | $ | 19 | | $ | 8 | | $ | 17 | | $ | 2 | | |
2006 | | | 18 | | | 7 | | | 8 | | | 2 | | | $ | 19 | | $ | 6 | |
2007 | | | 18 | | | 7 | | | 8 | | | 2 | | | | 19 | | | 6 | |
2008 | | | 18 | | | 7 | | | 9 | | | 2 | | | | 19 | | | 6 | |
2009 | | | 19 | | | 7 | | | 9 | | | 2 | | | | 19 | | | 6 | |
2010-2014 | | | 101 | | | 34 | | | 61 | | | 9 | | |
2010 | | | | 19 | | | 6 | |
2011-2015 | | | | 105 | | | 31 | |
For the year ended Dec. 31, (in millions) | | NUI Retirement Plan | | NUI Postretirement Plan | |
2006 | | $ | 7 | | $ | 1 | |
2007 | | | 7 | | | 1 | |
2008 | | | 7 | | | 1 | |
2009 | | | 7 | | | 1 | |
2010 | | | 8 | | | 1 | |
2011-2015 | | | 45 | | | 5 | |
Our investment policies and strategies for our postretirement plans, including target allocation ranges, are similar to those offor our Retirement Plan.Weretirement plans. We fund the plan annually, andplans annually; retirees contribute 20% of medical premiums, 50% of the medical premium for spousal coverage and 100% of the dental premium. Our postretirement benefit plan’s weighted-averageplans, weighted average asset allocations for 2004, 20032005 and 20022004 and our target asset allocation ranges are as follows:follows.
| | Target Asset Allocation Ranges | �� | 2004 | | 2003 | | | Target Asset Allocation Ranges | | 2005 | | 2004 | |
Equity | | | 40%-85 | % | | 67 | % | | 59 | % | | | 40%-85 | % | | 52 | % | | 67 | % |
Fixed income | | | 25%-50 | % | | 32 | % | | 40 | % | | | 25%-50 | % | | 46 | % | | 32 | % |
Real Estate and other | | | 0%-10 | % | | - | % | | - | % | |
Real estate and other | | | | 0%-10 | % | | 1 | % | | - | % |
Cash | | | 0%-10 | % | | 1 | % | | 1 | % | | | 0%-10 | % | | 1 | % | | 1 | % |
Employee Savings Plan Benefits
We sponsor the Retirement Savings Plus Plan (RSP), a defined contribution benefit plan that allows eligible participants to make contributions to their accounts up to specified limits to its account.limits. Under the RSP, we made matching contributions to participant accounts in the following amounts:
We also sponsor the Nonqualified Savings Plan (NSP), an unfunded, nonqualified plan similar to the RSP. The NSP provides an opportunity for eligible employees who could reach the maximum contribution amount in the RSP to contribute additional amounts for retirement savings. Our contributions to the NSP werehave not significant.been significant in any year.
Effective December 1, 2004, all NUI employees who were participating in NUI’s qualified defined contribution benefit plan were eligible to participate in the RSP, and those who were participants in NUI’s nonqualified defined contribution plan became eligible to participate in the NSP.
Stock-based and Other Incentive Compensation Plans
Employee Stock-based Compensation Plans and Agreements
We currently sponsor the following stock-based compensation plans
· | The Long-Term Incentive Plan (1999)(LTIP) provides for grants of performance units, restricted stock and incentive and nonqualified stock options, performance units and shares of restricted stocks to key employees. The LTIP currently authorizes the issuance of up to 7.99.5 million shares of our common stock. |
· | A predecessor plan, the Long-Term Stock Incentive Plan (LTSIP), provides for grants of restricted stock, incentive and nonqualified stock options, shares of restricted stocks and stock appreciation rights (SARs) to key employees. Following shareholder approval of the LTIP, no further grants have been made under the LTSIP. |
· | The Officer Incentive Plan (Officer Plan) provides for grants of nonqualified stock options and shares of restricted stock to new-hire officers. The Officer Plan authorizes the issuance of up to 600,000 shares of our common stock. |
· | SARsStock Appreciation Rights (SARs) have been granted to key employees under individual agreements that permit the holder to receive cash in an amount equal to the difference between the fair market value of a share of our common stock on the date of exercise and the SAR base value. A total of 26,863 SARs currently are outstanding.were outstanding as of December 31, 2005. |
· | We amended theThe 1996 Non-Employee Directors Equity Compensation Plan (Directors Plan), in which all originally provided for the grant of nonqualified stock options and shares of restricted stock to nonemployee directors participate,as payment of their annual retainer. In December 2002, the Directors Plan was amended to eliminate the granting of stock options effective December 2002.options. As a result, the Directors Plan now provides solely for the issuance of restrictedour common stock. It currentlyThe Directors Plan authorizes the issuance of up to 200,000 shares of our common stock. |
The following table summarizes activity for key employees and nonemployee directors related to grants of stock options:
| | Number of | | Weighted Average | |
| | Options | | Exercise Price | |
Outstanding-December 31, 2001 | | | 3,587,501 | | $ | 20.06 | |
Granted | | | 988,564 | | | 21.49 | |
Exercised | | | (785,853 | ) | | 19.28 | |
Forfeited | | | (156,255 | ) | | 21.59 | |
Outstanding-December 31, 2002 | | | 3,633,957 | | $ | 20.55 | |
Granted | | | 939,262 | | | 26.76 | |
Exercised | | | (863,112 | ) | | 20.08 | |
Forfeited | | | (199,137 | ) | | 22.00 | |
Outstanding-December 31, 2003 | | | 3,510,970 | | $ | 22.25 | |
Granted | | | 103,900 | | | 29.72 | |
Exercised | | | (1,050,053 | ) | | 20.90 | |
Forfeited | | | (390,745 | ) | | 22.44 | |
Outstanding-December 31, 2004 | | | 2,174,072 | | $ | 23.23 | |
Information about outstanding and exercisable options as of December 31, 2004 is as follows:
| | Options Outstanding | | Options Exercisable | |
Range of Exercise Prices | | Number of Options | | Weighted Average Remaining Contractual Life (in years) | | Weighted Average Exercise Price | | Number of Options | | Weighted Average Exercise Price | |
$13.75 to $17.49 | | | 2,199 | | | 5.0 | | $ | 16.99 | | | 2,199 | | $ | 16.99 | |
$17.50 to $19.99 | | | 201,640 | | | 3.8 | | $ | 18.85 | | | 199,973 | | $ | 18.84 | |
$20.00 to $24.10 | | | 1,164,156 | | | 5.5 | | $ | 21.23 | | | 1,126,827 | | $ | 21.17 | |
$24.11 to $30.00 | | | 751,936 | | | 8.4 | | $ | 26.97 | | | 325,737 | | $ | 26.91 | |
$30.01 to $34.00 | | | 54,141 | | | 6.2 | | $ | 31.07 | | | 3,524 | | $ | 31.20 | |
Outstanding-Dec. 31, 2004 | | | 2,174,072 | | | 6.4 | | $ | 23.23 | | | 1,658,260 | | $ | 22.04 | |
Summarized below are outstanding options that are fully exercisable:
| | Number of Options | | Weighted Average Exercise Price | |
Exercisable-December 31, 2002 | | | 2,483,756 | | $ | 20.07 | |
Exercisable-December 31, 2003 | | | 2,154,877 | | $ | 20.47 | |
Exercisable-December 31, 2004 | | | 1,658,260 | | $ | 22.04 | |
Our stock-based employee compensation plans are accounted for under the recognition and measurement principles ofAPB Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25), and related interpretations. For our stock option plans, we generally do not reflect stock-based employee compensation cost in net income, as options for those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. For our stock appreciation rights, we reflect stock-based employee compensation cost based on the fair value of our common stock at the balance sheet date since these awards constitute a variable plan under APB 25.
In accordance with the fair value method of determining compensation expense, we utilized the Black-Scholes pricing model and the estimate below for the years ended December 31, 2004, 2003 and 2002:
| | 2004 | | 2003 | | 2002 | |
Expected life (years) | | | 7 | | | 7 | | | 7 | |
Interest rate | | | 3.7 | % | | 3.8 | % | | 4.6 | % |
Volatility | | | 16.9 | % | | 19.2 | % | | 19.2 | % |
Dividend yield | | | 3.9 | % | | 4.2 | % | | 5.0 | % |
Fair value of options granted | | $ | 3.72 | | $ | 3.75 | | $ | 2.92 | |
Participants realize value from option grants or SARs only to the extent that the fair market value of our common stock on the date of exercise of the option or SAR exceeds the fair market value of the common stock on the date of the grant. The compensation costs that have been charged against income for performance units, restricted stock and other stock-based awards were $7 million in 2004, $8 million in 2003 and $2 million in 2002.· | The Employee Stock Purchase Plan (ESPP) is a nonqualified, broad-based employee stock purchase plan for eligible employees. The ESPP authorizes the issuance of up to 600,000 shares of our common stock. |
Incentive and Nonqualified Stock Options
We grant incentive and nonqualified stock options at the fair market value on the date of the grant. The vesting of incentive options is subject to a statutory limitation of $100,000 per year under Section 422A of the Internal Revenue Code. Otherwise, nonqualified options generally become fully exercisable not earlier than six months after the date of grant and generally expire 10 years after the date of grant. Participants realize value from option grants only to the extent that date.the fair market value of our common stock on the date of exercise of the option exceeds the fair market value of the common stock on the date of the grant.
The following table summarizes activity related to grants of stock options for key employees and nonemployee directors.
| | Number of | | Weighted Average | |
| | Options | | Exercise Price | |
Outstanding-Dec.31, 2002 | | | 3,633,957 | | $ | 20.55 | |
Granted | | | 939,262 | | | 26.76 | |
Exercised | | | (863,112 | ) | | 20.08 | |
Forfeited | | | (199,137 | ) | | 22.00 | |
Outstanding-Dec.31, 2003 | | | 3,510,970 | | $ | 22.25 | |
Granted | | | 103,900 | | | 29.72 | |
Exercised | | | (1,050,053 | ) | | 20.90 | |
Forfeited | | | (390,745 | ) | | 22.44 | |
Outstanding-Dec.31, 2004 | | | 2,174,072 | | $ | 23.23 | |
Granted | | | 1,014,121 | | | 33.80 | |
Exercised | | | (846,465 | ) | | 22.60 | |
Forfeited | | | (120,483 | ) | | 32.38 | |
Outstanding-Dec. 31, 2005 | | | 2,221,245 | | $ | 27.79 | |
In general, a performance unitInformation about outstanding and exercisable options as of December 31, 2005 is as follows.
| | Options Outstanding | | Options Exercisable | |
Range of Exercise Prices | | Number of Options | | Weighted Average Remaining Contractual Life (in years) | | Weighted Average Exercise Price | | Number of Options | | Weighted Average Exercise Price | |
$13.75 to $17.49 | | | 2,199 | | | 4.0 | | $ | 16.99 | | | 2,199 | | $ | 16.99 | |
$17.50 to $19.99 | | | 56,295 | | | 2.1 | | $ | 18.82 | | | 56,295 | | $ | 18.82 | |
$20.00 to $24.10 | | | 714,623 | | | 4.3 | | $ | 21.10 | | | 714,623 | | $ | 21.10 | |
$24.11 to $30.00 | | | 487,255 | | | 7.3 | | $ | 27.00 | | | 454,840 | | $ | 26.97 | |
$30.01 to $34.00 | | | 792,052 | | | 8.8 | | $ | 33.09 | | | 46,453 | | $ | 31.00 | |
$34.01 to $39.50 | | | 168,821 | | | 7.6 | | $ | 36.65 | | | 1,279 | | $ | 35.81 | |
Outstanding - Dec. 31, 2005 | | | 2,221,245 | | | 6.8 | | $ | 27.79 | | | 1,275,689 | | $ | 23.46 | |
Summarized below are outstanding options that are fully exercisable.
Exercisable at: | | Number of Options | | Weighted Average Exercise Price | |
December 31, 2003 | | | 2,154,877 | | $ | 20.47 | |
December 31, 2004 | | | 1,658,260 | | $ | 22.04 | |
December 31, 2005 | | | 1,275,689 | | $ | 23.46 | |
Our stock-based employee compensation plans are accounted for under the recognition and measurement principles of APB 25 and related interpretations. For our stock option plans, we generally do not reflect stock-based employee compensation cost in net income, as options for those plans had an awardexercise price equal to receive an equal numberthe market value of shares of companythe underlying common stock or an equivalent valueon the date of cash subject to the achievement of certain pre-established performance criteria.
In February 2002,grant. For our SARs, we granted to a select group of key executives a total of 1.5 million in performance units with a performance measurement period that ended December 31, 2004. The amount actually earned would bereflect stock-based employee compensation cost based on the highest average closing pricefair value of our common stock over any 10 consecutive trading days during the performance measurement period and could range from a minimum of 10% to 100% of the granted units. The performance units were subject to certain transfer restrictions and forfeiture upon termination of employement. In addition, during a portion of the performance measurement period, performance units were eligible for dividend credits based on vested performance units. Of the 1.5 million units that were granted only 1 million units were eligible for vesting at December 31, 2004. Upon vesting, the performance units were payable in shares of our common stock, provided, however, at the election of the participant, up to 50% was payable in cash.
At December 31, 2004, based on the highest average closing price over any 10 consecutive trading days during the performance measurement period, only 18.31% of the units vested, representing an aggregate of 198,000 units, including accrued dividends. These units were valued at our closing stock price on December 31, 2004 of $33.24 per unit representingbalance sheet date since these awards constitute a value of $6.2 million. The total value of the awards in the amount of $6.6 million was paid out as follows
· | $2.6 million paid in cash |
· | $2.8 million withheld to cover applicable taxes |
· | 35,342 shares of common stocks with an approximate value of $1.2 million |
variable plan under APB 25.
In November 1999,accordance with the fair value method of determining compensation expense, we grantedused the Black-Scholes pricing model and the estimates listed below for the years ended December 31, 2005, 2004 and 2003.
| | 2005 | | 2004 | | 2003 | |
Expected life (years) | | | 7 | | | 7 | | | 7 | |
Interest rate | | | 4.0 | % | | 3.7 | % | | 3.8 | % |
Volatility | | | 17.3 | % | | 16.9 | % | | 19.2 | % |
Dividend yield | | | 3.7 | % | | 3.9 | % | | 4.2 | % |
Fair value of options granted | | $ | 4.70 | | $ | 3.72 | | $ | 3.75 | |
The compensation costs that have been charged against income for performance units, that vestedrestricted stock and other stock-based awards were $5 million in September 2002. Based on performance achievement and the accrual of dividend credit, a total of 10,254 shares of common stock were issued to the participants. We did not grant performance units2005, $7 million in 2004 orand $8 million in 2003.
Stock Appreciation Rights
We granthave granted SARs, which are payable in cash, at fair market value on the date of grant. SARs generally become fully exercisable not earlier than 12 months after the date of grant and generally expire six years after that date. Participants realize value from SAR grants only to the extent that the fair market value of our common stock on the date of exercise of the SAR exceeds the fair market value of the common stock on the date of the grant.
We recognize the intrinsic value of the SARs as compensation expense over the vesting period. Compensation expense for 2005, 2004 and 2003 was immaterial. The following table summarizes activity related to grants of SARs:SARs.
| | Number of SARs | | Weighted Average Exercise Price | | |
Number of SARs | |
Weighted Average Exercise Price | |
Outstanding as of December 31, 2002 | | | 141,253 | | $ | 23.50 | | |
Outstanding as of Dec.31, 2002 | | | | 141,253 | | $ | 23.50 | |
Issued | | | 45,790 | | | 24.30 | | | | 45,790 | | | 24.30 | |
Exercised | | | (17,718 | ) | | 23.50 | | | | (17,718 | ) | | 23.50 | |
Forfeited | | | (9,368 | ) | | 23.99 | | | | (9,368 | ) | | 23.99 | |
Outstanding as of December 31, 2003 | | | 159,957 | | | 23.70 | | |
Outstanding as of Dec.31, 2003 | | | | 159,957 | | | 23.70 | |
Issued | | | - | | | - | | | | - | | | - | |
Exercised | | | (60,262 | ) | | 23.70 | | | | (60,262 | ) | | 23.70 | |
Forfeited | | | (72,832 | ) | | 23.50 | | | | (72,832 | ) | | 23.50 | |
Outstanding as of December 31, 2004 | | | 26,863 | | | 24.24 | | |
Outstanding as of Dec.31, 2004 | | | | 26,863 | | | 24.24 | |
Issued | | | | - | | | - | |
Exercised | | | | - | | | - | |
Forfeited | | | | - | | | - | |
Outstanding as of Dec. 31, 2005 | | | | 26,863 | | | 24.24 | |
Directors PlanPerformance Units
In general, a performance unit is an award of the right to receive (i) an equal number of shares of company common stock or (ii) cash, subject to the achievement of certain pre-established performance criteria. Performance units are subject to certain transfer restrictions and forfeiture upon termination of employment. In January 2005, we granted restricted stock units and performance cash units to a select group of officers as described below.
Restricted Stock UnitsIn general, a restricted stock unit is an award that represents the opportunity to receive a specified number of shares of our common stock, subject to the achievement of certain pre-established performance criteria.
In January 2005, we granted to a select group of officers a total of 86,800 restricted stock units (the 2005 restricted stock units) under the LTIP, of which 77,300 of these units were outstanding as of December 31, 2005. The 2005 restricted stock units had a 12-month performance measurement period related to management’s success in integrating its acquisitions and generating improvement in earnings from these acquired businesses. The performance measure was achieved during 2005. On January 3, 2006, the 2005 restricted stock units were converted to an equal number of shares of our common stock and are now subject to time-based vesting.
Performance Cash UnitsIn general, a performance cash unit is an award that represents the opportunity to receive a cash award, subject to the achievement of certain pre-established performance criteria.
In January 2005, we granted performance cash units to a select group of officers under the LTIP. The performance cash units represent a maximum aggregate payout of $3 million. The performance cash units have a performance measurement period that ranges from 12 to 36 months and a performance measure that relates to our internal measure of total shareholder return. As of December 31, 2005, based on our anticipated performance, we had recorded a liability of $2 million for these performance cash units. In addition, in 2005, we granted performance cash units to select executives that were intended to recognize the executive’s promotion into key senior leadership roles and retain the executives.
At the end of the performance measurement period for the 12-month performance cash units (December 31, 2005), the performance measure was achieved and in January 2006 an aggregate of $743,680 was paid.
2002 Performance Unit AwardsIn February 2002, we granted to a select group of officers a total of 1.5 million performance units with a performance measurement period that ended December 31, 2004. The amount actually earned was based on the highest average closing price of our common stock over any 10 consecutive trading days during the performance measurement period and could range from a minimum of 10% to 100% of the units granted. During a portion of the performance measurement period, these units were eligible for dividend credits based on vested performance units. Of the 1.5 million units that were granted, 1 million units were eligible for vesting at December 31, 2004. Upon vesting, at the election of the participant the performance units were payable in shares of our common stock, or up to 50% in cash.
