UNITED STATES |
SECURITIES AND EXCHANGE COMMISSION |
Washington, D.C. 20549 |
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FORM 10-Q |
(Mark One) | |
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF |
THE SECURITIES EXCHANGE ACT OF 1934 |
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For the Quarterly Period Ended JuneSeptember 30, 2009 |
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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, Atlanta, Georgia 30309 |
(Address and zip code of principal executive offices) |
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404-584-4000 |
(Registrant's telephone number, including area code) |
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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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨ |
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Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨ |
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” ”accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. |
Large accelerated filer þ | Accelerated filer ¨ |
Non-accelerated filer ¨ (Do not check if a smaller reporting company) | Smaller reporting company ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨ No þ |
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Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date. |
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Class | Outstanding as of July 24,October 22, 2009 |
Common Stock, $5.00 Par Value | 77,278,94277,398,732 |
AGL RESOURCES INC.
Quarterly Report on Form 10-Q
For the Quarter Ended JuneSeptember 30, 2009
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AGL Capital | AGL Capital Corporation |
AGL Networks | AGL Networks, LLC |
Atlanta Gas Light | Atlanta Gas Light Company |
Bcf | Billion cubic feet |
Chattanooga Gas | Chattanooga Gas Company |
Credit FacilitiesFacility | Credit agreementsagreement supporting our commercial paper program |
EBIT | Earnings before interest and taxes, a non-GAAP measure that includes operating income and other income and excludes interest expense, and income tax expense; as an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, operating income, net income, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP |
EITF | Emerging Issues Task Force |
ERC | Environmental remediation costs associated with our distribution operations segment which are generally recoverable through rates mechanisms |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
FIN | FASB Interpretation Number |
Fitch | Fitch Ratings |
FSP | FASB Staff Position |
GAAP | Accounting principles generally accepted in the United States of America |
Georgia Commission | Georgia Public Service Commission |
GNG | Georgia Natural Gas, the name under which SouthStar does business in Georgia |
GNGC | Georgia Natural Gas Company, our wholly-owned subsidiary that owns our current 70% interest in SouthStar |
Golden Triangle Storage | Golden Triangle Storage, Inc. |
Heating Degree Days | A measure of the effects of weather on our businesses, calculated when the average daily actual temperatures are less than a baseline temperature of 65 degrees Fahrenheit. |
Heating Season | The period from November through March when natural gas usage and operating revenues are generally higher because more customers are connected to our distribution systems when weather is coldercolder. |
Jefferson Island | Jefferson Island Storage & Hub, LLC |
LOCOM | Lower of weighted average cost or current market price |
Marketers | Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission |
Moody’s | Moody’s Investors Service |