These units were paid out as follows:
· | $2.6 million paid in cash |
· | $2.8 million withheld to cover applicable taxes |
· | 35,342 shares of common stock with an approximate value of $1.2 million |
Stock and Restricted Stock Awards
In general, we refer to an award of our common stock that is subject to time-based vesting or achievement of performance measures as “restricted stock.” Restricted stock awards are subject to certain transfer restrictions and forfeiture upon termination of employment.
Stock AwardsUnder the Directors Plan, each nonemployee director receives an annual retainer that has an aggregate value of $60,000. At the election of each director, the annual retainer is paid in cash (with a $30,000 limit) and/or shares of our common stock or is deferred and invested in common stock equivalents under the 1998 Common Stock Equivalent Plan for Non-Employee Directors. Upon initial election to our Board of Directors, each nonemployee director receives 1,000 shares of common stock onas of the first day of his or her service. Shares issued under the Directors Plan are 100% vested and nonforfeitable as of the date of grant.
Restricted Stock AwardsIn January 2005, we granted to a select group of executive officers a total of 41,200 shares of restricted stock under the LTIP, of which 34,200 shares were outstanding as of December 31, 2005. The restricted stock awards had a 12-month performance measurement period with a performance measure related to management’s success in integrating its acquisitions and generating improvement in earnings from these acquired businesses. At the end of the performance measurement period (December 31, 2005), the performance measure was achieved, one-third of the shares vested, and the balance is now subject to time-based vesting. In addition, in 2005, we granted shares of restricted stock to select executives that were intended to recognize the executive’s promotion into key senior leadership roles and retain the executives.
Restricted stock awards generally are subject to some vesting restrictions. We awarded shares of restricted stock to our key employees and shares of company stock to our nonemployee directors, net of forfeitures, to key employees and nonemployee directors in the following amounts:
| | 2004 | | 2003 | | 2002 | | | 2005 (1) | | 2004 | | 2003 | |
Employees | | | 51,300 | | | 244,128 | | | 30,000 | | | | 133,542 | | | 51,300 | | | 244,128 | |
Nonemployee directors | | | 8,727 | | | 12,152 | | | 1,410 | | | | 7,621 | | | 8,727 | | | 12,152 | |
Total | | | 60,027 | | | 256,280 | | | 31,410 | | | | 141,163 | | | 60,027 | | | 256,280 | |
| | | | | | | | | | | | | | | | | | | | |
Weighted average fair value at year-end | | $ | 32.45 | | $ | 27.15 | | $ | 23.19 | | |
Weighted average fair value at year end | | | $ | 34.44 | | $ | 32.45 | | $ | 27.15 | |
In addition, 104,000 of the 256,280 shares awarded to selected employees in 2003 vested in 2004. The remaining nonvested shares were contingent upon our achievement of selected cash flow performance measures over the one-year performance measurement period. Recipients were entitled to vote and receive dividends on stock awards. The shares were subject to certain transfer restrictions and are forfeited upon termination of employment, absent a change of control.(1) | Includes 35,342 shares that were converted as a result of the 2002 performance units that vested. |
Employee Stock Purchase Plan
We have established the Employee Stock Purchase Plan (ESPP), a nonqualified employee stock purchase plan for eligible employees. Under the ESPP, employees may purchase shares of our common stock duringin quarterly intervals at 85% of fair market value. Employee contributions under the ESPP may not exceed $25,000 per employee during any calendar year. The ESPP currently allows for the purchase of 600,000 shares. As of December 31, 2004,2005, our employees havehad purchased 73,254a total of 40,927 shares leaving 526,746485,819 shares available for purchase. The ESPP was adopted by our Board in 2001, with an initial term of four years that expiredexpires January 31, 2005. Our Board of Directors approved an amendment to the ESPP, subject to shareholder approval at the next annual meeting of shareholders, to extend the term of the ESPP for a ten-year period effective January 31, 2005. More information about the ESPP is presented below:2015.
| | 2004 | | 2003 | | 2002 | | | 2005 | | 2004 | | 2003 | |
Shares purchased on the open market | | | 35,789 | | | 24,871 | | | 12,594 | | | | 40,927 | | | 35,789 | | | 24,871 | |
Average per share purchase price | | $ | 25.20 | | $ | 22.08 | | $ | 23.22 | | | $ | 30.52 | | $ | 25.20 | | $ | 22.08 | |
Purchase price discount paid | | $ | 159,144 | | $ | 97,400 | | $ | 44,024 | | |
Purchase price discount | | | $ | 220,847 | | $ | 159,144 | | $ | 97,400 | |
Financing
| | | | | | Outstanding as of: | |
Dollars in millions | | Year(s) Due | | Int. rate as of Dec. 31, 2004 | | Dec. 31, 2004 | | Dec. 31, 2003 | |
Short-term debt | | | | | | | | | |
Commercial paper(1) | | | 2005 | | | 2.5 | % | $ | 314 | | $ | 303 | |
Current portion of long-term debt | | | - | | | - | | | - | | | 77 | |
Sequent line of credit(2) | | | 2005 | | | 2.5 | | | 18 | | | 3 | |
Current portion of capital leases | | | 2005 | | | 4.9 | | | 2 | | | - | |
Total short-term debt(3) | | | | | | 2.5 | % | $ | 334 | | $ | 383 | |
Long-term debt - net of current portion | | | | | | | | | | | | | |
Medium-Term notes | | | | | | | | | | | | | |
Series A | | | 2021 | | | 9.1 | % | $ | 30 | | $ | 30 | |
Series B | | | 2012-2022 | | | 8.3-8.7 | | | 61 | | | 61 | |
Series C | | | 2014-2027 | | | 6.6-7.3 | | | 117 | | | 122 | |
Senior Notes | | | 2011-2013 | | | 4.5-7.1 | | | 975 | | | 525 | |
Gas facility revenue bonds, net of unamortized issuance costs | | | 2022-2033 | | | 1.9-6.4 | | | 199 | | | - | |
Notes payable to Trusts | | | 2037-2041 | | | 8.0-8.2 | | | 232 | | | - | |
Trust Preferred Securities | | | 2037-2041 | | | - | | | - | | | 222 | |
Capital leases | | | 2013 | | | 4.9 | | | 8 | | | - | |
AGL Capital interest rate swaps | | | 2011-2041 | | | 3.6-5.2 | | | 1 | | | (4 | ) |
Total long-term debt(3) | | | | | | 6.0 | % | $ | 1,623 | | $ | 956 | |
| | | | | | | | | | | | | |
Total short-term and long-term debt (3) | | | | | | 5.4 | % | $ | 1,957 | | $ | 1,339 | |
(1) | The daily weighted average rate was 1.6% for 2004 and 1.3% for 2003. |
(2) | The daily weighted average rate was 2.0% for 2004 and 1.6% for 2003. |
(3) | The weighted average interest rate excludes capital leases but includes interest rate swaps, if applicable |
Short-term Debt
Our short-term debt at December 31, 2004 and 2003 was composed of borrowings under our commercial paper program which consisted of short-term, unsecured promissory notes with maturities ranging from 3 to 56 days, Atlanta Gas Light’s Medium-Term notes with maturities within one year, current portions of our capital lease obligations, Sequent’s line of credit and SouthStar’s line of credit.
Commercial paperIn September 2004, we amended our credit facility that supports our commercial paper program (Credit Facility). Under the terms of the amendment, the Credit Facility has been extended from May 26, 2007 to September 30, 2009. The aggregate principal amount available under the Credit Facility has been increased from $500 million to $750 million and the cost of borrowing has been decreased relative to the prior credit agreements. In addition, our option to increase the aggregate cumulative principal amount available for borrowing on not more than one occasion during each calendar year during the term of the Credit Facility has been increased from $200 million to $250 million.
Sequent line of creditIn June 2004, Sequent’s $25 million unsecured line of credit was extended to July 2005. This unsecured line of credit is used solely for the posting of exchange deposits and is unconditionally guaranteed by us. This line of credit bears interest at the federal funds effective rate plus 0.5%.
SouthStar line of creditIn April 2004, SouthStar amended its $75 million revolving line of credit, which is used to meet seasonal working capital needs. SouthStar’s line of credit is scheduled to expire in April 2007 and is not guaranteed by us. At December 31, 2004, there were no amounts outstanding under this facility.
Long-term Debt
Our long-term debt matures more than one year from the date of issuance and consists of Medium-Term notes Series A, Series B and Series C, which we issued under an indenture dated December 1, 1989, Senior Notes, Gas Facility Revenue Bonds, Notes Payable to Trusts and capital leases. The notes are unsecured and rank on parity with all of our other unsecured indebtedness. Our annual maturities of long-term debt are as follows:
· | no maturities in 2005-2010 |
· | $1,623 million in 2011 and beyond |
Senior NotesIn February 2001, we issued $300 million of Senior Notes with a maturity date of January 14, 2011. These Senior Notes have an interest rate of 7.125% payable on January 14 and July 14, beginning July 14, 2001. The proceeds from the issuance were used to refinance a portion of the existing short-term debt under the commercial paper program.
In March 2003, we entered into interest rate swaps of $100 million to effectively convert a portion of the fixed-rate interest obligation on the $300 million in Senior Notes Due 2011 to a variable-rate obligation. We pay floating interest each January 14 and July 14 at six-month LIBOR plus 3.4%.The effective variable interest rate at December 31, 2004 was 5.2%.These interest rate swaps expire January 14, 2011, unless terminated earlier. For more information on our interest rate swaps, see Note 4.
In July 2003, we issued $225 million in Senior Notes with a maturity date of April 15, 2013. The Senior Notes have an interest rate of 4.45% payable on April 15 and October 15 of each year, beginning October 15, 2003 with interest accruing from July 2, 2003. We used the net proceeds from the Senior Notes to repay approximately $204 million of Medium-Term notes as well as approximately $20 million of short-term debt.
In September 2004, we issued $250 million in Senior Notes with a maturity of October 1, 2034. The Senior Notes have an interest rate of 6.00% payable on April 1 and October 1 of each year, beginning April 1, 2005 with interest accruing from September 27, 2004.
In December 2004, we issued $200 million in Senior Notes with a maturity of January 15, 2015. The Senior Notes have an interest rate of 4.95% payable on January 15 and July 15 of each year, beginning July 15, 2005 with interest accruing from December 20, 2004.We used the net proceeds from both of the senior notes issuances in 2004 to repay commercial paper borrowings and for general corporate purposes.
The trustee with respect to all of the above-referenced senior notes is the Bank of New York Trust Company, N.A., pursuant to an indenture dated February 20, 2001. We fully and unconditionally guarantee all of our senior notes.
Gas Facility Revenue BondsNUI Utilities, Inc., a wholly owned subsidiary of NUI, had outstanding at closing $200 million of indebtedness pursuant to Gas Facility Revenue Bonds. We do not guarantee or provide any other form of security for the repayment of this indebtedness. NUI Utilities is party to a series of loan agreements with the New Jersey Economic Development Authority (NJEDA) pursuant to which the NJEDA has issued four series of gas facilities revenue bonds:
· | $46 million of bonds at 6.35 %, due October 1, 2022 |
· | $20 million of bonds at 6.4%, due October 1, 2024 |
· | $39 million of bonds at variable rates, due June 1, 2026 (Variable Bonds) |
· | $55 million of bonds at 5.7 %, due June 1, 2032 |
· | $40 million of bonds at 5.25%, due November 1, 2033 |
The Variable Bonds contain a provision whereby the holder can "put" the bonds back to the issuer. In 1996, NUI Utilities executed a long-term Standby Bond Purchase Agreement (SBPA) with a syndicate of banks, which was amended and restated on June 12, 2001. Under the terms of the SBPA, as further amended, The Bank of New York Trust Company, N.A. (Bank of New York) is obligated under certain circumstances to purchase Variable Bonds that are tendered by the holders thereof and not remarketed by the remarketing agent. Such obligation of the Bank of New York would remain in effect until the expiration of the SBPA, unless it is extended or earlier terminated.
The terms of the SBPA restrict the payment of dividends by NUI Utilities to an amount based, in part, on the earned surplus of NUI Utilities. On May 19, 2004, NUI Utilities and The Bank of New York amended the SBPA to eliminate the effect of NUI Utilities’ settlement with the New Jersey Board of Public Utilities (NJBPU) and the estimated refunds to customers in Florida on the earned surplus of NUI Utilities. In addition the amendment extended the expiration date of the SBPA to June 29, 2005.
If the SBPA is not further extended beyond June 29, 2005, in accordance with the terms of the Variable Bonds, all of the Variable Bonds would be subject to mandatory tender at a purchase price of 100 percent of the principal amount, plus accrued interest, to the date of tender. In such case, any Variable Bonds that are not remarketable by the remarketing agent will be purchased by the Bank of New York.
Beginning six months after the expiration or termination of the SBPA, any Variable Bonds still held by the bank must be redeemed or purchased by NUI Utilities in 10 equal, semi-annual installments. In addition, while the SBPA is in effect, any tendered Variable Bonds that are purchased by the bank and not remarketed within one year must be redeemed or purchased by NUI Utilities at such time, and every six months thereafter, in 10 equal, semi-annual installments.
As of December 31, 2004, the aggregate principal and accrued interest on the outstanding Variable Bonds totaled approximately $39 million. Principal and any unpaid interest on the outstanding Variable Bonds are due on June 1, 2026, unless the put option is exercised before that time.
Notes Payable to TrustsIn June 1997, we established AGL Capital Trust I (Trust I), a Delaware business trust, of which AGL Resources owns all the common voting securities. Trust I issued and sold $75 million of 8.17% capital securities (liquidation amount $1,000 per capital security) to certain initial investors. Trust I used the proceeds to purchase 8.17% Junior Subordinated Deferrable Interest Debentures issued by us. Trust I capital securities are subject to mandatory redemption at the time of the repayment of the junior subordinated debentures on June 1, 2037, or the optional prepayment by us after May 31, 2007.
In March 2001, we established AGL Capital Trust II (Trust II), a Delaware business trust, of which AGL Capital owns all the common voting securities. In May 2001, Trust II issued and sold $150 million of 8.00% capital securities (liquidation amount $25 per capital security). Trust II used the proceeds to purchase 8.00% Junior Subordinated Deferrable Interest Debentures issued by us. The proceeds from the issuance were used to refinance a portion of our existing short-term debt under the commercial paper program. Trust II capital securities are subject to mandatory redemption at the time of the repayment of the junior subordinated debentures on May 15, 2041, or the optional prepayment by AGL Capital after May 21, 2006. Additionally we entered into interest rate swaps to effectively convert a portion of the fixed-rate interest obligation on our Notes Payable to Trusts to a variable-rate obligation. The effective variable interest rate at December 31, 2004 was 3.6%. For more information on our interest rate swaps, see Note 4.
The trustee is the Bank of New York with respect to the 8.17% capital securities pursuant to an indenture dated June 11, 1997, and with respect to the 8.00% capital securities pursuant to an indenture dated May 21, 2001. We fully and unconditionally guarantee all our Trusts’ obligations for the capital securities.
Other Preferred SecuritiesAs of December 31, 2003, we had 10.0 million shares of authorized, unissued Class A Junior Participating Preferred Stock, no par value, and 10.0 million shares of authorized, unissued preferred stock, no par value.
Capital leasesOur capital leases consist primarily of a sale/leaseback transaction completed in 2002 by Florida Gas related to its gas meters and other equipment and will be repaid over 11 years. Pursuant to the terms of the lease agreement, Florida Gas is required to insure the leased equipment during the lease term. In addition, at the expiration of the lease term, Florida Gas has the option to purchase the leased meters from the lessor at their fair market value.
Default Events
Our Credit Facility financial covenants and the Public Utility Holding Company Act of 1935, as amended (PUHCA), require us to maintain a ratio of total debt to total capitalization of no greater than 70%. Our debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. Our most important default events include
· | a maximum leverage ratio |
· | insolvency events and nonpayment of scheduled principal or interest payments |
· | acceleration of other financial obligations |
· | change of control provisions |
We do not have any trigger events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that requires us to issue equity based on credit ratings or other trigger events. We are currently in compliance with all existing debt provisions and covenants.
> Note 9
Common Shareholders’ Equity
Shareholder Rights Plan
On March 6, 1996, our Board of Directors adopted a Shareholder Rights Plan. The plan contains provisions to protect our shareholders in the event of unsolicited offers to acquire us or other takeover bids and practices that could impair the ability of the Board of Directors to fully represent shareholders’ interests fully.interests. As required by the Shareholder Rights Plan, the Board of Directors declared a dividend of one preferred share purchase right (a Right) for each outstanding share of our common stock, with distribution made to shareholders of record on March 22, 1996.
The Rights, which will expire March 6, 2006, are represented by and traded with our common stock. The Rights are not currently exercisable and do not become exercisable unless a triggering event occurs. One of the triggering events is the acquisition of 10% or more of our common stock by a person or group of affiliated or associated persons.persons (subject to certain exceptions). Unless previously redeemed, upon the occurrence of one of the specified triggering events, each Right will entitle its holder to purchase one one-hundredth of a share of Class A Junior Participating Preferred Stock at a purchase price of $60. Each preferred share will have 100 votes, voting together with the common stock. Because of the nature of the preferred shares’ dividend, liquidation and voting rights, one one-hundredth of a share of preferred stock is intended to have the value, rights and preferences of one share of common stock. As of December 31, 2004, 1.02005, 1 million shares of Class A Junior Participating Preferred Stock were reserved for issuance under that plan.
Equity Offering
On November 18, 2004, we completed our public offering of 11.04 million shares of common stock. We priced the offering at $31.01 per share and generated net proceeds of approximately $332 million, which we used to purchase the outstanding capital stock of NUI and to repay short-term debt incurred to fund the purchase of Jefferson Island Storage & Hub LLC. In February 2003, we completed our public offering of 6.4 million shares of common stock. The offering generated net proceeds of approximately $137 million, which we used to repay outstanding short-term debt and for general corporate purposes.
Dividends
We derive a substantial portion of our consolidated assets, earnings and cash flow from the operation of regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. Our common shareholders may receive dividends when declared byat the discretion of our Board of Directors, whichDirectors. Dividends may be paid in cash, stock or other form of payment.payment, and payment of future dividends will depend on our future earnings, cash flow, financial requirements and other factors, some of which are noted below. In certain cases, our ability to pay dividends to ourcommonour common shareholders is limited by the following:
· | satisfyingour ability to satisfy our obligations under certain financing agreements, including debt-to-capitalization and total shareholders’ equity covenants |
· | satisfyingour ability to satisfy our obligations to any preferred shareholders |
· | restrictions under the PUHCAPublic Utility Holding Company Act of 1935, as amended (PUHCA) on our payment of dividends out of capital or unearned surplus without prior permission from the SECSEC. (the PUCHA is repealed effective February 8, 2006) |
Under
Additionally, under Georgia law, the payment of cash dividends to the holders of our common stock is limited to our legally available assets and subject to the prior payment of dividends on any outstanding shares of preferred stock and junior preferred stock. Our assets are not legally available for paying cash dividends if, after payment of the dividend,
· | we could not pay our debts as they become due in the usual course of business, or |
· | our total assets would be less than our total liabilities plus, subject to some exceptions, any amounts necessary to satisfy (upon dissolution) the preferential rights upon dissolution of shareholders whose preferential rights are superior to those of the shareholders receiving the dividends |
The following table provides information on increases in our quarterly common stock dividends over the last three years.
Date | | % change | | Quarterly dividend | | Indicated annual dividend | |
November 2005 | | | 19 | % | $ | 0.37 | | $ | 1.48 | |
February 2005 | | | 7 | | | 0.31 | | | 1.24 | |
April 2004 | | | 4 | | | 0.29 | | | 1.16 | |
April 2003 | | | 4 | | | 0.28 | | | 1.12 | |
Share Repurchase Program
In February 2006, our Board of Directors authorized a plan to repurchase up to 8 million shares of our outstanding common stock over a five-year period. These purchases are intended to principally offset share issuances under our employee incentive compensation plans, director plans, and dividend reinvestment and stock purchase plans. Stock repurchases under this program may be made in the open market or in private transactions at times and in amounts that we deem appropriate. However, there is no guarantee as to the exact number of additional shares that may be repurchased, and we may terminate or limit the stock repurchase program at any time. We will hold the repurchased shares as treasury shares.
Debt
Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies, including state public service commissions, the SEC and the Federal Energy Regulatory Commission (FERC). On April 1, 2004, we received approval from the SEC, under the PUHCA, for the renewal of our financing authority to issue securities through April 2007. In August 2005, the Energy Policy Act of 2005 (Energy Act) was enacted which repealed the PUHCA, effective February 8, 2006. The Energy Act provided the FERC with granting of previous financing authorizations approvals that were previously required by the SEC under the PUHCA. The following table provides more information on our various securities.
| | | | | | Outstanding as of: | |
Dollars in millions | | Year(s) due | | Int. rate (1) | | Dec. 31, 2005 | | Dec. 31, 2004 | |
Short-term debt | | | | | | | | | |
Commercial paper (2) | | | 2006 | | | 4.5 | % | $ | 485 | | $ | 314 | |
SouthStar line of credit (3) | | | 2006 | | | 7.3 | | | 36 | | | - | |
Sequent line of credit (4) | | | 2006 | | | - | | | - | | | 18 | |
Capital leases | | | 2006 | | | 4.9 | | | 1 | | | 2 | |
Total short-term debt (5) | | | | | | 4.8 | % | $ | 522 | | $ | 334 | |
Long-term debt - net of current portion | | | | | | | | | | | | | |
Medium-term notes | | | 2012-2027 | | | 6.6-9.1 | % | $ | 208 | | $ | 208 | |
Senior notes | | | 2011-2034 | | | 4.5-7.1 | | | 975 | | | 975 | |
Gas facility revenue bonds, net of unamortized issuance costs | | | 2022-2033 | | | 3.2-5.7 | | | 199 | | | 199 | |
Notes payable to Trusts | | | 2037-2041 | | | 8.0-8.2 | | | 232 | | | 232 | |
Capital leases | | | 2013 | | | 4.9 | | | 6 | | | 8 | |
AGL Capital interest rate swaps | | | 2011 | | | 7.2 | | | (5 | ) | | 1 | |
Total long-term debt (5) | | | | | | 6.1 | % | $ | 1,615 | | $ | 1,623 | |
| | | | | | | | | | | | | |
Total debt (5) | | | | | | 5.8 | % | $ | 2,137 | | $ | 1,957 | |
(1) | As of December 31, 2005. |
(2) | The daily weighted average interest rate was 3.6% for 2005 and 1.6% for 2004. |
(3) | The daily weighted average interest rate was 6.8% for 2005. |
(4) | The daily weighted average interest rate was 2.0% for 2004. |
(5) | Weighted average interest rate, including interest rate swaps if applicable and excluding debt issuance and other financing-related costs. |
Short-term Debt
Our short-term debt at December 31, 2005 and 2004 was composed of borrowings under our commercial paper program which consisted of short-term, unsecured promissory notes with maturities ranging from 3 to 56 days; current portions of our capital lease obligations; SouthStar’s line of credit; and Sequent’s line of credit.
Commercial PaperOn August 30, 2005, we amended our Credit Facility that supports our commercial paper program. Under the terms of the amendment, the aggregate principal amount available under the Credit Facility was increased from $750 million to $850 million and we have the option to increase the aggregate principal amount available for borrowing to $1.1 billion on not more than three occasions during each calendar year. The amended Credit Facility expires on August 31, 2010.
SouthStar Line of CreditIn April 2004, the SouthStar line of credit was extended to April 2007. This line is collaterized by various percentages of eligible accounts receivable, unbilled revenue, and inventory of SouthStar. The base rate on the line is the prime rate and / or LIBOR plus a margin based on certain financial measures. We do not guarantee or provide any other form of security for the repayment of any outstanding indebtedness.
Sequent Line of CreditIn June 2005, Sequent’s $25 million unsecured line of credit was extended to July 2006. In September 2005, Sequent entered into an additional $20 million unsecured line of credit scheduled to expire in September 2006. These unsecured lines of credit, which total $45 million and bear interest at the federal funds effective rate plus 0.5%, are used solely for the posting of margin deposits for New York Mercantile Exchange transactions and are unconditionally guaranteed by AGL Resources.
Pivotal Utility Holdings Line of Credit In September 2005, Pivotal Utility entered into a $20 million unsecured line of credit expiring on September 30, 2006. This line of credit supports Elizabethtown Gas’ hedging program and bears interest at the federal funds effective rate plus 0.5%, is used solely for the posting of deposits and is unconditionally guaranteed by us. For more information on Elizabethtown Gas’ hedging program, see Note 4.
We announcedLong-term Debt
Our long-term debt matures more than one year from the following increases indate of issuance and consists of medium-term notes Series A, Series B and Series C, which we issued under an indenture dated December 1, 1989; senior notes; gas facility revenue bonds; notes payable to Trusts; and capital leases. The notes are unsecured and rank on parity with all our cash dividends payable on our common stock:other unsecured indebtedness. Our annual maturities of long-term debt are as follows:
· | In February 2005, we announced a 7% increase$4 million in our common stock dividend. The increase raised the quarterly dividend from $0.29 per share to $0.31 per share, for an indicated annual dividend of $1.24 per share.2007-2010 |
· | In April 2004, we announced a 4% increase$1,611 million in our common stock dividend, raising the quarterly dividend from $0.28 per share to $0.29 per share which indicated an annual dividend2011 and beyond |
Senior NotesThe following table provides more information on our senior notes, which were issued to refinance portions of our existing short-term debt and medium-term notes, to finance acquisitions and for general corporate purposes.
Issue date | | Amount (in millions) | | Interest rate | | Maturity | |
Feb. 2001 | | $ | 300 | | | 7.125 | % | | Jan 2011 | |
July 2003 | | | 225 | | | 4.45 | | | Apr 2013 | |
Sep. 2004 | | | 250 | | | 6.0 | | | Oct 2034 | |
Dec. 2004 | | | 200 | | | 4.95 | | | Jan 2015 | |
In March 2003, we entered into interest rate swaps of $100 million to effectively convert a portion of the fixed-rate interest obligation on the $300 million in Senior Notes Due 2011 to a variable-rate obligation. We pay floating interest each January 14 and July 14 at six-month LIBOR plus 3.4%. The effective variable interest rate at December 31, 2005 was 7.2%. These interest rate swaps expire January 14, 2011, unless terminated earlier. For more information on our interest rate swaps, see Note 4.
The trustee with respect to all of the above-referenced senior notes is the Bank of New York Trust Company, N.A. (Bank of New York), pursuant to an indenture dated February 20, 2001. We fully and unconditionally guarantee all our senior notes.
Gas Facility Revenue BondsPivotal Utility has $200 million of indebtedness pursuant to gas facility revenue bonds. We do not guarantee or provide any other form of security for the repayment of this indebtedness. Pivotal Utility is party to a series of loan agreements with the New Jersey Economic Development Authority (NJEDA) pursuant to which the NJEDA has issued four series of gas facility revenue bonds:
· | $47 million of $1.16 per share.bonds at adjusting rates due October 1, 2022 |
· | In April 2003, we announced a 4% increase in our common stock dividend from $0.27 per share to $0.28 per share, which indicated an annual dividend$20 million of $1.12bonds at adjusting rates due October 1, 2024 |
· | $39 million of bonds at variable rates due June 1, 2026 (variable bonds) |
· | $55 million of bonds at 5.7% due June 1, 2032 |
· | $40 million of bonds at 5.25% due November 1, 2033 |
In April 2005, we refinanced $20 million of our Gas Facility Revenue Bonds Due October 1, 2024. The original bonds had a fixed interest rate of 6.4% per year and were refunded with $20 million of adjustable-rate gas facility revenue bonds. The maturity date of these bonds remains October 1, 2024. The new bonds were issued at an initial annual interest rate of 2.8% and initially have a 35-day auction period where the interest rate will adjust every 35 days. The interest rate at December 31, 2005 was 3.3%.
In May 2005, we refinanced an additional $47 million in Gas Facility Revenue Bonds Due October 1, 2022 and bearing interest at an annual fixed rate of 6.35%. The new bonds were issued at an initial annual interest rate of 2.9% and initially have a 35-day auction period where the interest rate will adjust every 35 days. The maturity date remains October 1, 2022. The interest rate at December 31, 2005 was 3.2%.
The variable bonds contain a provision whereby the holder can "put" the bonds back to the issuer. In 1996, Pivotal Utility executed a long-term Standby Bond Purchase Agreement (SBPA) with a syndicate of banks, which was amended and restated on June 1, 2005. Under the terms of the SBPA, as further amended, the participating banks are obligated under certain circumstances to purchase variable bonds that are tendered by the holders thereof and not remarketed by the remarketing agent. Such obligation of the participating banks would remain in effect until the June 1, 2010 expiration of the SBPA, unless it is extended or earlier terminated.
Notes Payable to TrustsIn June 1997, we established AGL Capital Trust I (Trust I), a Delaware business trust, of which AGL Resources owns all the common voting securities. Trust I issued and sold $75 million of 8.17% capital securities (liquidation amount $1,000 per capital security) to certain initial investors. Trust I used the proceeds to purchase 8.17% junior subordinated deferrable interest debentures issued by us. Trust I capital securities are subject to mandatory redemption at the time of the repayment of the junior subordinated debentures on June 1, 2037, or the optional prepayment by us after May 31, 2007.
In March 2001, we established AGL Capital Trust II (Trust II), a Delaware business trust, of which AGL Capital owns all the common voting securities. In May 2001, Trust II issued and sold $150 million of 8.00% capital securities (liquidation amount $25 per capital security). Trust II used the proceeds to purchase 8.00% junior subordinated deferrable interest debentures issued by us. The proceeds from the issuance were used to refinance a portion of our existing short-term debt under the commercial paper program. Trust II capital securities are subject to mandatory redemption at the time of the repayment of the junior subordinated debentures on May 15, 2041, or the optional prepayment by AGL Capital after May 21, 2006. Additionally we entered into interest rate swaps to effectively convert a portion of the fixed-rate interest obligation on our notes payable to Trusts to a variable-rate obligation. At the beginning of 2005, we had $75 million of outstanding interest rate swap agreements associated with our Note Payable at AGL Capital Trust II. On September 7, 2005, we terminated these interest rate swap agreements. We received a payment of $1 million related to this termination, which included accrued interest and the fair value of these interest rate swap agreements at the termination date.
The trustee is the Bank of New York with respect to the 8.17% capital securities pursuant to an indenture dated June 11, 1997, and with respect to the 8.00% capital securities pursuant to an indenture dated May 21, 2001. We fully and unconditionally guarantee all our Trust I and Trust II obligations for the capital securities.
Other Preferred SecuritiesAs of December 31, 2005, we had 10 million shares of authorized, unissued Class A junior participating preferred stock, no par value, and 10 million shares of authorized, unissued preferred stock, no par value.
Capital Leases Our capital leases consist primarily of a sale/leaseback transaction completed in 2002 by Florida City Gas related to its gas meters and other equipment and will be repaid over 11 years. Pursuant to the terms of the lease agreement, Florida City Gas is required to insure the leased equipment during the lease term. In addition, at the expiration of the lease term, Florida City Gas has the option to purchase the leased meters from the lessor at their fair market value.
Default Events
Our Credit Facility financial covenants and the PUHCA require us to maintain a ratio of total debt to total capitalization of no greater than 70%. As of December 31, 2005 this ratio was 59%. Our debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. Our most important default events include
· | a maximum leverage ratio |
· | insolvency events and nonpayment of scheduled principal or interest payments |
· | acceleration of other financial obligations |
· | change of control provisions |
We do not have any trigger events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that requires us to issue equity based on credit ratings or other trigger events. We are currently in compliance with all existing debt provisions and covenants.
Commitments and Contingencies
Contractual Obligations and Commitments
We have incurred various contractual obligations and financial commitments in the normal course of our operationsoperating and financing activities. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.Weactivities. We calculate any expected pension contributions using an actuarial method called the projected unit credit cost method. Under this method, and pursuant to these calculations, we expectwere not required to make a $1 millionany pension contribution in 2005, but we voluntarily made a $5 million contribution in August 2005. The following table illustrates our expected future contractual cash obligations as of December 31, 2004:2005.
| | | | Payments due before December 31, | |
| | | | | | 2007 | | 2009 | | 2011 | |
| | | | | | & | | & | | & | |
In millions | | Total | | 2006 | | 2008 | | 2010 | | thereafter | |
Interest charges (1) | | $ | 1,870 | | $ | 103 | | $ | 201 | | $ | 200 | | $ | 1,366 | |
Pipeline charges, storage capacity and gas supply (2) (3) | | | 1,766 | | | 285 | | | 515 | | | 411 | | | 555 | |
Long-term debt (4) | | | 1,615 | | | - | | | 2 | | | 2 | | | 1,611 | |
Short-term debt | | | 522 | | | 522 | | | - | | | - | | | - | |
PRP costs (5) | | | 265 | | | 30 | | | 72 | | | 95 | | | 68 | |
Operating leases (6) | | | 160 | | | 27 | | | 44 | | | 33 | | | 56 | |
Commodity and transportation charges | | | 129 | | | 30 | | | 19 | | | 14 | | | 66 | |
Environmental remediation costs (5) | | �� | 97 | | | 13 | | | 27 | | | 53 | | | 4 | |
Total | | $ | 6,424 | | $ | 1,010 | | $ | 880 | | $ | 808 | | $ | 3,726 | |
(1) Floating rate debt is based on the interest rate as of December 31, 2005 and the maturity of the underlying debt instrument. (2) Charges recoverable through a PGA mechanism or alternatively billed to Marketers. Also includes demand charges associated with Sequent. (3) A subsidiary of NUI entered into two 20-year agreements for the firm transportation and storage of natural gas during 2003 with aggregate annual demand charges of approximately $5 million. As a result of our acquisition of NUI and in accordance with SFAS No. 141, “Business Combinations,” the contracts were valued at fair value. The $38 million currently allocated to accrued pipeline demand charges in our consolidated balance sheets represents our estimate of the fair value of the acquired contracts. The liability will be amortized over the remaining life of the contracts. (4) Includes $232 million of notes payable to Trusts redeemable in 2006 and 2007. (5) Charges recoverable through rate rider mechanisms. (6) We have certain operating leases with provisions for step rent or escalation payments, or certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms in accordance with SFAS No. 13, “Accounting for Leases.” However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein. |
| | | | Payments Due Before December 31, | |
| | | | | | 2006 | | 2008 | | 2010 | |
| | | | | | & | | & | | & | |
In millions | | Total | | 2005 | | 2007 | | 2009 | | Thereafter | |
Long-term debt(1) (2) | | $ | 1,623 | | $ | - | | $ | 2 | | $ | 2 | | $ | 1,619 | |
Pipeline charges, storage capacity and gas supply(3) (4) | | | 1,051 | | | 258 | | | 262 | | | 179 | | | 352 | |
Short-term debt (2) | | | 334 | | | 334 | | | - | | | - | | | - | |
PRP costs(5) | | | 327 | | | 85 | | | 162 | | | 80 | | | - | |
Operating leases (6) | | | 170 | | | 27 | | | 39 | | | 29 | | | 75 | |
ERC(5) | | | 90 | | | 27 | | | 10 | | | 12 | | | 41 | |
Commodity and transportation charges | | | 20 | | | 19 | | | 1 | | | - | | | - | |
Total | | $ | 3,615 | | $ | 750 | | $ | 476 | | $ | 302 | | $ | 2,087 | |
(1) | Includes $232 million of Notes Payable to Trusts redeemable in 2006 and 2007. |
(2) | Does not include the interest expense associated with the long-term and short-term debt. |
(3) | Charges recoverable through a PGA mechanism or alternatively billed to Marketers. Also includes demand charges associated with Sequent. |
(4) | A subsidiary of NUI entered into two 20-year agreements for the firm transportation and storage of natural gas during 2003 with the annual demand charges aggregate of approximately $5 million. As a result of our acquisition of NUI and in accordance with SFAS 141, the contracts were valued at fair value. The $38 million currently allocated to accrued pipeline demand dharges on our consolidated balance sheets represent our estimate of the fair value of the acquired contracts. The liability will be amortized over the remaining life of the contracts. |
(5) | Charges recoverable through rate rider mechanisms. |
(6) | We have certain operating leases with provisions for step rent or escalation payments, or certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms in accordance with SFAS No. 13, “Accounting for Leases.” However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein. |
SouthStar has natural gas purchase commitments related to the supply of minimum natural gas volumes to its customers. These commitments are priced on an index plus premium basis. At December 31, 2004,2005, SouthStar had obligations under these arrangements for 11.28 Bcf for the year ending December 31, 2005.2006. This obligation is not included in the above table. SouthStar also had capacity commitments related to the purchase of transportation rights on interstate pipelines.