New Jersey CommissionBPU | 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 or loss on the sale of our assets; these items are included in our calculation of operating income as reflected in our condensed consolidated statements of income. Operating margin should not be considered an alternative to, or more meaningful than, operating income, net income, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP |
OTC | Over-the-counter |
Piedmont | Piedmont Natural Gas Company, Inc. |
Pivotal Utility | Pivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas |
PP&E | Property, plant and equipment |
PRP | Pipeline replacement program for Atlanta Gas Light |
S&P | Standard & Poor’s Ratings Services |
SEC | Securities and Exchange Commission |
Sequent | Sequent Energy Management, L.P. |
SFAS | Statement of Financial Accounting Standards |
SouthStar | SouthStar Energy Services LLC |
VaR | Value at risk 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 |
Virginia Natural Gas | Virginia Natural Gas, Inc. |
WACOG | Weighted average cost of gas |
WNA | Weather normalization adjustment |
REFERENCED ACCOUNTING STANDARDS
FIN 46 & FIN 46R | FIN 46, “Consolidation of Variable Interest Entities” |
EITF 99-2
| EITF 99-2, "Accounting for Weather Derivatives" |
FSP EITF 03-6-1 | FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” |
FSP FAS 132(R)-1 | FSP No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” |
FSP FAS 133-1 | FSP No. FAS 133-1, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133” |
FSP FAS 140-4 | FSP No. FAS 140-4, “Disclosures by Public Entities about Transfers of Financial Assets” |
FSP FAS 157-3 | FSP No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” |
FSP FAS 157-4 | FSP No. FAS 157-4, “Determining Whether a Market Is Not Active and a Transaction Is Not Distressed” |
SFAS 71 | SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” |
SFAS 133 | SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” |
SFAS 141 | SFAS No. 141, “Business Combinations” |
SFAS 157 | SFAS No. 157, “Fair Value Measurements” |
SFAS 160 | SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” |
SFAS 161 | SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities, an amendment of SFAS 133” |
SFAS 162 | SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” |
SFAS 165 | SFAS No. 165, “Subsequent Events” |
SFAS 166 | SFAS No. 166, “Accounting for Transfers of Financial Assets” |
SFAS 167 | SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” |
SFAS 168 | SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” |
Item 1. Financial Statements
AGL RESOURCES INC. AND SUBSIDIARIES
(UNAUDITED)
| | | | | As of | | | | |
In millions, except share data | | Sept. 30, 2009 | | | Dec. 31, 2008 | | | Sept. 30, 2008 | |
Current assets | | | | | | | | | |
Cash and cash equivalents | | $ | 21 | | | $ | 16 | | | $ | 11 | |
Inventories, net (Note 1) | | | 651 | | | | 663 | | | | 811 | |
Receivables | | | | | | | | | | | | |
Energy marketing receivables (Note 1) | | | 216 | | | | 549 | | | | 535 | |
Gas, unbilled and other receivables | | | 145 | | | | 472 | | | | 206 | |
Less allowance for uncollectible accounts | | | 16 | | | | 16 | | | | 17 | |
Total receivables | | | 345 | | | | 1,005 | | | | 724 | |
Derivative financial instruments – current portion (Note 2 and Note 3) | | | 146 | | | | 207 | | | | 172 | |
Unrecovered pipeline replacement program costs – current portion (Note 1) | | | 40 | | | | 41 | | | | 40 | |
Unrecovered environmental remediation costs – current portion (Note 1) | | | 13 | | | | 18 | | | | 20 | |
Other current assets | | | 102 | | | | 92 | | | | 162 | |