We also have incurred various contingent financial commitments in the normal course of business. Contingent financial commitments represent obligations that become payable only if certain pre-definedpredefined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. The following table illustrates our expected contingent financial commitments as of December 31, 2004:2005.
| | | | Commitments Due Before December 31, | |
| | | | | | 2006 | | 2008 | | 2010 | |
| | | | | | & | | & | | & | |
In millions | | Total | | 2005 | | 2007 | | 2009 | | Thereafter | |
Guarantees(1) | | $ | 7 | | $ | 7 | | $ | - | | $ | - | | $ | - | |
Standby letters of credit and performance/ surety bonds | | | 12 | | | 12 | | | - | | | - | | | - | |
Total | | $ | 19 | | $ | 19 | | $ | - | | $ | - | | $ | - | |
(1) We provide a guarantee on behalf of our subsidiary, SouthStar. We guarantee 70% of SouthStar’s obligations to Southern Natural Gas Company (Southern Natural) under certain agreements between the parties up to a maximum of $7 million if SouthStar fails to make payment to Southern Natural. We have certain guarantees that are recorded on our consolidated balance sheet that would not cause any additional impact on our financial statements beyond what was already recorded. |
| | | | Commitments due before Dec. 31, 2007 & | |
| | | |
In millions | | Total | | 2006 | | thereafter | |
Standby letters of credit, performance / surety bonds | | $ | 21 | | $ | 21 | | $ | - | |
Rental expense and sublease incomeExpense
The following table illustrates our totalWe incurred $26 million, $22 million, and $22 million in rental lease expensesexpense in 2005, 2004, and sublease credits incurred for property and equipment:
In millions | | 2004 | | 2003 | | 2002 | |
Rental expense | | $ | 22 | | $ | 22 | | $ | 20 | |
Sublease income | | | - | | | - | | | (2 | ) |
2003, respectively.
Litigation
We are involved in litigation arising in the normal course of business. We believe the ultimate resolution of such litigation will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. Changes to the status of previously disclosed litigation are as follows:
NUI shareholder complaintIn September 2004, a shareholder class action complaint (Complaint) was filed in a civil action captionedGreen Meadows Partners, LLP on behalf of itself and all others similarly situated v. Robert P. Kenney, Bernard S. Lee, Craig G. Mathews, Dr. Vera King Farris, James J. Forese, J. Russell Hawkins, R. Van Whisnand, John Kean, NUI and the Company, pending in the Superior Court of the State of New Jersey, County of Somerset, Law Division. The Complaint, brought on behalf of a potential class of the stockholders of NUI, names as defendants all of the directors of NUI (Individual Defendants), NUI and the Company.
The Complaint alleges that purported financial incentives in the form of change of control payments and indemnification rights created a conflict of interest on the part of certain of the Individual Defendants in evaluating a possible sale of NUI. The Complaint further alleges that the Individual Defendants, aided and abetted by the Company, breached fiduciary duties owed to the plaintiff and the potential class. The Complaint demands judgment (i) determining that the action is properly maintainable as a class action, (ii) declaring that the Individual Defendants breached fiduciary duties owed to the plaintiff and the potential class, aided and abetted by the Company, (iii) enjoining the sale of NUI, or if consummated, rescinding the sale, (iv) eliminating the $7.5 million break-up fee with the Company, (v) awarding the plaintiff and the potential class compensatory and/or rescissory damages, (vi) awarding interest, attorney’s fees, expert fees and other costs, and (vii) granting such other relief as the Court may find just and proper.
On October 12, 2004, we reached an agreement in principle with Green Meadows Partners, LLP to settle this litigation. The settlement called for NUI to provide certain additional information and disclosures to its shareholders, as reflected in the “Additional Disclosure” section of NUI’s proxy statement supplement, filed on October 12, 2004 with the SEC. In addition, as part of the settlement, NUI and the Company consented to a settlement class that consists of persons holding shares of NUI common stock at any time from July 15, 2004 until November 30, 2004, and we agreed to pay plaintiff’s attorney’s fees and costs in the amount of $285,000. No part of these attorney’s fees or costs will be paid out of funds that would otherwise have been paid to NUI’s shareholders.
On December 22, 2004, the trial court entered an order conditionally certifying a class for settlement purposes and designating the Plaintiff as a Settlement Class representative. The trial court’s order also established deadlines for Defendants to provide notice to the Settlement Class, for Settlement Class members to object to the settlement and for a final Settlement Hearing.
Fair Value of Financial Instruments
The following table shows the carrying amounts and fair values of financial instrumentsour long-term debt including any current portions included in our consolidated balance sheets:sheets.
In millions | | Carrying Amount | | Estimated Fair Value | |
As of December 31, 2004 | | | | | | | |
Long-term debt including current portion | | $ | 1,623 | | $ | 1,816 | |
As of December 31, 2003 | | | | | | | |
Long-term debt including current portion | | | 1,033 | | | 1,166 | |
In millions | | Carrying Amount | | Estimated Fair Value | |
As of December 31, 2005 | | $ | 1,615 | | $ | 1,784 | |
As of December 31, 2004 | | | 1,623 | | | 1,816 | |
The estimated fair values are determined based on interest rates that are currently available for issuance of debt with similar terms and remaining maturities. For the Notesnotes payable to Trusts, we used quoted market prices and dividend rates for preferred stock with similar terms.
Considerable judgment is required to develop the fair value estimates; therefore, the values are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair value estimates are based on information available to management as of December 31, 2004.2005. We are not aware of any subsequent factors that would significantly affect the estimated fair value amounts. For more information about the fair values of our interest rate swaps, see Note 4.
Income Taxes
We have two categories of income taxes in our statements of consolidated income: current and deferred. Current income tax expense consists of federal and state income tax less applicable tax credits related to the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year.
Investment Tax Credits
Deferred investment tax credits associated with distribution operations are included as a regulatory liability in our consolidated balance sheets(see Note 5). These investment tax credits are being amortized over the estimated life of the related properties as credits to income in accordance with regulatory treatment.requirements. We reduce income tax expense in our statements of consolidated income for the investment tax credits and other tax credits associated with our nonregulated subsidiaries. Components of income tax expense shown in the statements of consolidated income are as follows:follows.
In millions | | 2004 | | 2003 | | 2002 | |
Included in expenses: | | | | | | | | | | |
Current income taxes | | | | | | | | | | |
Federal | | $ | 25 | | $ | 20 | | | ($19 | ) |
State | | | 1 | | | 13 | | | (4 | ) |
Deferred income taxes | | | | | | | | | | |
Federal | | | 60 | | | 52 | | | 79 | |
State | | | 5 | | | 3 | | | 3 | |
Amortization of investment tax credits | | | (1 | ) | | (1 | ) | | (1 | ) |
Total | | $ | 90 | | $ | 87 | | $ | 58 | |
In millions | | 2005 | | 2004 | | 2003 | |
Current income taxes | | | | | | | | | | |
Federal | | $ | 84 | | $ | 25 | | $ | 20 | |
State | | | 18 | | | 1 | | | 13 | |
Deferred income taxes | | | | | | | | | | |
Federal | | | 17 | | | 60 | | | 52 | |
State | | | - | | | 5 | | | 3 | |
Amortization of investment tax credits | | | (2 | ) | | (1 | ) | | (1 | ) |
Total | | $ | 117 | | $ | 90 | | $ | 87 | |
The reconciliations between the statutory federal income tax rate, the effective rate and the related amount of tax for the years ended December 31, 2005, 2004 2003 and 20022003 are presented below:below.
2005 | | | | | |
Dollars in millions | | Amount | | % of Pretax Income | |
Computed tax expense at statutory rate | | $ | 109 | | | 35.0 | % |
State income tax, net of federal income tax benefit | | | 11 | | | 3.7 | |
Amortization of investment tax credits | | | (2 | ) | | (0.6 | ) |
Flexible dividend deduction | | | (2 | ) | | (0.6 | ) |
Other -- net | | | 1 | | | 0.2 | |
Total income tax expense at effective rate | | $ | 117 | | | 37.7 | % |
| | | | | | | |
2004 | | | | | | | |
Dollars in millions | | | Amount | | | % of Pretax Income | |
Computed tax expense at statutory rate | | $ | 85 | | | 35.0 | % |
State income tax, net of federal income tax benefit | | | 9 | | | 3.5 | |
Amortization of investment tax credits | | | (1 | ) | | (0.6 | ) |
Flexible dividend deduction | | | (2 | ) | | (0.6 | ) |
Other - net | | | (1 | ) | | (0.2 | ) |
Total income tax expense at effective rate | | $ | 90 | | | 37.1 | % |
| | 2004 | | 2003 | | 2002 | |
Dollars in millions | | Amount | | % of Pretax Income | | Amount | | % of Pretax Income | | Amount | | % of Pretax Income | |
Computed tax expense | | $ | 85 | | | 35.0 | % | $ | 78 | | | 35.0 | % | $ | 56 | | | 35.0 | % |
State income tax, net of federal income tax benefit | | | 9 | | | 3.5 | | | 8 | | | 3.8 | | | 4 | | | 2.4 | |
Amortization of investment tax credits | | | (1 | ) | | (0.6 | ) | | (1 | ) | | (0.6 | ) | | (1 | ) | | (0.8 | ) |
Flexible dividend deduction | | | (2 | ) | | (0.6 | ) | | (1 | ) | | (0.6 | ) | | (2 | ) | | (0.9 | ) |
Other-net | | | (1 | ) | | (0.2 | ) | | 3 | | | 1.4 | | | 1 | | | 0.3 | |
Total income tax expense | | $ | 90 | | | 37.1 | % | $ | 87 | | | 39.0 | % | $ | 58 | | | 36.0 | % |
2003 | | | | | |
Dollars in millions | | Amount | | % of Pretax Income | |
Computed tax expense at statutory rate | | $ | 78 | | | 35.0 | % |
State income tax, net of federal income tax benefit | | | 8 | | | 3.8 | |
Amortization of investment tax credits | | | (1 | ) | | (0.6 | ) |
Flexible dividend deduction | | | (1 | ) | | (0.6 | ) |
Other - net | | | 3 | | | 1.4 | |
Total income tax expense at effective rate | | $ | 87 | | | 39.0 | % |
Accumulated Deferred Income Tax Assets and Liabilities
We report some of our assets and liabilities differently for financial accounting purposes than we do for income tax purposes. TheWe report the tax effects of the differences in those items are reported as deferred income tax assets or liabilities in our consolidated balance sheets. TheWe measure the assets and liabilities are measured utilizingusing income tax rates that are currently in effect. Because of the regulated nature of the utilities’ business, we recorded a regulatory tax liability has been recorded in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS 109). The regulatory tax liability is being amortized, which we are amortizing over approximately 30 years(see Note 5). Our deferred tax asset includesassets include an additional pension liability of $33$37 million, which increased $7$3 million from 20032004 in accordance with SFAS 109 (see Note 6).
As indicated in the table below, our deferred tax assets and liabilities include certain items we acquired from NUI. We have provided a valuation allowance for some of these items that reducesreduce our net deferred tax assets to amounts we believe are more likely than not to be realized in future periods. With respect to our continuing operations, we have net operating losses in various jurisdictions. Components that give rise to the net accumulated deferred income tax liability are as follows:
follows.
| | As of: | |
In millions | | Dec. 31, 2004 | | Dec. 31, 2003 | |
Accumulated deferred income tax liabilities | | | | | | | |
Property-accelerated depreciation and other property-related items | | $ | 323 | | $ | 294 | |
Other | | | 238 | | | 125 | |
Total accumulated deferred income tax liabilities | | | 561 | | | 419 | |
Accumulated deferred income tax assets | | | | | | | |
Deferred investment tax credits | | | 8 | | | 7 | |
Deferred pension additional minimum liability | | | 34 | | | 27 | |
Net operating loss - NUI (1) | | | 31 | | | - | |
Net operating loss - Virginia Gas Company (2) | | | 6 | | | - | |
Capital loss carryforward | | | 5 | | | - | |
Alternative minimum tax credit (3) | | | 7 | | | - | |
Other | | | 41 | | | 9 | |
Total accumulated deferred income tax assets | | | 132 | | | 43 | |
Valuation allowances | | | (8 | ) | | - | |
Total accumulated deferred income tax assets, net of valuation allowance | | | 124 | | | 43 | |
Net accumulated deferred tax liability | | $ | 437 | | $ | 376 | |
| | As of: | |
In millions | | Dec. 31, 2005 | | Dec. 31, 2004 | |
Accumulated deferred income tax liabilities | | | | | |
Property - accelerated depreciation and other property-related items | | $ | 494 | | $ | 323 | |
Other | | | 39 | | | 238 | |
Total accumulated deferred income tax liabilities | | | 533 | | | 561 | |
Accumulated deferred income tax assets | | | | | | | |
Deferred investment tax credits | | | 7 | | | 8 | |
Deferred pension additional minimum liability | | | 37 | | | 34 | |
Net operating loss - NUI (1) | | | 26 | | | 31 | |
Net operating loss - Virginia Gas Distribution Company (2) | | | 0 | | | 6 | |
Capital loss carryforward (3) | | | 4 | | | 5 | |
Alternative minimum tax credit (4) | | | 8 | | | 7 | |
Other | | | 37 | | | 41 | |
Total accumulated deferred income tax assets | | | 119 | | | 132 | |
Valuation allowances (5) | | | (9 | ) | | (8 | ) |
Total accumulated deferred income tax assets, net of valuation allowance | | | 110 | | | 124 | |
Net accumulated deferred tax liability | | $ | 423 | | $ | 437 | |
(1) | Includes NUI’s federal net operating loss carryforwards of approximately $79$62 million that expire in 20242024. |
(2) | Includes Virginia Gas Company’s $18 million pre-acquisition net operating losses,Distribution Company which are subject to a Internal Revenue Service Section 382 limitation (or reduced amount available for deduction as a result of changewas sold in control) and expire in 2016 through 2020.December 2005. |
(3) | Was generatedExpires December 31, 2007. |
(4) | Generated by NUI and can be carried forward indefinitely to reduce our future tax liability. |
(5) | Increase to valuation allowance is primarily due to increase in net operating losses on NUI headquarters that are not usable in New Jersey. |
Related Party Transactions
We previously recognized revenue and had accounts receivable from our affiliate, SouthStar, as detailed in the table below. As a result of our adoption of FIN 46R inon January 1, 2004, we consolidated all of SouthStar’s accounts with our subsidiaries’ accounts and eliminated any intercompany balances between segments. For more discussion of FIN 46R and the impact of its adoption on our consolidated financial statements, see Note 3.
In millions | | 2004 | | 2003 | | 2002 | | | 2003 | |
Recognized revenue | | $ | - | | $ | 169 | | $ | 171 | | | $ | 169 | |
Accounts receivable | | | - | | | 11 | | | - | | | | 11 | |
> Note 14
Segment Information
OurPrior to 2005, our business iswas organized into three operating segments:segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environments as well as the manner in which we manage these segments and our internal management information flows.
Beginning in 2005 we added an additional segment, retail energy operations, which consists of the operations of SouthStar, our retail gas marketing subsidiary that conducts business primarily in Georgia. We added this segment as a result of the way management views its operations and in consideration of the impact of our acquisitions of NUI and Jefferson Island in the fourth quarter of 2004. The addition of this segment also is consistent with our desire to provide transparency and visibility to SouthStar on a stand-alone basis and to provide additional visibility to the remaining businesses in the energy investments segment, principally Pivotal Jefferson Island, LLC (Pivotal Jefferson Island) and Pivotal Propane of Virginia, Inc. (Pivotal Propane), which are more closely related in structure and operation.
We have recast the segment information for the years ended December 31, 2004 and 2003 in accordance with the guidance set forth in SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” as shown in the tables below.
Our four operating segments are now as follows:
· | Distribution operations consists primarily of |
o | Virginia Natural Gas.Gas |
· | Retail energy operations consists of SouthStar |
· | Wholesale services consists primarily of Sequent.Sequent |
· | Energy investments consists primarily of SouthStar, |
o | Pivotal Jefferson Island |
o | Pivotal Propane Virginia Gas Company and AGL Networks. |
We treat corporate, our fourthfifth segment, as a nonoperating business segment, that consists primarily ofand it currently includes AGL Resources, Inc., AGL Services Company, nonregulated financing and captive insurance subsidiariesPivotal Energy Development and the effect of intercompany eliminations. We eliminated intersegment sales for the years ended December 31, 2005, 2004 2003 and 20022003 from our statements of consolidated income.
We evaluate segment performance based primarily on the non-GAAP measure of earnings before interest and taxes (EBIT), which includes the effects of corporate expense allocations. EBIT is a non-GAAP measure that includes operating income, other income, equity in SouthStar’s income in 2003, and 2002, donations, minority interest in 2005 and 2004 and gains on sales of assets. Items that we do not include in EBIT are financing costs, including interest and debt expense, income taxes and the cumulative effect of a change in accounting principle, each of which we evaluate on a consolidated level. We believe EBIT is a useful measurement of our performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.
You should not consider EBIT an alternative to, or a more meaningful indicator of our operating performance than, operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The reconciliations of EBIT to operating income and net income for the years ended December 31, 2005, 2004 2003 and 20022003 are presented below:
In millions | | 2004 | | 2003 | | 2002 | |
Operating revenues | | $ | 1,832 | | $ | 983 | | $ | 877 | |
Operating expenses | | | 1,500 | | | 741 | | | 660 | |
Gain on sale of Caroline Street campus | | | - | | | 16 | | | - | |
Operating income | | | 332 | | | 258 | | | 217 | |
Other income | | | - | | | 40 | | | 30 | |
Minority interest | | | (18 | ) | | - | | | | |
EBIT | | | 314 | | | 298 | | | 247 | |
Interest expense | | | 71 | | | 75 | | | 86 | |
Earnings before income taxes | | | 243 | | | 223 | | | 161 | |
Income taxes | | | 90 | | | 87 | | | 58 | |
Income before cumulative effect of change in accounting principle | | | 153 | | | 136 | | | 103 | |
Cumulative effect of change in accounting principle | | | - | | | (8 | ) | | - | |
Net income | | $ | 153 | | $ | 128 | | $ | 103 | |
below.
In millions | | 2005 | | 2004 | | 2003 | |
Operating revenues | | $ | 2,718 | | $ | 1,832 | | $ | 983 | |
Operating expenses | | | 2,276 | | | 1,500 | | | 741 | |
Gain on sale of Caroline Street campus | | | - | | | - | | | 16 | |
Operating income | | | 442 | | | 332 | | | 258 | |
Other income | | | (1 | ) | | - | | | 40 | |
Minority interest | | | (22 | ) | | (18 | ) | | - | |
EBIT | | | 419 | | | 314 | | | 298 | |
Interest expense | | | 109 | | | 71 | | | 75 | |
Earnings before income taxes | | | 310 | | | 243 | | | 223 | |
Income taxes | | | 117 | | | 90 | | | 87 | |
Income before cumulative effect of change in accounting principle | | | 193 | | | 153 | | | 136 | |
Cumulative effect of change in accounting principle | | | - | | | - | | | (8 | ) |
Net income | | $ | 193 | | $ | 153 | | $ | 128 | |
Summarized income statement, balance sheet and capital expenditure information by segment as of and for the years ended December 31, 2005, 2004 and 2003 and 2002 areis shown in the following tables:tables.