Total current assets | | | 1,318 | | | | 2,042 | | | | 1,940 | |
Long-term assets and other deferred debits | | | | | | | | | | | | |
Property, plant and equipment | | | 5,791 | | | | 5,500 | | | | 5,377 | |
Less accumulated depreciation | | | 1,761 | | | | 1,684 | | | | 1,651 | |
Property, plant and equipment-net | | | 4,030 | | | | 3,816 | | | | 3,726 | |
Goodwill | | | 418 | | | | 418 | | | | 418 | |
Unrecovered pipeline replacement program costs (Note 1) | | | 169 | | | | 196 | | | | 202 | |
Unrecovered environmental remediation costs (Note 1) | | | 142 | | | | 125 | | | | 124 | |
Derivative financial instruments (Note 2 and Note 3) | | | 31 | | | | 38 | | | | 16 | |
Other | | | 75 | | | | 75 | | | | 78 | |
Total long-term assets and other deferred debits | | | 4,865 | | | | 4,668 | | | | 4,564 | |
Total assets | | $ | 6,183 | | | $ | 6,710 | | | $ | 6,504 | |
Current liabilities | | | | | | | | | | | | |
Short-term debt (Note 6) | | $ | 310 | | | $ | 866 | | | $ | 769 | |
Energy marketing trade payables (Note 1) | | | 245 | | | | 539 | | | | 568 | |
Accounts payable - trade | | | 155 | | | | 202 | | | | 181 | |
Accrued expenses | | | 102 | | | | 113 | | | | 83 | |
Accrued pipeline replacement program costs – current portion (Note 1) | | | 55 | | | | 49 | | | | 43 | |
Customer deposits | | | 43 | | | | 50 | | | | 39 | |
Derivative financial instruments – current portion (Note 2 and Note 3) | | | 27 | | | | 50 | | | | 34 | |
Accrued environmental remediation liabilities – current portion (Note 1 and Note 7) | | | 21 | | | | 17 | | | | 16 | |
Other current liabilities | | | 86 | | | | 97 | | | | 89 | |
Total current liabilities | | | 1,044 | | | | 1,983 | | | | 1,822 | |
Long-term liabilities and other deferred credits | | | | | | | | | | | | |
Long-term debt (Note 6) | | | 1,975 | | | | 1,675 | | | | 1,675 | |
Accumulated deferred income taxes | | | 644 | | | | 571 | | | | 625 | |
Accumulated removal costs (Note 1) | | | 194 | | | | 178 | | | | 176 | |
Accrued pension obligations (Note 4) | | | 187 | | | | 199 | | | | 43 | |
Accrued environmental remediation liabilities (Note 1 and Note 7) | | | 109 | | | | 89 | | | | 89 | |
Accrued pipeline replacement program costs (Note 1) | | | 100 | | | | 140 | | | | 152 | |
Accrued postretirement benefit costs (Note 4) | | | 41 | | | | 46 | | | | 19 | |
Derivative financial instruments (Note 2 and Note 3) | | | 4 | | | | 6 | | | | 8 | |
Other long-term liabilities and other deferred credits | | | 138 | | | | 139 | | | | 142 | |
Total long-term liabilities and other deferred credits | | | 3,392 | | | | 3,043 | | | | 2,929 | |
Total liabilities and other deferred credits | | | 4,436 | | | | 5,026 | | | | 4,751 | |
Commitments and contingencies (Note 7) | | | | | | | | | | | | |
Equity | | | | | | | | | | | | |
AGL Resources Inc. common shareholders’ equity, $5 par value; 750,000,000 shares authorized | | | 1,719 | | | | 1,652 | | | | 1,724 | |
Noncontrolling interest (Note 5) | | | 28 | | | | 32 | | | | 29 | |
Total equity | | | 1,747 | | | | 1,684 | | | | 1,753 | |
Total liabilities and equity | | $ | 6,183 | | | $ | 6,710 | | | $ | 6,504 | |
See Notes to Condensed Consolidated Financial Statements (Unaudited). | | | | | |
| | | | | As of | | | | |
In millions, except share data | | June 30, 2009 | | | December 31, 2008 | | | June 30, 2008 | |
Current assets | | | | | | | | | |
Cash and cash equivalents | | $ | 12 | | | $ | 16 | | | $ | 19 | |
Inventories, net (Note 1) | | | 532 | | | | 663 | | | | 708 | |
Receivables | | | | | | | | | | | | |
Energy marketing receivables (Note 1) | | | 276 | | | | 549 | | | | 807 | |
Gas, unbilled and other receivables | | | 209 | | | | 472 | | | | 258 | |