2004 | |
In millions | | Distribution Operations | | Wholesale Services | | Energy Investments | | Corporate and Intersegment Eliminations | | Consolidated AGL Resources | |
Operating revenues from external parties | | $ | 926 | | $ | 54 | | $ | 852 | | $ | - | | $ | 1,832 | |
Intersegment revenues(1) | | | 185 | | | - | | | - | | | (185 | ) | | - | |
Total revenues | | | 1,111 | | | 54 | | | 852 | | | (185 | ) | | 1,832 | |
Operating expenses | | | | | | | | | | | | | | | | |
Cost of gas | | | 470 | | | 1 | | | 707 | | | (184 | ) | | 994 | |
Operating and maintenance | | | 286 | | | 27 | | | 65 | | | (1 | ) | | 377 | |
Depreciation and amortization | | | 85 | | | 1 | | | 4 | | | 9 | | | 99 | |
Taxes other than income taxes | | | 24 | | | 1 | | | 1 | | | 4 | | | 30 | |
Total operating expenses | | | 865 | | | 30 | | | 777 | | | (172 | ) | | 1,500 | |
Operating income (loss) | | | 246 | | | 24 | | | 75 | | | (13 | ) | | 332 | |
Earnings in equity interests | | | - | | | - | | | 2 | | | - | | | 2 | |
Minority interest | | | - | | | - | | | (18 | ) | | - | | | (18 | ) |
Other income (loss) | | | 1 | | | - | | | - | | | (3 | ) | | (2 | ) |
EBIT | | $ | 247 | | $ | 24 | | $ | 59 | | | ($16 | ) | $ | 314 | |
Identifiable assets | | $ | 4,386 | | $ | 696 | | $ | 630 | | | ($86 | ) | $ | 5,626 | |
Investment in joint ventures | | | - | | | - | | | 235 | | | (221 | ) | | 14 | |
Total assets | | $ | 4,386 | | $ | 696 | | $ | 865 | | | ($307 | ) | $ | 5,640 | |
Goodwill | | $ | 340 | | $ | - | | $ | 14 | | $ | - | | $ | 354 | |
Capital expenditures | | $ | 205 | | $ | 8 | | $ | 40 | | $ | 11 | | $ | 264 | |
2003 | | |
2005 | | | | | | | | | | | | | | |
In millions | | Distribution Operations | | Wholesale Services | | Energy Investments | | Corporate and Intersegment Eliminations | | Consolidated AGL Resources | | | Distribution operations | | Retail energy operations | | Wholesale services | | Energy investments | | Corporate and intersegment eliminations | | Consolidated AGL Resources | |
Operating revenues (1) | | $ | 936 | | $ | 41 | | $ | 6 | | $ | - | | $ | 983 | | |
Operating revenues from external parties | | | $ | 1,571 | | $ | 996 | | $ | 95 | | $ | 56 | | $ | - | | $ | 2,718 | |
Intersegment revenues (1) | | | | 182 | | | - | | | - | | | - | | | (182 | ) | | - | |
Total revenues | | | | 1,753 | | 996 | | 95 | | 56 | | (182 | ) | | 2,718 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost of gas | | | 337 | | 1 | | 1 | | - | | 339 | | | | 939 | | 850 | | 3 | | 16 | | (182 | ) | | 1,626 | |
Operation and maintenance | | | 261 | | 20 | | 9 | | (7 | ) | | 283 | | | | 372 | | 58 | | 39 | | 17 | | (9 | ) | | 477 | |
Depreciation and amortization | | | 81 | | - | | 1 | | 9 | | 91 | | | | 114 | | 2 | | 2 | | 5 | | 10 | | 133 | |
Taxes other than income taxes | | | 24 | | | - | | | - | | | 4 | | | 28 | | | | 32 | | | 1 | | | 1 | | | 1 | | | 5 | | | 40 | |
Total operating expenses | | | 703 | | | 21 | | | 11 | | | 6 | | | 741 | | | | 1,457 | | | 911 | | | 45 | | | 39 | | | (176 | ) | | 2,276 | |
Gain (loss) on sale of Caroline Street campus (2) | | | 21 | | | - | | | - | | | (5 | ) | | 16 | | |
Operating income (loss) | | | 254 | | 20 | | (5 | ) | | (11 | ) | | 258 | | | | 296 | | 85 | | 50 | | 17 | | (6 | ) | | 442 | |
Donation to private foundation | | | (8 | ) | | - | | - | | - | | (8 | ) | |
Earnings in equity interests | | | - | | - | | 48 | | - | | 48 | | |
Minority interest | | | | - | | (22 | ) | | - | | - | | - | | (22 | ) |
Other income (loss) | | | 1 | | | - | | | - | | | (1 | ) | | - | | | | 3 | | | - | | | (1 | ) | | 2 | | | (5 | ) | | (1 | ) |
EBIT | | $ | 247 | | $ | 20 | | $ | 43 | | | ($12 | ) | $ | 298 | | | $ | 299 | | $ | 63 | | $ | 49 | | $ | 19 | | $ | (11 | ) | $ | 419 | |
Identifiable assets | | $ | 3,325 | | $ | 460 | | $ | 90 | | $ | 2 | | $ | 3,877 | | | $ | 4,720 | | $ | 342 | | $ | 1,058 | | $ | 350 | | $ | (219 | ) | $ | 6,251 | |
Investment in joint ventures | | | - | | | - | | | 101 | | | - | | | 101 | | | | - | | | - | | | - | | | - | | | - | | | - | |
Total assets | | $ | 3,325 | | $ | 460 | | $ | 191 | | $ | 2 | | $ | 3,978 | | | $ | 4,720 | | $ | 342 | | $ | 1,058 | | $ | 350 | | $ | (219 | ) | $ | 6,251 | |
Goodwill | | $ | 177 | | $ | - | | $ | - | | $ | - | | $ | 177 | | | $ | 408 | | $ | - | | $ | - | | $ | 14 | | $ | - | | $ | 422 | |
Capital expenditures | | $ | 126 | | $ | 2 | | $ | 8 | | $ | 22 | | $ | 158 | | | $ | 215 | | $ | 4 | | $ | 1 | | $ | 9 | | $ | 38 | | $ | 267 | |
2002 | | |
2004 | | | | | | | | | | | | | | |
In millions | | Distribution Operations | | Wholesale Services | | Energy Investments | | Corporate and Intersegment Eliminations | | Consolidated AGL Resources | | | Distribution operations | | Retail energy operations | | Wholesale services | | Energy investments | | Corporate and intersegment eliminations | | Consolidated AGL Resources | |
Operating revenues (1) | | $ | 852 | | $ | 23 | | $ | 2 | | $ | - | | $ | 877 | | |
Operating revenues from external parties | | | $ | 926 | | $ | 827 | | $ | 54 | | $ | 25 | | $ | - | | $ | 1,832 | |
Intersegment revenues (1) | | | | 185 | | | - | | | - | | | - | | | (185 | ) | | - | |
Total revenues | | | | 1,111 | | 827 | | 54 | | 25 | | (185 | ) | | 1,832 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost of gas | | | 267 | | - | | - | | 1 | | 268 | | | | 471 | | 695 | | 1 | | 12 | | (184 | ) | | 995 | |
Operation and maintenance | | | 255 | | 13 | | 8 | | (2 | ) | | 274 | | | | 286 | | 60 | | 27 | | 5 | | (1 | ) | | 377 | |
Depreciation and amortization | | | 82 | | - | | - | | 7 | | 89 | | | | 85 | | 2 | | 1 | | 2 | | 9 | | 99 | |
Taxes other than income taxes | | | 25 | | | 1 | | | 1 | | | 2 | | | 29 | | | | 23 | | | - | | | 1 | | | 1 | | | 4 | | | 29 | |
Total operating expenses | | | 629 | | | 14 | | | 9 | | | 8 | | | 660 | | | | 865 | | | 757 | | | 30 | | | 20 | | | (172 | ) | | 1,500 | |
Operating income (loss) | | | 223 | | 9 | | (7 | ) | | (8 | ) | | 217 | | | | 246 | | 70 | | 24 | | 5 | | (13 | ) | | 332 | |
Interest income | | | 1 | | - | | - | | - | | 1 | | |
Earnings in equity interests | | | - | | - | | 27 | | - | | 27 | | | | - | | - | | - | | 2 | | - | | 2 | |
Minority interest | | | | - | | (18 | ) | | - | | - | | - | | (18 | ) |
Other income (loss) | | | 1 | | | - | | | 4 | | | (3 | ) | | 2 | | | | 1 | | | - | | | - | | | - | | | (3 | ) | | (2 | ) |
EBIT | | $ | 225 | | $ | 9 | | $ | 24 | | | ($11 | ) | $ | 247 | | | $ | 247 | | $ | 52 | | $ | 24 | | $ | 7 | | $ | (16 | ) | $ | 314 | |
Identifiable assets | | $ | 3,150 | | $ | 364 | | $ | 107 | | $ | 46 | | $ | 3,667 | | | $ | 4,383 | | $ | 244 | | $ | 696 | | $ | 386 | | $ | (86 | ) | $ | 5,623 | |
Investment in joint ventures | | | - | | | - | | | 75 | | | - | | | 75 | | | | - | | | - | | | - | | | 235 | | | (221 | ) | | 14 | |
Total assets | | $ | 3,150 | | $ | 364 | | $ | 182 | | $ | 46 | | $ | 3,742 | | | $ | 4,383 | | $ | 244 | | $ | 696 | | $ | 621 | | $ | (307 | ) | $ | 5,637 | |
Goodwill | | | $ | 340 | | $ | - | | $ | - | | $ | 14 | | $ | - | | $ | 354 | |
Capital expenditures | | $ | 128 | | $ | 1 | | $ | 29 | | $ | 29 | | $ | 187 | | | $ | 205 | | $ | 4 | | $ | 8 | | $ | 36 | | $ | 11 | | $ | 264 | |
2003 | | | | | | | | | | | | | |
In millions | | Distribution operations | | Retail energy operations | | Wholesale services | | Energy investments | | Corporate and intersegment eliminations | | Consolidated AGL Resources | |
Operating revenues (1) | | $ | 936 | | $ | - | | $ | 41 | | $ | 6 | | $ | - | | $ | 983 | |
Operating expenses | | | | | | | | | | | | | | | | | | | |
Cost of gas | | | 337 | | | - | | | 1 | | | 1 | | | - | | | 339 | |
Operation and maintenance | | | 261 | | | - | | | 20 | | | 9 | | | (7 | ) | | 283 | |
Depreciation and amortization | | | 81 | | | - | | | - | | | 1 | | | 9 | | | 91 | |
Taxes other than income taxes | | | 24 | | | - | | | - | | | - | | | 4 | | | 28 | |
Total operating expenses | | | 703 | | | - | | | 21 | | | 11 | | | 6 | | | 741 | |
Gain (loss) on sale of Caroline Street campus (2) | | | 21 | | | - | | | - | | | - | | | (5 | ) | | 16 | |
Operating income (loss) | | | 254 | | | - | | | 20 | | | (5 | ) | | (11 | ) | | 258 | |
Donation to private foundation | | | (8 | ) | | - | | | - | | | - | | | - | | | (8 | ) |
Earnings in equity interests | | | - | | | 46 | | | - | | | 2 | | | - | | | 48 | |
Other income (loss) | | | 1 | | | - | | | - | | | - | | | (1 | ) | | - | |
EBIT | | $ | 247 | | $ | 46 | | $ | 20 | | | ($3 | ) | $ | (12 | ) | $ | 298 | |
Identifiable assets | | $ | 3,325 | | $ | - | | $ | 460 | | $ | 90 | | $ | 2 | | $ | 3,877 | |
Investment in joint ventures | | | - | | | 71 | | | - | | | 30 | | | - | | | 101 | |
Total assets | | $ | 3,325 | | $ | 71 | | $ | 460 | | $ | 120 | | $ | 2 | | $ | 3,978 | |
Goodwill | | $ | 177 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | 177 | |
Capital expenditures | | $ | 126 | | $ | - | | $ | 2 | | $ | 8 | | $ | 22 | | $ | 158 | |
(1) | Intersegment revenues - Wholesale services records its energy marketing and risk management revenue on a net basis. The following table provides detail of wholesale services’ total gross revenues and gross sales to distribution operations:operations. |
In millions | | Third-Party Gross Revenues | | Intersegment Revenues | | Total Gross Revenues | | | Third-party Gross Revenues | | Intersegment Revenues | | Total Gross Revenues | |
2005 | | | $ | 6,017 | | $ | 792 | | $ | 6,809 | |
2004 | | $ | 4,378 | | $ | 369 | | $ | 4,747 | | | | 4,378 | | | 369 | | | 4,747 | |
2003 | | | 3,298 | | | 353 | | | 3,651 | | | | 3,298 | | | 353 | | | 3,651 | |
2002 | | | 1,639 | | | 131 | | | 1,770 | | |
(2) | The gain before income taxes of $16 million on the sale of our Caroline Street campus was recorded as operating income (loss) in two of our segments. A gain of $21 million on the sale of the land was recorded in distribution operations and a write-off of ($5)$5 million on the buildings and their contents was recorded in our corporate segment. |
Quarterly Financial Data (Unaudited)
Our quarterly financial data for 2005, 2004 2003 and 20022003 are summarized below. The variance in our quarterly earnings is the result of the seasonal nature of our primary business.
2004 | | | | |
In millions, except per share amounts | | March 31 | | June 30 | | Sept. 30 | | Dec. 31 | | | March 31 | | June 30 | | Sept. 30 | | Dec. 31 | |
2005 | | | | | | | | | | |
Operating revenues | | $ | 651 | | $ | 294 | | $ | 262 | | $ | 625 | | | $ | 908 | | $ | 430 | | $ | 387 | | $ | 993 | |
Operating income | | | 133 | | | 53 | | | 46 | | | 100 | | | | 181 | | | 66 | | | 54 | | | 141 | |
Net income | | | 66 | | | 21 | | | 20 | | | 46 | | | | 88 | | | 24 | | | 15 | | | 66 | |
Basic earnings per share | | | 1.02 | | | 0.34 | | | 0.31 | | | 0.64 | | | | 1.15 | | | 0.31 | | | 0.19 | | | 0.86 | |
Fully diluted earnings per share | | | 1.00 | | | 0.33 | | | 0.31 | | | 0.64 | | | | 1.14 | | | 0.30 | | | 0.19 | | | 0.85 | |
2004 | | | | | | | | | | | | | | |
Operating revenues | | | $ | 651 | | $ | 294 | | $ | 262 | | $ | 625 | |
Operating income | | | | 133 | | | 53 | | | 46 | | | 100 | |
Net income | | | | 66 | | | 21 | | | 20 | | | 46 | |
Basic earnings per share | | | | 1.02 | | | 0.34 | | | 0.31 | | | 0.64 | |
Fully diluted earnings per share | | | | 1.00 | | | 0.33 | | | 0.31 | | | 0.64 | |
2003 | | | |
In millions, except per share amounts | | March 31 | | June 30 | | Sept. 30 | | Dec. 31 | |
Operating revenues | | $ | 353 | | $ | 187 | | $ | 166 | | $ | 278 | |
Operating income | | | 101 | | | 41 | | | 58 | | | 58 | |
Income before cumulative effect of change in accounting principle | | | 60 | | | 19 | | | 22 | | | 35 | |
Net income | | | 52 | | | 19 | | | 22 | | | 35 | |
Basic earnings per share before cumulative change in accounting principle | | | 0.99 | | | 0.30 | | | 0.35 | | | 0.54 | |
Basic earnings per share | | | 0.86 | | | 0.30 | | | 0.35 | | | 0.54 | |
Fully diluted earnings per share before cumulative change in accounting principle | | | 0.98 | | | 0.29 | | | 0.34 | | | 0.54 | |
Fully diluted earnings per share | | | 0.85 | | | 0.29 | | | 0.34 | | | 0.54 | |
2002 | | | | |
In millions, except per share amounts | | March 31 | | June 30 | | Sept. 30 | | Dec. 31 | | |
2003 | | | | | | | | | | |
Operating revenues | | $ | 272 | | $ | 161 | | $ | 193 | | $ | 251 | | | $ | 353 | | $ | 187 | | $ | 166 | | $ | 277 | |
Operating income | | | 74 | | | 42 | | | 38 | | | 63 | | | | 101 | | | 41 | | | 58 | | | 58 | |
Income before cumulative effect of change in accounting principle | | | | 60 | | | 19 | | | 22 | | | 35 | |
Net income | | | 50 | | | 12 | | | 10 | | | 31 | | | | 52 | | | 19 | | | 22 | | | 35 | |
Basic earnings per share before cumulative change in accounting principle | | | | 0.99 | | | 0.30 | | | 0.35 | | | 0.54 | |
Basic earnings per share | | | 0.90 | | | 0.22 | | | 0.17 | | | 0.55 | | | | 0.86 | | | 0.30 | | | 0.35 | | | 0.54 | |
Fully diluted earnings per share before cumulative change in accounting principle | | | | 0.98 | | | 0.29 | | | 0.34 | | | 0.54 | |
Fully diluted earnings per share | | | 0.89 | | | 0.22 | | | 0.17 | | | 0.55 | | | | 0.85 | | | 0.29 | | | 0.34 | | | 0.54 | |
Our basic and fully diluted earnings per common share are calculated based on the weighted daily average number of common shares and common share equivalents outstanding during the quarter. Those totals differ from the basic and fully diluted earnings per share as shown onin the statements of consolidated income, which are based on the weighted average number of common shares and common share equivalents outstanding during the entire year.
To the Board of Directors and Shareholders of AGL Resources Inc.:
We have completed an integrated audit ofAGLaudits of AGL Resources Inc.’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 20042005 and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions on AGL Resources Inc.'s 2005, 2004, and 2003 consolidated financial statements and on its internal control over financial reporting as of December 31, 2005, based on our audits and the reports of other auditors, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, based on our audits and the report of other auditors, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of AGL Resources Inc. and its subsidiaries at December 31, 20042005 and 2003,2004, and the results of their operations and their cash flows for each of the twothree years in the period ended December 31, 20042005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion,based on our audits and the report of other auditors, the 20042005 and 20032004 financial statement schedule information listed in theindexthe index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the relatedconsolidatedfinancialrelated 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 financial statementschedulestatement schedule based on our audits. We did not audit the 2004 and 2003 financial statements ofSouthStarof SouthStar Energy Services LLC, ajointa joint venture in which a subsidiary of the Company has a non-controlling 70% financial interest, which statements reflect total assetsofassets of $243 million as of December 31, 2004 and total revenues of $827 million as of and for the year ended December 31, 2004. The Company’s equity investmentin earnings in SouthStar Energy Services LLC was $71 million and equity in earnings was $46 million as of and for the year ended December 31, 2003. Those statements were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included forSouthStarfor SouthStar Energy Services LLC., is based solely on the report of the other auditors. 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 of financial statements 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 and the report of other auditors provide a reasonable basis for our opinion.