Less allowance for uncollectible accounts | | | (19 | ) | | | (16 | ) | | | (19 | ) |
Total receivables | | | 466 | | | | 1,005 | | | | 1,046 | |
Derivative financial instruments – current portion (Note 2 and Note 3) | | | 177 | | | | 207 | | | | 107 | |
Unrecovered pipeline replacement program costs – current portion (Note 1) | | | 41 | | | | 41 | | | | 37 | |
Unrecovered environmental remediation costs – current portion (Note 1) | | | 14 | | | | 18 | | | | 20 | |
Other current assets | | | 74 | | | | 92 | | | | 106 | |
Total current assets | | | 1,316 | | | | 2,042 | | | | 2,043 | |
Long-term assets and other deferred debits | | | | | | | | | | | | |
Property, plant and equipment | | | 5,685 | | | | 5,500 | | | | 5,284 | |
Less accumulated depreciation | | | 1,729 | | | | 1,684 | | | | 1,621 | |
Property, plant and equipment-net | | | 3,956 | | | | 3,816 | | | | 3,663 | |
Goodwill | | | 418 | | | | 418 | | | | 420 | |
Unrecovered pipeline replacement program costs (Note 1) | | | 174 | | | | 196 | | | | 216 | |
Unrecovered environmental remediation costs (Note 1) | | | 146 | | | | 125 | | | | 130 | |
Derivative financial instruments (Note 2 and Note 3) | | | 37 | | | | 38 | | | | 25 | |
Other | | | 73 | | | | 75 | | | | 94 | |
Total long-term assets and other deferred debits | | | 4,804 | | | | 4,668 | | | | 4,548 | |
Total assets | | $ | 6,120 | | | $ | 6,710 | | | $ | 6,591 | |
Current liabilities | | | | | | | | | | | | |
Short-term debt (Note 6) | | $ | 418 | | | $ | 866 | | | $ | 513 | |
Energy marketing trade payables (Note 1) | | | 317 | | | | 539 | | | | 927 | |
Accounts payable - trade | | | 167 | | | | 202 | | | | 158 | |
Accrued expenses | | | 107 | | | | 113 | | | | 106 | |
Deferred natural gas costs (Note 1) | | | 52 | | | | 25 | | | | 20 | |
Accrued pipeline replacement program costs – current portion (Note 1) | | | 50 | | | | 49 | | | | 48 | |
Customer deposits | | | 48 | | | | 50 | | | | 33 | |
Derivative financial instruments – current portion (Note 2 and Note 3) | | | 36 | | | | 50 | | | | 112 | |
Accrued environmental remediation liabilities – current portion (Note 1 and Note 7) | | | 19 | | | | 17 | | | | 15 | |
Other current liabilities | | | 67 | | | | 72 | | | | 47 | |
Total current liabilities | | | 1,281 | | | | 1,983 | | | | 1,979 | |
Long-term liabilities and other deferred credits | | | | | | | | | | | | |
Long-term debt (Note 6) | | | 1,675 | | | | 1,675 | | | | 1,637 | |
Accumulated deferred income taxes | | | 609 | | | | 571 | | | | 604 | |
Accumulated removal costs (Note 1) | | | 199 | | | | 178 | | | | 175 | |
Accrued pension obligations (Note 4) | | | 187 | | | | 199 | | | | 44 | |
Accrued environmental remediation liabilities (Note 1 and Note 7) | | | 114 | | | | 89 | | | | 92 | |
Accrued pipeline replacement program costs (Note 1) | | | 113 | | | | 140 | | | | 162 | |
Accrued postretirement benefit costs (Note 4) | | | 44 | | | | 46 | | | | 21 | |
Derivative financial instruments (Note 2 and Note 3) | | | 3 | | | | 6 | | | | 13 | |
Other long-term liabilities and other deferred credits | | | 136 | | | | 139 | | | | 144 | |
Total long-term liabilities and other deferred credits | | | 3,080 | | | | 3,043 | | | | 2,892 | |
Commitments and contingencies (Note 7) | | | | | | | | | | | | |
Equity (Note 5) | | | | | | | | | | | | |
AGL Resources Inc. common shareholders’ equity, $5 par value; 750,000,000 shares authorized | | | 1,732 | | | | 1,652 | | | | 1,686 | |
Noncontrolling interest | | | 27 | | | | 32 | | | | 34 | |
Total equity | | | 1,759 | | | | 1,684 | | | | 1,720 | |
Total liabilities and equity | | $ | 6,120 | | | $ | 6,710 | | | $ | 6,591 | |
See Notes to Condensed Consolidated Financial Statements (Unaudited). | | | | | |
AGL RESOURCES INC. AND SUBSIDIARIES
(UNAUDITED)
| | Three months ended | | | Six months ended | | | Three months ended | | | Nine months ended | |
| | June 30, | | | June 30, | | | September 30, | | | September 30, | |
In millions, except per share amounts | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Operating revenues | | $ | 377 | | | $ | 444 | | | $ | 1,372 | | | $ | 1,456 | | | $ | 307 | | | $ | 539 | | | $ | 1,679 | | | $ | 1,995 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost of gas | | | 152 | | | | 275 | | | | 741 | | | | 932 | | | | 99 | | | | 261 | | | | 840 | | | | 1,193 | |
Operation and maintenance | | | 119 | | | | 114 | | | | 244 | | | | 233 | | | | 115 | | | | 104 | | | | 359 | | | | 337 | |
Depreciation and amortization | | | 39 | | | | 38 | | | | 78 | | | | 74 | | | | 40 | | | | 38 | | | | 118 | | | | 112 | |
Taxes other than income taxes | | | 12 | | | | 11 | | | | 24 | | | | 23 | | | | 10 | | | | 10 | | | | 34 | | | | 33 | |
Total operating expenses | | | 322 | | | | 438 | | | | 1,087 | | | | 1,262 | | | | 264 | | | | 413 | | | | 1,351 | | | | 1,675 | |
Operating income | | | 55 | | | | 6 | | | | 285 | | | | 194 | | | | 43 | | | | 126 | | | | 328 | | | | 320 | |
Other income | | | 3 | | | | 3 | | | | 5 | | | | 4 | | | | 2 | | | | 2 | | | | 7 | | | | 6 | |
Interest expense, net | | | (24 | ) | | | (26 | ) | | | (49 | ) | | | (56 | ) | | | (26 | ) | | | (29 | ) | | | (75 | ) | | | (85 | ) |
Earnings (loss) before income taxes | | | 34 | | | | (17 | ) | | | 241 | | | | 142 | | |
Income tax expense (benefit) | | | 13 | | | | (7 | ) | | | 85 | | | | 47 | | |
Net income (loss) | | | 21 | | | | (10 | ) | | | 156 | | | | 95 | | |
Less net income attributable to the noncontrolling interest (Note 5) | | | 1 | | | | 1 | | | | 17 | | | | 17 | | |
Net income (loss) attributable to AGL Resources Inc. | | $ | 20 | | | $ | (11 | ) | | $ | 139 | | | $ | 78 | | |
Earnings before income taxes | | | | 19 | | | | 99 | | | | 260 | | | | 241 | |
Income tax expense | | | | 7 | | | | 39 | | | | 92 | | | | 86 | |
Net income | | | | 12 | | | | 60 | | | | 168 | | | | 155 | |
Less net (loss) income attributable to the noncontrolling interest (Note 5) | | | | - | | | | (5 | ) | | | 17 | | | | 12 | |
Net income attributable to AGL Resources Inc. | | | $ | 12 | | | $ | 65 | | | $ | 151 | | | $ | 143 | |
Per common share data (Note 1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic earnings (loss) per common share attributable to AGL Resources Inc. common shareholders | | $ | 0.26 | | | $ | (0.15 | ) | | $ | 1.81 | | | $ | 1.02 | | |
Diluted earnings (loss) per common share attributable to AGL Resources Inc. common shareholders | | $ | 0.26 | | | $ | (0.15 | ) | | $ | 1.81 | | | $ | 1.01 | | |
Basic earnings per common share attributable to AGL Resources Inc. common shareholders | | | $ | 0.16 | | | $ | 0.85 | | | $ | 1.97 | | | $ | 1.87 | |
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders | | | $ | 0.16 | | | $ | 0.85 | | | $ | 1.97 | | | $ | 1.87 | |
Cash dividends declared per common share | | $ | 0.43 | | | $ | 0.42 | | | $ | 0.86 | | | $ | 0.84 | | | $ | 0.43 | | | $ | 0.42 | | | $ | 1.29 | | | $ | 1.26 | |
Weighted-average number of common shares outstanding (Note 1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | | 76.7 | | | | 76.2 | | | | 76.8 | | | | 76.2 | | | | 76.9 | | | | 76.4 | | | | 76.7 | | | | 76.2 | |
Diluted | | | 76.9 | | | | 76.2 | | | | 76.9 | | | | 76.4 | | | | 77.2 | | | | 76.6 | | | | 76.9 | | | | 76.5 | |
See Notes to Condensed Consolidated Financial Statements (Unaudited).