As discussed in Note 31 to the consolidated financial statements, effective January 1, 2003, AGL Resources Inc. and subsidiariesadopted EITF No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. As discussed in Note 3 to the consolidated financial statements, effective January 1, 2003, AGL Resources Inc. and subsidiaries adopted Statementchanged its method of Financial Accounting Standards No. 143,Accountingaccounting for Asset Retirement Obligations. As discussed in Note 3 to the consolidated financial statements, effectiverealized gains and losses on derivative energy commodity contracts as of January 1, 2004, AGL Resources Inc.2003, and subsidiaries adopted Financial Accounting Standards Board (FASB) Interpretation No. 46-R, “Consolidationits method of Variable Interest Entities”.accounting for variable interest entities as of January 1, 2004.
Internal control over financial reporting
Also, in our opinion, based on our audit and the report of other auditors, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting related to AGL Resources Inc. appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 20042005 based on criteria established inInternal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, based on our audit and the report of other auditors, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004,2005, based on criteria established inInternal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit.We did not examine the effectiveness of internal control ofSouthStar Energy Services LLC as of December 31, 2004. The effectiveness of SouthStar Energy Services LLC’s internal control over financial reporting was audited by other auditors whose report has been furnished to us, and our opinions expressed herein, insofar as they relate to the effectiveness ofSouthStar Energy Services LLC’s internal control over financial reporting arebased solely on the report of the other auditors.Weaudit. We conducted our audit of internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit and the report of the other auditors provideprovides a reasonable basis for our opinions.
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.
As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Jefferson Island Storage & Hub LLC and NUI Corporation from its assessment of internal control over financial reporting as of December 31, 2004 because they were acquired by the Company in purchase business combinations during 2004. We have also excluded Jefferson Island Storage & Hub LLC and NUI Corporation from our audit of internal control over financial reporting. Jefferson Island Storage & Hub LLC and NUI Corporation are wholly owned subsidiaries whose total assets represent $86 million and $1,352 million and total revenues represent $11 million and $86 million, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2004.
/s/ PricewaterhouseCoopers LLP
Atlanta, Ga.Georgia
February 14, 20056, 2006
REPORT OF ERNST & YOUNG LLP,
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Executive Committee and Members
SouthStar Energy Services LLC
We have audited the balance sheets of SouthStar Energy Services LLC (the Company) as of December 31, 2004 and 2003, and the related statements of income, changes in members’ capital, and cash flowsflow for each of the threetwo years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of SouthStar Energy Services LLC at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the threetwo years in the period ended December 31, 2004 in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of SouthStar Energy Services LLC'sLLC’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 4, 2005 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Atlanta, Georgia
February 4, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of
Directors of AGL Resources Inc.:
We have audited the accompanying consolidated statements of income, shareholders’ equity, and cash flows for the year ended December 31, 2002 of AGL Resources Inc. and subsidiaries (the “Company”). Our audit also included the financial statement schedule listed in the Index at Item 15 for the year ended December 31, 2002. These financial statements and financial statement schedule are the responsibility of the Company���s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audit.
We conducted our audit 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, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of AGL Resources Inc. and subsidiaries for the year ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
January 27, 2003
None
Conclusions Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act). As of December 31, 2004, the end of the period covered by this report, except, and in accordance with the Public Company Accounting Oversight Board’s Auditing Standard No.2,An Audit of Internal Control Over Financial Reporting Performed in Conjunction With an Audit of Financial Statements, the disclosure controls and procedures of Jefferson Island Storage & Hub, LLC and NUI Corporation were excluded from management’s evaluation, as Jefferson Island Storage & Hub, LLC and NUI Corporation were acquired on October 1, 2004 and November 30, 2004, respectively. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 20042005 in providing a reasonable level of assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
Management’s ReportsReport on Internal Control Over Financial Reporting
AGL Resources Inc.
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework inInternal Control - Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We excluded Jefferson Island Storage & Hub, LLC and NUI Corporation from our assessment of internal control over financial reporting as of December 31, 2004 because they were acquired by us in purchase business combinations during the fourth quarter of 2004. Jefferson Island Storage & Hub, LLC’s and NUI Corporation’s total assets represents $86 million and $1,352 million, and total revenues represents $11 million and $86 million, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2004.
Based on our evaluation under the framework inInternal Control — Integrated Framework issued by COSO, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated2005 in their report, which insofar as it relates to the effectiveness of SouthStar Energy Services LLC is based solely upon the report of other auditors and is included herein.
February 15, 2005
/s/ Paula Rosput Reynolds
Paula Rosput Reynolds
Chairman, President and Chief Executive Officer
/s/ Richard T. O’Brien
Richard T. O’Brien
Executive Vice President and Chief Financial Officer
SouthStar Energy Services LLC
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework inInternal Control - Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission, and in accordance with, Public Company Accounting Oversight Board’s Auditing Standard No. 2,An Audit of Internal Control Over Financial Reporting Performed in Conjunction With an Audit of Financial Statements. Based on our evaluation under the framework inInternal Control - Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004.
Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.
February 2, 2005
/s/ Michael A. Braswell
Michael A. Braswell
President, SouthStar Energy Services LLC
/s/ Michael A. Degnan
Michael A. Degnan
Director, Finance & Accounting, SouthStar Energy Services LLC
Report of Independent Registered Public Accounting Firm
The Executive Committee and Members of SouthStar Energy Services LLC
We have audited management’s assessment, included in the accompanying Report of Management on Internal Control Over Financial Reporting, that SouthStar Energy Services LLC (“SouthStar”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). SouthStar’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provideproviding 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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositionsOur management’s assessment of the assetseffectiveness of the company; (2) 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 (3) 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.
In our opinion, management’s assessment that SouthStar maintained effective internal control over financial reporting as of December 31, 2004, is fairly2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in all material respects, based on the COSO criteria. Also, in our opinion, SouthStar maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.their report.
February 6, 2006
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets of SouthStar as of December 31, 2004/s/ D. Raymond Riddle
D. Raymond Riddle
Interim Chairman and 2003, and the related statements of income, changes in members’ capital, and cash flows for each of the three years in the period ended December 31, 2004 of SouthStar and our report dated February 4, 2005 expressed an unqualified opinion thereon.Chief Executive Officer
/s/ Ernst & Young LLPAndrew W. Evans
Andrew W. Evans
Atlanta, Georgia
February 4, 2005Senior Vice President and Chief Financial Officer
Changes in Internal Control over Financial Reporting
There were no significant changes in our internal control over financial reporting identified in connection with the above-referenced evaluation by management of the effectiveness of our internal control over financial reporting that occurred during our fourth quarter ended December 31, 2004.2005.
None
Part III
The information required by this item with respect to directors will be set forth under the captions “Election of Directors” and “Corporate Governance - Committees of the Board,” “Audit Committee” and “Nominating and Corporate Governance Committee - Nomination of Director Candidates” in the Proxy Statement for our 20052006 Annual Meeting of Shareholders (the Proxy Statement) or in a subsequent amendment to this report. The information required by this item with respect to the executive officers is pursuant to Instruction 3 of Item 401(b) of Regulation S-K and General Instruction G (3) of Form 10-K, set forth at Part I, Item 4A of this report under the caption “Executive Officers of the Registrant.” The information required by this item with respect to Section 16(a) beneficial ownership reporting compliance will be set forth under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement or amendment. All such information that is provided in the Proxy Statement is incorporated herein by reference.
Code of EthicsWe have adopted a code of ethics, which applies to our chief executive officer and our senior financial officers. Our code of ethics is included as an exhibit to this report and is posted on our website at www.aglresources.com under the heading “Corporate Governance - Highlights.” We will also provide a copy of the code of ethics without charge upon request made to shareholders upon request.our Director of Investor Relations at 404-584-3801. Any amendments to or waivers from any provision of our code of ethics will be disclosed by posting such information on our website.
The information required by this item will be set forth under the captions “Director Compensation,” “Compensation and Management Development Committee Report,” “Compensation and Management Development Committee Interlocks and Insider Participation,” “Executive Compensation,” and “Stock Performance Graph” in the Proxy Statement or subsequent amendment referred to in Item 10 above. All such information that is provided in the Proxy Statement is incorporated herein by reference, except for the information under the captions “Compensation and Management Development Committee Report” and “Stock Performance Graph,” which is specifically not so incorporated herein by reference.
The information required by this item will be set forth under the captions “Share Ownership” and “Equity“Executive Compensation - Equity Compensation Plan Information” in the Proxy Statement or subsequent amendment referred to in Item 10 above. All such information that is provided in the Proxy Statement is incorporated herein by reference.
The information required by this item will be set forth under the captions “Certain Relationships and Related Transactions” in the Proxy Statement or subsequent amendment referred to in Item 10 above. All such information that is provided in the Proxy Statement is incorporated herein by reference.
The information required by this item will be set forth under the caption “Proposal 43 - Ratification of the Appointment of PricewaterhouseCoopers LLP as ourOur Independent Auditor for 2005”2006” in the Proxy Statement or subsequent amendment to referred to in Item 10 above. All such information that is provided in the Proxy Statement is incorporated herein by reference.
PART IV
(a) Documents Filed as Part of This Report.
(1) Financial Statements
Included underin Item 8 are the following financial statements:
· | Consolidated Balance Sheets as of December 31, 20042005 and 20032004 |
· | Statements of Consolidated Income for the years ended December 31, 2005, 2004, 2003 and 20022003 |
· | Statements of Consolidated Common Stockholders’Shareholders’ Equity for the years ended December 31, 2005, 2004 2003 and 20022003 |
· | Statements of Consolidated Cash Flows for the years ended December 31, 2005, 2004, 2003 and 20022003 |
· | Notes to Consolidated Financial Statements |
· | Reports of Independent Auditors’ Reports |
· | Independent Auditors’ Report on Management’s Assessment of Internal ControlRegistered Public Accounting Firms |
(2) Financial Statement Schedules
· | Financial Statements for SouthStar Energy Services LLC for each of the three years ended December 31, 2003 and Report of Independent Auditors (incorporated by reference to Item 15(d) of AGL Resources Inc.’s Form 10-K for the fiscal year ended December 31, 2003). |
· | Financial Statement Schedule II. Valuation and Qualifying Accounts -Allowance for Uncollectible Accounts and Income Tax Valuations |
· | Schedules other than those referred to above are omitted and are not applicable or not required, or the required information is shown in the financial statements or notes thereto |
Schedules other than those referred to above are omitted and are not applicable or not required, or the required information is shown in the financial statements or notes thereto.
(3) Exhibits
Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses.
1.1 | Underwriting Agreement dated February 11, 2003 by and among AGL Resources Inc. and the Underwriters named therein. (Exhibit 1.1, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2002). |
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1.2 | Underwriting Agreement dated September 22, 2004 among AGL Capital Corporation, AGL Resources Inc. and J. P. Morgan Securities, Inc., as representative of the several underwriters named in Schedule A thereto (Exhibit 1, AGL Resources Inc. Form 8-K dated September 22, 2004). |
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1.3 | Underwriting Agreement dated November 18, 2004 among AGL Resources Inc. and J. P. Morgan Securities Inc. and Morgan Stanley & Co. Incorporated, as representatives of the several underwriters named in Schedule A thereto (Exhibit 1, AGL Resources Inc. Form 8-K dated November 18, 2004). |
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1.4 | Underwriting Agreement dated December 15, 2004 among AGL Capital Corporation, AGL Resources Inc. and Banc of America Securities LLC and J. P. Morgan Securities, Inc., as representatives of the several underwriters named in Schedule A thereto. (Exhibit 1, AGL Resources Inc. Form 8-K dated December 15, 2004). |
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2.1 | Stock Purchase Agreement dated May 8, 2000 by and between AGL Resources Inc. and Consolidated Natural Gas Company, Virginia Natural Gas, Inc. and Dominion Resources, Inc. (Exhibit 2.1, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2000). |
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2.2 | First Amendment to Stock Purchase Agreement dated October 1, 2000 by and between AGL Resources Inc. and Consolidated Natural Gas Company, Virginia Natural Gas, Inc. and Dominion Resources, Inc. (Exhibit 2.2, AGL Resources Inc. Form 8-K dated October 18, 2000). |
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2.3 | Agreement and Plan of Merger by and between AGL Resources Inc., Cougar Corporation and NUI Corporation, dated July 14, 2004 (Exhibit 2.1, AGL Resources Inc. Form 8-K dated July 15, 2004). |
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3.1 | Amended and Restated Articles of Incorporation filed January 5, 1996,November 2, 2005, with the Secretary of State of the Statestate of Georgia (Exhibit B, Proxy Statement and Prospectus filed as a part of Amendment No. 1 to Registration Statement on3.1, AGL Resources Inc. Form S-4, No. 33-99826)8-K dated November 2, 2005). |
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3.2 | Bylaws, as amended on October 29, 2003 (Exhibit 3.2, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2003). |
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4.1.a | Specimen form of Common Stock certificate (Exhibit 4.1, AGL Resources Inc. Form 10-K for the fiscal year ended September 30, 1999). |
4.1.b | Specimen AGL Capital Corporation 6.00% Senior Notes due 2034 (Exhibit 4.1, AGL Resources Inc. Form 8-K dated September 22, 2004). |
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4.1.c | Specimen AGL Capital Corporation 4.95% Senior Notes due 2015. (Exhibit 4.1, AGL Resources Inc. Form 8-K dated December 15, 2004). |
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4.24.1.d | Specimen form of Right certificate (Exhibit 1, AGL Resources Inc. Form 8-K filed March 6, 1996). |
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4.34.2.a | Indenture, dated as of December 1, 1989, between Atlanta Gas Light Company and Bankers Trust Company, as Trustee (Exhibit 4(a), Atlanta Gas Light Company registration statement on Form S-3, No. 33-32274). |
4.4 | |
4.2.b | First Supplemental Indenture dated as of March 16, 1992, between Atlanta Gas Light Company and NationsBank of Georgia, National Association, as Successor Trustee (Exhibit 4(a), Atlanta Gas Light Company registration statement on Form S-3, No. 33-46419). |
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4.54.2.c | Indenture, dated February 20, 2001 among AGL Capital Corporation, AGL Resources Inc. and The Bank of New York, as Trustee (Exhibit 4.2, AGL Resources Inc. registration statement on Form S-3, filed on September 17, 2001, No. 333-69500) |
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4.64.3.a | Guarantee of AGL Resources Inc. dated as of September 27, 2004 regarding the AGL Capital Corporation 6.00% Senior Note due 2034 (Exhibit 4.3, AGL Resources Inc. Form 8-K dated September 22, 2004). |
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4.74.3.b | Guarantee of AGL Resources Inc. dated as of December 20, 2004 regarding the AGL Capital Corporation 4.95% Senior Note due 2015 (Exhibit 4.3, AGL Resources Inc. Form 8-K dated December 15, 2004). |
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4.4.a | Rights Agreement dated as of March 6, 1996 between AGL Resources Inc. and Wachovia Bank of North Carolina, N.A. as Rights Agent (Exhibit 1, AGL Resources Inc. Form 8-A dated March 6, 1996). |
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4.4.b | Second Amendment to Rights Agreement dated as of June 5, 2002 between AGL Resources Inc. and Equiserve Trust Company, N.A. (Exhibit 1, AGL Resources Inc. Amendment No. 1 to Form 8-A dated June 2, 2002). |
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10.1 | Executive Compensation Contracts, Plans and Arrangements. |
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10.1.a | AGL Resources Inc. Long-Term Incentive Plan (1999), as amended and restated as of January 1, 2002 (Exhibit 99.2, AGL Resources Inc. Form 10-Q for the quarter ended March 31, 2002). |
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10.1.b | First amendment to the AGL Resources Inc. Long-Term Incentive Plan (1999), as amended and restated.restated (Exhibit 10.1.b, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2004). |
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10.1.c | Form of Incentive Stock Option Agreement, Nonqualified Stock Option Agreement and Restricted Stock Agreement for key employees (Exhibit 10.1, AGL Resources Inc. Form 10-Q for the quarter ended September 30, 2004). |
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10.1.d | Form of Restricted Stock Unit Agreement and Performance Cash Unit Agreement for key employees (Exhibit 10.1 and 10.2, respectively, AGL Resources Inc. Form 8-K dated January 3, 2005). |
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10.1.e | Form of Performance Unit Agreement for key employees.employees (Exhibit 10.1.e, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2004). |
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10.1.f | AGL Resources Inc. Long-Term Stock Incentive Plan of 1990 (Exhibit 10(ii), Atlanta Gas Light Company Form 10-K for the fiscal year ended September 30, 1991). |
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10.1.g | First Amendment to the AGL Resources Inc. Long-Term Stock Incentive Plan of 1990 (Exhibit B to the Atlanta Gas Light Company Proxy Statement for the Annual Meeting of Shareholders held February 5, 1993). |
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10.1.h | Second Amendment to the AGL Resources Inc. Long-Term Stock Incentive Plan of 1990 (Exhibit 10.1.d, AGL Resources Inc. Form 10-K for the fiscal year ended September 30, 1997). |
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10.1.i | Third Amendment to the AGL Resources Inc. Long-Term Stock Incentive Plan of 1990 (Exhibit C to the Proxy Statement and Prospectus filed as a part of Amendment No. 1 to Registration Statement on Form S-4, No. 33-99826). |
10.1.j | Fourth Amendment to the AGL Resources Inc. Long-Term Stock Incentive Plan of 1990 (Exhibit 10.1.f, AGL Resources Inc. Form 10-K for the fiscal year ended September 30, 1997). |
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10.1.k | Fifth Amendment to the AGL Resources Inc. Long-Term Stock Incentive Plan of 1990 (Exhibit 10.1.g, AGL Resources Inc. Form 10-K for the fiscal year ended September 30, 1997). |
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10.1.l | Sixth Amendment to the AGL Resources Inc. Long-Term Stock Incentive Plan of 1990 (Exhibit 10.1.a, AGL Resources Inc. Form 10-Q for the quarter ended March 31, 1998). |
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10.1.m | Seventh Amendment to the AGL Resources Inc. Long-Term Stock Incentive Plan of 1990 (Exhibit 10.1, AGL Resources Inc. Form 10-Q for the quarter ended December 31, 1998). |
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10.1.n | Eighth Amendment to the AGL Resources Inc. Long-Term Stock Incentive Plan of 1990 (Exhibit 10.1, AGL Resources Inc. Form 10-Q for the quarter ended March 31, 2000). |
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10.1.o | Ninth Amendment to the AGL Resources Inc. Long-Term Stock Incentive Plan 1990 (Exhibit 10.6, AGL Resources Inc. Form 10-Q for the quarter ended September 30, 2002). |
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10.1.p | AGL Resources Inc. Nonqualified Savings Plan as amended and restated as of January 1, 2001 (Exhibit 10.1.n, AGL Resources Inc. Form 10-K for the fiscal year ended September 30, 2001). |
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10.1.q | First Amendment to the AGL Resources Inc. Nonqualified Savings Plan (Exhibit 10.3, AGL Resources Inc. Form 10-Q for the quarter ended September 30, 2002). |
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10.1.r | Second Amendment to the AGL Resources Inc. Nonqualified Savings Plan.Plan (Exhibit 10.1.r, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2004). |
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10.1.s | Third Amendment to the AGL Resources Inc. Nonqualified Savings Plan.Plan (Exhibit 10.1.s, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2004). |
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10.1.t | AGL Resources Inc. Amended and Restated 1996 Non-Employee Directors Equity Compensation Plan (Exhibit 10.1, AGL Resources Inc. Form 10-Q for the quarter ended September 30, 2002). |
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10.1.u | First Amendment to the AGL Resources Inc. Amended and Restated 1996 Non-Employee Directors Equity Compensation Plan (Exhibit 10.1.o, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2002). |
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10.1.v | AGL Resources Inc. 1998 Common Stock Equivalent Plan for Non-Employee Directors (Exhibit 10.1.b, AGL Resources Inc. Form 10-Q for the quarter ended December 31, 1997). |
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10.1.w | First Amendment to the AGL Resources Inc. 1998 Common Stock Equivalent Plan for Non-Employee Directors (Exhibit 10.5, AGL Resources Inc. Form 10-Q for the quarter ended March 31, 2000). |
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10.1.x | Second Amendment to the AGL Resources Inc. 1998 Common Stock Equivalent Plan for Non-Employee Directors (Exhibit 10.4, AGL Resources Inc. Form 10-Q for the quarter ended September 30, 2002). |
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10.1.y | Third Amendment to the AGL Resources Inc. 1998 Common Stock Equivalent Plan for Non-Employee Directors (Exhibit 10.5, AGL Resources Inc. Form 10-Q for the quarter ended September 30, 2002). |
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10.1.z | AGL Resources Inc. Officer Incentive Plan (Exhibit 10.2, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2001). |
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10.1.aa | Form of AGL Resources Inc. Executive Post Employment Medical Benefit Plan (Exhibit 10.1.d, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2003). |
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10.1.ab | AGL Resources Inc. Executive Performance Incentive Plan dated February 2, 2002 (Exhibit 99.1, AGL Resources Inc. Form 10-Q for the quarter ended March 31, 2002). |
10.1.ac | Forms of Nonqualified Stock Option Agreement without the reload provision (LTIP and OIP) (Exhibit 10.1, AGL Resources Inc. Form 8-K dated March 15, 2005). |
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10.1.ad | Form of Nonqualified Stock Option Agreement with the reload provision (OIP) (Exhibit 10.2, AGL Resources Inc. Form 8-K dated March 15, 2005). |
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10.1.ae | Continuity Agreement, dated December 1, 2003, by and between AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly owned subsidiary) and Kevin P. Madden (Exhibit 10.1.w, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2003). |
10.1.ad | Continuity Agreement, dated December 1, 2003, by and between AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly owned subsidiary) and Richard T. O’Brien (Exhibit 10.1.x, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2003). |
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10.1.ae10.1.af | Continuity Agreement, dated December 1, 2003, by and between AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly owned subsidiary) and Paula G. Rosput (Exhibit 10.1.y, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2003). |
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10.1.af10.1.ag | Continuity Agreement, dated September 30, 2005, by and between AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly owned subsidiary) and Andrew W. Evans (Exhibit 10.1, AGL Resources Inc. Form 8-K dated September 27, 2005). |
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10.1.ah | Description of compensation arrangements for Paula Rosput Reynolds, Richard T. O’Brien, Kevin P. Madden and Paul R. Shlanta (Item 1.01, AGL Resources Inc. Form 8-K dated February 8, 2005). |
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10.1.ai | Description of compensation agreements for Paula Rosput Reynolds and D. Raymond Riddle (Item 1.01, AGL Resources Inc. Form 8-K/A Amendment No. 1 dated December 6, 2005). |
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10.1.aj | Description of compensation agreements for Kevin P. Madden and R. Eric Martinez (Item 1.01, AGL Resources Inc. Form 8-K/A Amendment No. 1, dated December 7, 2005). |
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10.1.ak | Description of compensation for Andrew W. Evans (Item 1.01, AGL Resources Inc. Form 8-K, dated September 27, 2005). |
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10.1.al | Continuity Agreement, dated December 1, 2003, by and between AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly owned subsidiary) and Paul R. Shlanta (Exhibit 10.1.z, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2003). |
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10.1.ag10.1.am | Continuity Agreement, dated December 1, 2003, by and between AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly owned subsidiary) and Melanie M. Platt (Exhibit 10.2, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2004). |
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10.1.ah10.1.an | Form of Director Indemnification Agreement, dated April 28, 2004, between AGL Resources Inc., on behalf of itself and the Indemnities named therein (Exhibit 10.3, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2004). |
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10.1.ai10.1.ao | Description of Directors’ Compensation (Exhibit 10.1, AGL Resources Inc. Form 8-K dated December 1, 2004). |
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10.1.aj10.1.ap | Description of Director’s Compensation with respect to the annual retainer and description of Director non-employee share-ownership guidelines (Item 1.01, AGL Resources Inc. Form 8-K dated December 7, 2005). |
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10.1.aq | Form of Stock Award Agreement for Non-Employee Directors.Directors (Exhibit 10.1.aj, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2004). |
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10.1.ak10.1.ar | Form on Nonqualified Stock Option Agreement for Non-Employee Directors.Directors (Exhibit 10.1.ak, AGL Resources Inc. Form 10-K for the fiscal year ended December 31, 2004). |
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10.1.al10.1.as | Summary of AGL Resources Inc. Annual Team Performance Incentive Plan for 2004- 2005 (Exhibit 10.1, AGL Resources Inc. Form 8-K dated February 2,June 27, 2005). |
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10.1.at | Non-Solicitation, Cooperation and General Release and Waiver Agreement, dated January 1, 2006, by and between AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly-owned subsidiary) and Paula Rosput Reynolds (Exhibit 10.1, AGL Resources Inc. Form 8-K dated January 1, 2006). |
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10.2 | Guaranty Agreement, effective November 30, 2003, by and between Atlanta Gas Light Company and AGL Resources Inc. (Exhibit 10.3, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2003). |
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10.3 | Form of Commercial Paper Dealer Agreement between AGL Capital Corporation, as Issuer, AGL Resources Inc., as Guarantor, and the Dealers named therein, dated September 25, 2000 (Exhibit 10.79, AGL Resources Inc. Form 10-K for the fiscal year ended September 30, 2000). |
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10.4 | Guarantee of AGL Resources Inc., dated October 5, 2000, of payments on promissory notes issued by AGL Capital Corporation (AGLCC) pursuant to the Issuing and Paying Agency Agreement dated September 25, 2000, between AGLCC and The Bank of New York (Exhibit 10.80, AGL Resources Inc. Form 10-K for the fiscal year ended September 30, 2000). |
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10.5 | Issuing and Paying Agency Agreement, dated September 25, 2000, between AGL Capital Corporation and The Bank of New York. (Exhibit 10.81, AGL Resources Inc. Form 10-K for the fiscal year ended September 30, 2000). |
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10.6 | Master Management Services Agreement, dated April 24, 2000, by and between Atlanta Gas Light Company and Environmental ThermoRetec Consulting Corporation. (Exhibit 10.1, AGL Resources Inc. 10-Q for the quarter ended June 30, 2000) (Confidential treatment pursuant to 17 CFR Sections 200.80 (b) and 240.24b-2 has been granted regarding certain portions of this exhibit, which portions have been filed separately with the Commission) (Exhibit 10.82, AGL Resources Inc. Form 10-K for the fiscal year ended September 30, 2000). |
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10.7 | Amended and Restated Master Environmental Management Services Agreement, dated July 25, 2002 by and between Atlanta Gas Light Company and The RETEC Group, Inc. (Exhibit 10.2, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2003). (Confidential treatment pursuant to 17 CFR Sections 200.80 (b) and 240.24-b has been granted regarding certain portions of this exhibit, which portions have been filed separately with the Commission). |
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10.810.7 | Credit Agreement, dated as of October 22, 2004, among AGL Resources Inc., as Guarantor, AGL Capital Corporation, as Borrower, JPMorgan Chase Bank, as administrative agent, Morgan Stanley Senior Funding, Inc., as syndication agent, and the several other banks and other financial institutions named therein (Exhibit 10.2, AGL Resources Inc. Form 10-Q for the quarter ended September 30, 2004). |
10.910.8 | Three Year Credit Agreement, dated May 26, 2004, by and between AGL Resources Inc., as Guarantor, AGL Capital Corporation, as Borrower, and the Lenders named therein (Exhibit 10.1, AGL Resources Inc. Form 10-Q for the quarter ended June 30, 2004). |
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10.1010.9 | First Amendment toAmended and Restated Credit Agreement, dated September 30, 2004,August 31, 2005, by and among AGL Resources Inc., AGL Capital Corporation, SunTrust Bank, as administrative agent, Wachovia Bank, National Association, as syndication agent, JP Morgan Chase Bank, The Bank of Tokyo-Mitsubishi, Ltd. and Calyon New York Branch, as documentation agents, and the several other banks and other financial institutions named therein (Exhibit 10, AGL Resources Inc., Form 8-K dated September 30, 2004)August 31, 2005).
|
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10.1110.10 | SouthStar Energy Services LLC Agreement, dated April 1, 2004 by and between Georgia Natural Gas Company and Piedmont Energy Company (Exhibit 10, AGL Resources Inc. Form 10-Q for the quarter ended March 31, 2004). |
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12 | Statements of computation of ratios. |
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14 | AGL Resources Inc. Code of Ethics for its Chief Executive Officer and its Senior Financial Officers (Exhibit 14, AGL Resources Inc. Form 10-K for the year ended December 31, 2004). |
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| Consent of Deloitte & Touche LLP, independent registered public accounting firm |
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23.3 | |
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24 | Powers of Attorney (included with Signature Pageon signature page hereto). |
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31 | |
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32 | |
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(b) | Exhibits filed as part of this report. |
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| See Item 15(a)(3). |
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(c) | Financial statement schedules filed as part of this report. See Item 15(a)(2). |
(b)Exhibits filed as part of this report.
See Item 15(a)(3).
(c)Financial statement schedules filed as part of this report.
See Item 15(a)(2).
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 2, 2005.1, 2006.
AGL RESOURCES INC.
By:/s/ Paula Rosput ReynoldsD. Raymond Riddle
Paula Rosput ReynoldsD. Raymond Riddle
Interim Chairman President and Chief Executive Officer
Power of Attorney
KNOW ALL MEN BY THESE PRESENT,PRESENTS, that each person whose signature appears below constitutes and appoints Paula Rosput Reynolds, Richard T. O’BrienD. Raymond Riddle, Andrew W. Evans, Bryan E. Seas and Paul R. Shlanta, and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K for the year ended December 31, 2004,2005, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite or necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated as of February 2, 2005.1, 2006.
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Signatures | Title |
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/s/ Paula Rosput ReynoldsD. Raymond Riddle | Interim Chairman President and Chief Executive Officer |
Paula Rosput Reynolds | (Principal Executive Officer) |
D. Raymond Riddle |
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/s/ Richard T. O’BrienAndrew W. Evans | ExecutiveSenior Vice President and Chief Financial Officer (Principal Financial Officer) |
Richard T. O’BrienAndrew W. Evans |
| (Principal |
/s/ Bryan E. Seas | Vice President, Controller and Chief Accounting and FinancialOfficer (Principal Accounting Officer) |
Bryan E. Seas |
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/s/ Thomas D. Bell, Jr. | Director |
Thomas D. Bell, Jr. | |
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//s/ Charles R. Crisp | Director |
Charles R. Crisp | |
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/s/ Michael J. Durham | Director |
Michael J. Durham |
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/s/ Dean R. O’Hare | Director |
Dean R. O’Hare |
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/s/ Arthur E. Johnson | Director |
Arthur E. Johnson |
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//s/ Arthur E. Johnson | Director |
Arthur E. Johnson | |
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/s/ Wyck A. Knox, Jr.
| Director |
Wyck A. Knox, Jr. | |
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//s/ Dennis M. Love Dennis M. Love | Director |
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/s/ D. Raymond Riddle
| Director |
D. Raymond Riddle | |
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/s/ James A. Rubright | Director |
James A. Rubright | |
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/s/ Felker W. Ward, Jr. | Director |
Felker W. Ward, Jr. | |
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/s/ Bettina M. Whyte | Director |
Bettina M. Whyte | |
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/s/ Henry C. Wolf | Director |
Henry C. Wolf | |
Financial Statements for SouthStar Energy Services LLC for each of the three years in the period ended December 31, 2003 and Report of Independent Auditors, which are included pursuant to Rule 3-09 of Regulation S-X.
REPORT OF INDENDENT AUDITORS
The Executive Committee and Members
SouthStar Energy Services LLC
We have audited the balance sheets of SouthStar Energy Services LLC as of December 31, 2003 and 2002, and the related statements of income, changes in members’ capital, and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of SouthStar Energy Services LLC at December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States.
/s/ Ernst & Young LLP
Atlanta, Georgia
January 21, 2004
SouthStar Energy Services LLC
Balance Sheets
| | December 31 | |
| | 2003 | | 2002 | |
Assets | | (In Thousands) | |
Current assets: | | | | | | | |
Cash and cash equivalents | | $ | 7,639 | | $ | 6,906 | |
Restricted cash | | | 3,654 | | | 8,484 | |
Accounts receivable: | | | | | | | |
Trade accounts receivable | | | 64,532 | | | 71,913 | |
Unbilled revenue | | | 70,539 | | | 55,941 | |
Allowance for doubtful accounts | | | (11,231 | ) | | (14,945 | ) |
| | | 123,840 | | | 112,909 | |
Inventories | | | 29,108 | | | 35,799 | |
Financial instruments | | | 4,541 | | | - | |
Prepaid gas and expenses | | | 4,830 | | | 708 | |
Other current assets | | | 300 | | | 244 | |
Total current assets | | | 173,912 | | | 165,050 | |
Property and equipment: | | | | | | | |
Office equipment | | | 54 | | | 27 | |
Furniture and fixtures | | | 254 | | | 187 | |
Software | | | 2,250 | | | 500 | |
Leasehold improvements | | | 192 | | | 81 | |
| | | 2,750 | | | 795 | |
Less accumulated depreciation | | | (808 | ) | | (580 | ) |
Net property and equipment | | | 1,942 | | | 215 | |
Intangibles, net of accumulated amortization of $5,493 and $4,818 at December 31, 2003 and 2002, respectively | | | - | | | 675 | |
Total assets | | $ | 175,854 | | $ | 165,940 | |
Liabilities and Members’ capital | | | | | | | |
Current liabilities: | | | | | | | |
Accounts payable | | $ | 6,204 | | $ | 15,893 | |
Revolving line of credit | | | 5,169 | | | - | |
Accrued gas costs | | | 51,844 | | | 43,666 | |
Customer deposits | | | 6,095 | | | 11,189 | |
Financial instruments | | | - | | | 3,744 | |
Accrued compensation | | | 2,213 | | | 1,810 | |
Other accrued expenses | | | 3,522 | | | 3,290 | |
Total current liabilities | | | 75,047 | | | 79,592 | |
Total liabilities | | | 75,047 | | | 79,592 | |
Members’ capital | | | 99,622 | | | 87,918 | |
Accumulated other comprehensive income (loss) | | | 1,185 | | | (1,570 | ) |
Total Members’ capital | | | 100,807 | | | 86,348 | |
Total liabilities and Members’ capital | | $ | 175,854 | | $ | 165,940 | |
See accompanying notes.
SouthStar Energy Services LLC
Statements of Income
| | Year ended December 31 | |
| | 2003 | | 2002 | | 2001 | |
| | (In Thousands) | |
| | | | | | | |
Revenues | | $ | 745,599 | | $ | 629,615 | | $ | 715,388 | |
Cost of sales | | | 621,591 | | | 514,516 | | | 621,256 | |
Gross margin | | | 124,008 | | | 115,099 | | | 94,132 | |
| | | | | | | | | | |
Operating expenses: | | | | | | | | | | |
Selling, general and administrative | | | 59,895 | | | 72,231 | | | 73,033 | |
Depreciation and amortization | | | 1,147 | | | 1,964 | | | 1,281 | |
| | | 61,042 | | | 74,195 | | | 74,314 | |
Operating income | | | 62,966 | | | 40,904 | | | 19,818 | |
| | | | | | | | | | |
Miscellaneous income (expense): | | | | | | | | | | |
Interest expense | | | (343 | ) | | (306 | ) | | (2,860 | ) |
Interest income | | | 475 | | | 788 | | | 143 | |
Other, net | | | 215 | | | 128 | | | (297 | ) |
| | | 347 | | | 610 | | | (3,014 | ) |
Net income | | | 63,313 | | | 41,514 | | | 16,804 | |
| | | | | | | | | | |
Proforma provision for income taxes (unaudited) | | | 25,325 | | | 16,606 | | | 6,722 | |
Proforma net income (unaudited) | | $ | 37,988 | | $ | 24,908 | | $ | 10,082 | |
See accompanying notes.
SouthStar Energy Services LLC
Statements of Changes in Members’ Capital
(In Thousands)
Balance, January 1, 2001, as restated (Note 2) | | $ | 83,600 | |
| | | | |
Net income | | | 16,804 | |
Other comprehensive loss (Note 6) | | | (709 | ) |
Comprehensive income | | | 16,095 | |
| | | | |
Contributions from Members | | | 15,000 | |
Distributions to Members | | | (20,000 | ) |
Balance, December 31, 2001 | | | 94,695 | |
| | | | |
Net income | | | 41,514 | |
Other comprehensive loss (Note 6) | | | (861 | ) |
Comprehensive income | | | 40,653 | |
| | | | |
Distributions to Members | | | (49,000 | ) |
Balance, December 31, 2002 | | | 86,348 | |
| | | | |
Net income | | | 63,313 | |
Other comprehensive income (Note 6) | | | 2,755 | |
Comprehensive income | | | 66,068 | |
| | | | |
Distributions to Members | | | (51,609 | ) |
Balance, December 31, 2003 | | $ | 100,807 | |
See accompanying notes.