AGL RESOURCES INC. AND SUBSIDIARIES
(UNAUDITED)
| | AGL Resources Inc. Common Shareholders Equity | | | | | | | | | AGL Resources Inc. Common Shareholders Equity | | | | | | | |
| | Common stock | | | Premium on common | | | Earnings | | | Accumulated other comprehensive | | | Treasury | | | Noncontrolling | | | | | | Common stock | | | Premium on common | | | Earnings | | | Accumulated other comprehensive | | | Treasury | | | Noncontrolling | | | | |
In millions, except per share amounts | | Shares | | | Amount | | | stock | | | reinvested | | | loss | | | shares | | | interest | | | Total | | | Shares | | | Amount | | | stock | | | reinvested | | | loss | | | shares | | | interest | | | Total | |
Balance as of December 31, 2007 | | | 76.4 | | | $ | 390 | | | $ | 667 | | | $ | 680 | | | $ | (13 | ) | | $ | (63 | ) | | $ | 47 | | | $ | 1,708 | | | | 76.4 | | | $ | 390 | | | $ | 667 | | | $ | 680 | | | $ | (13 | ) | | $ | (63 | ) | | $ | 47 | | | $ | 1,708 | |
Net income | | | - | | | | - | | | | - | | | | 78 | | | | - | | | | - | | | | 17 | | | | 95 | | | | - | | | | - | | | | - | | | | 143 | | | | - | | | | - | | | | 12 | | | | 155 | |
Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | (1 | ) | | | - | | | | - | | | | (1 | ) | | | - | | | | - | | | | - | | | | - | | | | (1 | ) | | | - | | | | - | | | | (1 | ) |
Dividends on common stock ($0.84 per share) | | | - | | | | - | | | | - | | | | (64 | ) | | | - | | | | - | | | | - | | | | (64 | ) | |
Dividends on common stock ($1.26 per share) | | | | - | | | | - | | | | - | | | | (96 | ) | | | - | | | | 3 | | | | - | | | | (93 | ) |
Distributions to noncontrolling interest | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (30 | ) | | | (30 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (30 | ) | | | (30 | ) |
Issuance of treasury shares | | | 0.3 | | | | - | | | | - | | | | (3 | ) | | | - | | | | 11 | | | | - | | | | 8 | | | | 0.4 | | | | - | | | | (1 | ) | | | (4 | ) | | | - | | | | 12 | | | | - | | | | 7 | |
Stock-based compensation expense (net of taxes) (Note 5) | | | - | | | | - | | | | 4 | | | | - | | | | - | | | | - | | | | - | | | | 4 | | |
Balance as of June 30, 2008 | | | 76.7 | | | $ | 390 | | | $ | 671 | | | $ | 691 | | | $ | (14 | ) | | $ | (52 | ) | | $ | 34 | | | $ | 1,720 | | |
Stock-based compensation expense (net of taxes) (Note 1) | | | | - | | | | - | | | | 7 | | | | - | | | | - | | | | - | | | | - | | | | 7 | |
Balance as of September 30, 2008 | | | | 76.8 | | | $ | 390 | | | $ | 673 | | | $ | 723 | | | $ | (14 | ) | | $ | (48 | ) | | $ | 29 | | | $ | 1,753 | |
| | AGL Resources Inc. Common Shareholders Equity | | | | | | | | | AGL Resources Inc. Common Shareholders Equity | | | | | | | |
| | Common stock | | | Premium on common | | | Earnings | | | Accumulated other comprehensive | | | Treasury | | | Noncontrolling | | | | | | Common stock | | | Premium on common | | | Earnings | | | Accumulated other comprehensive | | | Treasury | | | Noncontrolling | | | | |
In millions, except per share amounts | | Shares | | | Amount | | | stock | | | reinvested | | | loss | | | shares | | | interest | | | Total | | | Shares | | | Amount | | | stock | | | reinvested | | | loss | | | shares | | | interest | | | Total | |
Balance as of December 31, 2008 | | | 76.9 | | | $ | 390 | | | $ | 676 | | | $ | 763 | | | $ | (134 | ) | | $ | (43 | ) | | $ | 32 | | | $ | 1,684 | | | | 76.9 | | | $ | 390 | | | $ | 676 | | | $ | 763 | | | $ | (134 | ) | | $ | (43 | ) | | $ | 32 | | | $ | 1,684 | |
Net income | | | - | | | | - | | | | - | | | | 139 | | | | - | | | | - | | | | 17 | | | | 156 | | | | - | | | | - | | | | - | | | | 151 | | | | - | | | | - | | | | 17 | | | | 168 | |
Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | (3 | ) | | | - | | | | (2 | ) | | | (5 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (1 | ) | | | (1 | ) |
Dividends on common stock ($0.86 per share) | | | - | | | | - | | | | - | | | | (66 | ) | | | - | | | | (2 | ) | | | - | | | | (68 | ) | |
Dividends on common stock ($1.29 per share) | | | | - | | | | - | | | | - | | | | (99 | ) | | | - | | | | 3 | | | | - | | | | (96 | ) |
Distributions to noncontrolling interest | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (20 | ) | | | (20 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (20 | ) | | | (20 | ) |
Issuance of treasury shares | | | 0.4 | | | | - | | | | (6 | ) | | | (3 | ) | | | - | | | | 17 | | | | - | | | | 8 | | | | 0.5 | | | | - | | | | (6 | ) | | | (4 | ) | | | - | | | | 16 | | | | - | | | | 6 | |
Stock-based compensation expense (net of taxes) (Note 5) | | | - | | | | - | | | | 4 | | | | - | | | | - | | | | - | | | | - | | | | 4 | | |
Balance as of June 30, 2009 | | | 77.3 | | | $ | 390 | | | $ | 674 | | | $ | 833 | | | $ | (137 | ) | | $ | (28 | ) | | $ | 27 | | | $ | 1,759 | | |
Stock-based compensation expense (net of taxes) (Note 1) | | | | - | | | | - | | | | 6 | | | | - | | | | - | | | | - | | | | - | | | | 6 | |
Balance as of September 30, 2009 | | | | 77.4 | | | $ | 390 | | | $ | 676 | | | $ | 811 | | | $ | (134 | ) | | $ | (24 | ) | | $ | 28 | | | $ | 1,747 | |
See Notes to Condensed Consolidated Financial Statements (Unaudited). |
AGL RESOURCES INC. AND SUBSIDIARIES
(UNAUDITED)
| | Three months ended | | | Six months ended | | | Three months ended | | | Nine months ended | |
| | June 30, | | | June 30, | | | September 30, | | | September 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Comprehensive income (loss) attributable to AGL Resources Inc. (net of tax) | | | | | | | | | | | | | |
Net income (loss) attributable to AGL Resources Inc. | | $ | 20 | | | $ | (11 | ) | | $ | 139 | | | $ | 78 | | |
Comprehensive income attributable to AGL Resources Inc. (net of tax) | | | | | | | | | | | | | |
Net income attributable to AGL Resources Inc. | | | $ | 12 | | | $ | 65 | | | $ | 151 | | | $ | 143 | |
Cash flow hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Derivative financial instruments unrealized (losses) gains arising during the period | | | (1 | ) | | | 2 | | | | (11 | ) | | | 4 | | | | (1 | ) | | | (1 | ) | | | (12 | ) | | | 3 | |
Reclassification of derivative financial instruments realized losses (gains) included in net income | | | 6 | | | | (1 | ) | | | 8 | | | | (5 | ) | | | 4 | | | | 1 | | | | 12 | | | | (4 | ) |
Other comprehensive income (loss) | | | 5 | | | | 1 | | | | (3 | ) | | | (1 | ) | | | 3 | | | | - | | | | - | | | | (1 | ) |
Comprehensive income (loss) (Note 5) | | $ | 25 | | | $ | (10 | ) | | $ | 136 | | | $ | 77 | | |
Comprehensive income (Note 1) | | | $ | 15 | | | $ | 65 | | | $ | 151 | | | $ | 142 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Comprehensive income attributable to noncontrolling interest (net of tax) | | | | | | | | | | | | | | | | | |
Net income attributable to noncontrolling interest | | $ | 1 | | | $ | 1 | | | $ | 17 | | | $ | 17 | | |
Comprehensive income (loss) attributable to noncontrolling interest (net of tax) | | | | | | | | | | | | | | | | | |
Net income (loss) attributable to noncontrolling interest | | | $ | - | | | $ | (5 | ) | | $ | 17 | | | $ | 12 | |
Cash flow hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Derivative financial instruments unrealized (losses) gains arising during the period | | | (1 | ) | | | 1 | | | | (6 | ) | | | 2 | | | | - | | | | 1 | | | | (6 | ) | | | 3 | |
Reclassification of derivative financial instruments realized losses (gains) included in net income | | | 3 | | | | (1 | ) | | | 4 | | | | (2 | ) | | | 1 | | | | (1 | ) | | | 5 | | | | (3 | ) |