SouthStar Energy Services LLC
Statements of Cash Flows
| | Year ended December 31 | |
| | 2003 | | 2002 | | 2001 | |
| | (In Thousands) | |
| | | | | | | |
Operating activities | | | | | | | |
Net income | | $ | 63,313 | | $ | 41,514 | | $ | 16,804 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | |
Depreciation | | | 228 | | | 222 | | | 164 | |
Amortization | | | 919 | | | 1,742 | | | 1,117 | |
Provision for doubtful accounts | | | 16,627 | | | 26,240 | | | 36,740 | |
Net changes in operating assets and liabilities: | | | | | | | | | | |
Accounts receivable and unbilled revenue | | | (27,558 | ) | | (26,320 | ) | | 71,592 | |
Inventories | | | 6,691 | | | (1,157 | ) | | (188 | ) |
Prepaid gas and expenses | | | (4,122 | ) | | (185 | ) | | (35 | ) |
Restricted cash | | | 4,830 | | | (6,896 | ) | | (1,588 | ) |
Other current assets | | | (300 | ) | | - | | | 2,968 | |
Accounts payable | | | (9,689 | ) | | 10,066 | | | (25,470 | ) |
Accrued gas costs | | | 8,178 | | | 11,280 | | | (38,120 | ) |
Customer deposits | | | (5,094 | ) | | 8,532 | | | 2,657 | |
Financial instruments | | | (5,530 | ) | | 2,174 | | | (709 | ) |
Accrued compensation | | | 403 | | | 596 | | | (1,281 | ) |
Other accrued expenses | | | 232 | | | 1,477 | | | (7,225 | ) |
Net cash provided by operating activities | | | 49,128 | | | 69,285 | | | 57,426 | |
| | | | | | | | | | |
Investing activities | | | | | | | | | | |
Capital expenditures | | | (1,955 | ) | | (57 | ) | | (444 | ) |
Net cash used in investing activities | | | (1,955 | ) | | (57 | ) | | (444 | ) |
| | | | | | | | | | |
Financing activities | | | | | | | | | | |
Contributions from Members | | | - | | | - | | | 15,000 | |
Distributions to Members | | | (51,609 | ) | | (49,000 | ) | | (20,000 | ) |
Net additions (payments) on revolving line of credit | | | 5,169 | | | (17,212 | ) | | (53,865 | ) |
Net cash used in financing activities | | | (46,440 | ) | | (66,212 | ) | | (58,865 | ) |
| | | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | 733 | | | 3,016 | | | (1,883 | ) |
Cash and cash equivalents at beginning of year | | | 6,906 | | | 3,890 | | | 5,773 | |
Cash and cash equivalents at end of year | | $ | 7,639 | | $ | 6,906 | | $ | 3,890 | |
| | | | | | | | | | |
Supplemental disclosures of cash flow information | | | | | | | | | | |
Cash paid during the year for interest | | $ | 282 | | $ | 348 | | $ | 3,512 | |
See accompanying notes.
SouthStar Energy Services LLC
Notes to Financial Statements
December 31, 2003
1. Organization
SouthStar Energy Services LLC (the “Company”) is a limited liability corporation formed on July 1, 1998 by Georgia Natural Gas Company (“GNGC”), a wholly owned subsidiary of AGL Resources Inc., Piedmont Energy Company (“Piedmont”), and Dynegy Energy Services, Inc. (“Dynegy”), to offer natural gas, propane, fuel oil, electricity, and related services to residential, commercial and industrial users in the Southeastern United States. The Company was certified as a retail marketer with the Georgia Public Service Commission on October 6, 1998. The Limited Liability Company Agreement of SouthStar Energy Services LLC (the “LLC Agreement”) provides for the Company to be dissolved ten years from the date of organization at the election of one or more Members. Absent such an action, the Company will dissolve twenty years from the date of organization unless extended by unanimous vote of the Members.
On March 11, 2003, GNGC completed the purchase ofDynegy’s 20% interest in the Company. As a result, GNGC owns a non-controlling 70% interest in the Company. Piedmont maintained its 30% economic ownership interest in the Company subsequent to March 11, 2003. Although GNGC owns a 70% economic interest in the Company, it does not have a controlling interest, as all matters of significance require the unanimous vote of the Members.
As part of the transaction, the Members agreed to permit Dynegy Marketing and Trade to exit its contract to provide asset management and gas procurement and supply services for the Company, effective January 31, 2003.
2. Summary of Significant Accounting Policies
Cash and Cash Equivalents
The Company considers all highly liquid investments with maturities of three months or less when purchased to be cash equivalents.
Restricted Cash
Restricted cash represents deposits held to secure credit extended to certain customers.
Inventories
Gas inventories are stated at the lower of cost or market with cost determined using a weighted average method.
Accounts Receivable
The Company performs credit evaluations on new customers and requires deposits from certain customers. Customers are generally billed monthly and accounts receivable are generally due within 30 days. The majority of the Company’s customers do not maintain long-term contracts with the Company. Provisions for doubtful accounts are recorded to reflect the expected net realizable value of accounts receivable based on historical collection trends. Accounts receivable are charged off once the Company has completed all reasonable collection efforts.
Property and equipment is stated at cost and consists of office furniture, computer software and equipment and leasehold improvements. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.
Intangibles
Intangible assets consisted primarily of customer contracts and lists contributed by the Members at the Company’s inception, which were being amortized on a straight-line basis over five years. Intangibles also include the purchase price for firm market customers acquired from other certified marketers, which is being amortized on a straight-line basis over five years.
During the year ended December 31, 2001, the Company determined that the initial intangibles recorded on its opening balance sheet were overstated by $7,682,000. The Company also determined that the original useful life of twenty years assigned to the intangibles at inception was based on the term of the LLC Agreement. Such useful life should have been determined based on the useful lives of the underlying gas contracts. The Company determined such useful lives should have been five years. These errors occurred as a result of a misuse of information, which existed at the date of the Company’s inception. The Company reduced January 1, 2001 Members’ capital by $8,447,000 to adjust for the effect of these errors. The effect of the adjustment was not deemed to be material to the results of operations or financial position of the Company as of and for the year ended December 31, 2001.
Revenues
The Company recognizes revenues as gas is delivered to customers. Unbilled revenue represents gas delivered but not yet billed to customers and is based on the estimated usage from the latest meter reading to the end of the accounting period.
Income Taxes
The Company is treated as a partnership for federal and state income tax purposes. As such, the Company is not liable for income taxes as the taxable income or loss is reported in the income tax returns of the Members. Accordingly, the accompanying financial statements do not provide for federal or state income taxes.
The proforma provision for income taxes represents a provision for federal and state income taxes as if the Company had operated as a C Corporation for income tax purposes.
Members’ Capital
The LLC Agreement calls for capital accounts to be established for each Member. The Executive Committee, by its unanimous vote, can require the Members to contribute additional capital to the Company. Withdrawals of capital from the Company also require unanimous Executive Committee approval.
The Members are parties to a Capital Contribution Agreement (the “Contribution Agreement”) that requires each Member to contribute additional capital to the Company to pay invoices for goods and services received from any vendor that is affiliated with a Member whenever funds are not otherwise available to pay those invoices. The capital contributions to pay affiliated vendor invoices are repaid as funds become available, but repayment is subordinated to the Company’s revolving line of credit with its financial institution. There was no activity related to the Contribution Agreement during the years ended December 31, 2003 and 2002. A Member contribution of $15 million to the Company was repaid to the Members under the Contribution Agreement during the year ended December 31, 2001.
Accounting Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Comprehensive Income
Comprehensive income consists of net income and other gains and losses affecting Members’ capital that, under GAAP, are excluded from net income. For the Company, such items consist primarily of unrealized gains and losses on certain derivatives.
Advertising
Advertising expenses are recognized as incurred and aggregated $3,169,000 and $4,743,000 for the years ended December 31, 2003 and 2002, respectively. The Company incurred no expenses for advertising during the year ended December 31, 2001.
Financial Instruments
The Company utilizes financial contracts to hedge the price volatility of natural gas. These financial contracts (futures, options, and swaps) are considered to be derivatives, with prices based on selected market indices. The Company accounts for these instruments in accordance with Statement of Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”). Those derivative transactions that qualify as cash flow hedges are reflected in the balance sheets at the fair values of the open positions with the corresponding unrealized gain or loss included in other comprehensive income, a component of Members’ capital. Those derivative transactions that are not designated as hedges are reflected in the balance sheets at fair values with corresponding unrealized gains or losses included in cost of sales in the statements of income. The effectiveness of the derivative as a hedge is based on a high correlation between changes in its value and changes in the value of the underlying hedged item. Ineffectiveness related to the Company’s derivative transactions designated as hedges is not material at December 31, 2003 and 2002. The termination of a derivative designated as a cash flow hedge will result in the reclassification of amounts included in accumulated other comprehensive income to the statement of income if the hedged transaction is no longer probable of occurring, otherwise the reclassification to the statement of income of accumulated other comprehensive income will be deferred until the hedged transaction affects earnings. The Company includes in operating results amounts received or paid when the underlying transaction settles. Fair value is based on published market indices and other appropriate valuation methodologies. The Company’s use of derivatives is governed by a risk management policy and is limited to hedging activities. The Company does not enter into or hold derivatives for trading or speculative purposes.
The Company enters into weather derivative contracts for hedging purposes in order to preserve margins in the event of warmer than normal weather in the winter months. These contracts are accounted for using the intrinsic value method under the guidelines of EITF 99-2,Accounting for Weather Derivatives.
The fair values of other financial instruments, which include cash, accounts receivable, accounts payable, accrued expenses and other liabilities, approximate their carrying values due to their short-term nature. See Note 6 for further discussion.
New Accounting Standards
In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 142,Goodwill and Other Intangible Assets (“SFAS No. 142”). This Statement changes the accounting for goodwill and intangible assets with indefinite useful lives from an amortization method to an impairment-only approach. The Company adopted SFAS No. 142 on January 1, 2002. Such adoption did not have a significant impact on the Company’s financial statements.
In April 2003, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 149,Amendment of FASB Statement No. 133 on Derivative and Hedging Transactions (“SFAS No. 149”). This Statement clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative as discussed in SFAS No. 133. In addition, it clarifies when a derivative contains a financing component that warrants special reporting in the statement of cash flows. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, except for certain hedging relationships designated after June 30, 2003. The Company adopted SFAS No. 149 on July 1, 2003. Such adoption did not have a significant impact on the Company’s financial statements.
Reclassifications
Certain reclassifications were made to the prior year’s financial statements to conform with the current year’s presentation.
3. Revolving Line of Credit
In October 2000, the Company entered into a revolving line of credit (the “Revolver”) with a group of banks to provide the working capital needed to meet seasonal demands. Maximum borrowings under the Revolver are $75,000,000. The Revolver is collateralized by varying percentages of eligible accounts receivable (85%), unbilled revenue (75%) and inventory (80%) of the Company. As of December 31, 2003 and 2002, $66,831,000 and $69,824,000, respectively, were available under the Revolver. The Revolver expires on March 19,2004. The base interest rate on the Revolver is Prime and/or LIBOR plus a margin. The margin rate applied to LIBOR begins at 2% for earnings before interest, taxes, depreciation and amortization (“EBITDA”) less than $9 million and is incrementally reduced to a minimum of 1.7% at EBITDA of $13 million or greater. The interest rate for borrowings under the Revolver was 4.00% and 4.25% at December 31, 2003 and 2002, respectively. Interest under the Revolver is payable monthly. At December 31, 2003 and 2002, the Company had irrevocable letters of credit totaling $3,000,000 and $5,176,000, respectively, securing certain of the Company’s pipeline capacity purchases. Amounts secured under letters of credit reduce the availability under the Revolver.
4. Commitments and Contingencies
The Company has entered into operating leases for office facilities and office equipment. Rental expense under operating leases was $731,000, $656,000 and $567,000 for the years ended December 31, 2003, 2002 and 2001, respectively. In September 2003, the Company entered into a three year operating lease agreement for office space with an affiliate of GNGC, which expires on July 7, 2006. Rent expense for the year ended December 31, 2003 includes $120,000 related to this lease.
The future minimum rentals under non-cancelable operating leases in effect at December 31, 2003 are as follows:
2004 | | $ | 632,000 | |
2005 | | | 487,000 | |
2006 | | | 205,000 | |
| | $ | 1,324,000 | |
At December 31, 2003, the Company had certain natural gas purchase commitments. These purchase commitments are correlated directly to fixed price sales contracts with certain of the Company’s customers. Obligations under these purchase agreements at December 31, 2003 aggregated $7,746,000 through November 2004. Obligations under these purchase agreements at December 31, 2002 aggregated $14,330,000 through 2003.
During the years ended December 31, 2003, 2002 and 2001, the Company purchased natural gas of $42,829,000, $32,480,000 and $21,977,000, respectively, under similar gas purchase agreements.
The Company also had natural gas purchase commitments related to the supply of minimum natural gas volumes during the winter months. These commitments are priced on an index-plus-premium basis. At December 31, 2003, the Company had obligations under these agreements for 15,745,000 dekatherms through March 2004. At December 31, 2002, the Company had obligations under these agreements for 13,181,000 dekatherms through March 2003. During the years ended December 31, 2003 and 2002, respectively, the Company purchased natural gas of $81,911,000 and $38,325,000 under similar gas purchase agreements. There were no purchases under similar agreements during the year ended December 31, 2001.
The Company entered into a new contract effective December 1, 2002 with its existing service provider for the outsourcing of its billing and customer service functions. The contract expires on November 30, 2007. During the years ended December 31, 2003, 2002 and 2001, the Company incurred $22,359,000, $26,441,000 and $20,018,000, respectively, for these services. The Company can terminate the agreement at any time without cause. In the first twelve months of the contract there is no penalty associated with such a termination. After that period, termination requires paying a penalty, which is calculated, based on the date of termination.
5. Employee Benefit Plans
The Company has a qualified incentive savings plan, which provides an opportunity for all eligible employees to contribute to their retirement savings. The Company matches 100% of the employee’s contribution up to a maximum Company contribution of 5% of each employee’s base compensation. For the years ended December 31, 2003, 2002 and 2001, the Company’s contributions under this plan were $208,000, $155,000 and $132,000, respectively.
6. Financial Instruments
The Company entered into natural gas financial contracts in order to hedge its natural gas inventory and to fix the price of a portion of its natural gas purchases. These contracts settle monthly with varying maturity dates through September 2005. At December 31, 2003, the fair value of open positions was reflected in the financial statements as an asset aggregating $4,541,000 offset by the combination of an increase to other comprehensive income (a component of Members’ capital) of $1,185,000 for the portion of the open positions designated as hedges and a decrease of $3,356,000 to cost of sales for the portion of the open positions not designated as hedges. Approximately $1,100,000 of the other comprehensive income balance at December 31, 2003 is expected to be reclassified into the statement of income within the next twelve months as the underlying transactions settle. At December 31, 2002, the fair value of open positions was reflected in the financial statements as a liability of $3,744,000 offset by the combination of an increase to other comprehensive loss (a component of Members’ capital) of $1,570,000 for the portion of the open positions designated as hedges and an increase of $2,174,000 to cost of sales for the portion of the open positions not designated as hedges.
To preserve margins in the event of warmer than normal weather in the winter months, the Company purchased option-based weather derivative contracts for the months of November 2003 through March 2004. The contracts contain strike amount provisions based on cumulative heating degree days (“HDD”) for the covered periods. Based upon actual HDD’s in November and December 2003, no receivable was recorded at December 31, 2003. Under a similar option-based weather derivative contract for the months of November 2002 through March 2003, based upon actual HDD’s in November and December 2002, no receivable was recorded at December 31, 2002.
7. Related Party Transactions
In conjunction with the Georgia Natural Gas Competition and Deregulation Act, the Company is assigned rights to capacity from Atlanta Gas Light Company (“AGLC”), an affiliate of GNGC, based on market share.
The Company purchased natural gas and pipeline capacity from affiliates of GNGC, Dynegy and Piedmont as follows:
| | Year ended December 31 | |
| | 2003 | | 2002 | | 2001 | |
GNGC | | $ | 181,348,000 | | $ | 243,113,000 | | $ | 190,000,000 | |
Dynegy | | | 15,791,000 | | | 178,115,000 | | | 445,000,000 | |
Piedmont | | | 1,096,000 | | | 9,615,000 | | | 12,000,000 | |
The Company owed the following amounts to affiliates of GNGC, Dynegy and Piedmont related to natural gas purchases and other services:
| | December 31 | |
| | 2003 | | 2002 | |
GNCC | | $ | 10,703,000 | | $ | 4,368,000 | |
Dynegy | | | - | | | 15,828,000 | |
Piedmont | | | - | | | 254,000 | |
The amounts due to affiliates in the table above are included in accrued gas costs on the balance sheet as of December 31, 2003 and 2002, respectively.
Effective April 1, 2003, the Georgia Public Service Commission ordered a change in the assets assigned to marketers with certain assets reverting back to AGLC, an affiliate of GNGC. As a result of this stipulation, the Company was required to sell 846,000 dekatherms of natural gas to AGLC aggregating $4,368,000. The sale was transacted at market index rates in effect at April 1, 2003.
For the year ended December 31, 2001, the Company was billed $5,701,000 by an affiliate of GNGC for customer enrollment and ongoing customer service.
AGL Resources Inc. and Subsidiaries
VALUATION AND QUALIFYING ACCOUNTS - ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS AND INCOME TAX VALUATION FOR EACH OF THE THREE YEARS IN THE PERIOD ENDED DECEMBER 31, 2004.2005.
In millions | | Allowance for uncollectible accounts | | Income tax valuation | |
Balance at December 31, 2001 | | $ | 7 | | $ | - | |
Provisions charged to income in 2002 | | | 3 | | | - | |
Accounts written off as uncollectible, net in 2002 | | | (8 | ) | | - | |
Balance at December 31, 2002 | | | 2 | | | - | |
Provisions charged to income in 2003 | | | 6 | | | - | |
Accounts written off as uncollectible, net in 2003 | | | (6 | ) | | - | |
Balance at December 31, 2003 | | | 2 | | | - | |
Provisions charged to income in 2004 | | | 5 | | | - | |
Accounts written off as uncollectible, net in 2004 | | | (5 | ) | | - | |
Additional provisions due to NUI acquisition | | | 4 | | | 8 | |
Additional provisions due to consolidation of SouthStar | | | 9 | | | - | |
Balance at December 31, 2004 | | $ | 15 | | $ | 8 | |
In millions | | Allowance for uncollectible accounts | | Income tax valuation | |
Balance at December 31, 2002 | | $ | 2 | | $ | - | |
Provisions charged to income in 2003 | | | 6 | | | - | |
Accounts written off as uncollectible, net in 2003 | | | (6 | ) | | - | |
Balance at December 31, 2003 | | | 2 | | | - | |
Provisions charged to income in 2004 | | | 5 | | | - | |
Accounts written off as uncollectible, net in 2004 | | | (5 | ) | | - | |
Additional provisions due to NUI acquisition | | | 4 | | | 8 | |
Additional provisions due to consolidation of SouthStar | | | 9 | | | - | |
Balance at December 31, 2004 | | | 15 | | | 8 | |
Provisions charged to income in 2005 | | | 17 | | | - | |
Accounts written off as uncollectible, net in 2005 | | | (17 | ) | | - | |
Additional valuation allowances | | | - | | | 1 | |
Balance at December 31, 2005 | | $ | 15 | | $ | 9 | |