Other comprehensive income (loss) | | | 2 | | | | - | | | | (2 | ) | | | - | | | | 1 | | | | - | | | | (1 | ) | | | - | |
Comprehensive income (Note 5) | | $ | 3 | | | $ | 1 | | | $ | 15 | | | $ | 17 | | |
Comprehensive income (loss) (Note 1) | | | $ | 1 | | | $ | (5 | ) | | $ | 16 | | | $ | 12 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income (loss), including portion attributable to noncontrolling interest (net of tax) | | | | | | | | | | | | | | | | | |
Net income (loss) | | $ | 21 | | | $ | (10 | ) | | $ | 156 | | | $ | 95 | | |
Total comprehensive income (net of tax) | | | | | | | | | | | | | | | | | |
Net income | | | $ | 12 | | | $ | 60 | | | $ | 168 | | | $ | 155 | |
Cash flow hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Derivative financial instruments unrealized (losses) gains arising during the period | | | (2 | ) | | | 3 | | | | (17 | ) | | | 6 | | | | (1 | ) | | | - | | | | (18 | ) | | | 6 | |
Reclassification of derivative financial instruments realized losses (gains) included in net income | | | 9 | | | | (2 | ) | | | 12 | | | | (7 | ) | | | 5 | | | | - | | | | 17 | | | | (7 | ) |
Other comprehensive income (loss) | | | 7 | | | | 1 | | | | (5 | ) | | | (1 | ) | | | 4 | | | | - | | | | (1 | ) | | | (1 | ) |
Comprehensive income (loss) (Note 5) | | $ | 28 | | | $ | (9 | ) | | $ | 151 | | | $ | 94 | | |
Comprehensive income (Note 1) | | | $ | 16 | | | $ | 60 | | | $ | 167 | | | $ | 154 | |
See Notes to Condensed Consolidated Financial Statements (Unaudited).
AGL RESOURCES INC. AND SUBSIDIARIES
(UNAUDITED)
| | | | | | | | | | | | |
| | Six months ended | | | Nine months ended | |
| | June 30, | | | September 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Cash flows from operating activities | | | | | | | | | | | | |
Net income | | $ | 156 | | | $ | 95 | | | $ | 168 | | | $ | 155 | |
Adjustments to reconcile net income to net cash flow provided by operating activities | | | | | | | | | | | | | | | | |
Depreciation and amortization | | | 78 | | | | 74 | | | | 118 | | | | 112 | |
Deferred income taxes | | | 29 | | | | (34 | ) | | | 62 | | | | 66 | |
Change in derivative financial instrument assets and liabilities | | | 14 | | | | 51 | | | | 43 | | | | (86 | ) |
Changes in certain assets and liabilities | | | | | | | | | | | | | | | | |
Gas, unbilled and other receivables | | | 266 | | | | 152 | | | | 327 | | | | 202 | |
Energy marketing receivables and energy marketing trade payables, net | | | | 39 | | | | 53 | |
Inventories | | | 131 | | | | (157 | ) | | | 12 | | | | (260 | ) |
Energy marketing receivables and energy marketing trade payables, net | | | 51 | | | | 140 | | |
Accrued expenses | | | (6 | ) | | | 19 | | |
Gas and trade payables | | | (35 | ) | | | (14 | ) | | | (47 | ) | | | 9 | |
Other – net | | | 47 | | | | 33 | | | | (36 | ) | | | (79 | ) |
Net cash flow provided by operating activities | | | 731 | | | | 359 | | | | 686 | | | | 172 | |
Cash flows from investing activities | | | | | | | | | | | | | | | | |
Payments to acquire, property, plant and equipment | | | (207 | ) | | | (166 | ) | | | (314 | ) | | | (254 | ) |
Net cash flow used in investing activities | | | (207 | ) | | | (166 | ) | | | (314 | ) | | | (254 | ) |
Cash flows from financing activities | | | | | | | | | | | | | | | | |
Issuance of senior notes | | | | 300 | | | | - | |
Net payments and borrowings of short-term debt | | | (448 | ) | | | (67 | ) | | | (556 | ) | | | 189 | |
Dividends paid on common shares | | | (68 | ) | | | (64 | ) | | | (96 | ) | | | (93 | ) |
Distribution to noncontrolling interest | | | (20 | ) | | | (30 | ) | | | (20 | ) | | | (30 | ) |
Issuance of treasury shares | | | 8 | | | | 8 | | |
Payments of long-term debt | | | - | | | | (161 | ) | | | - | | | | (161 | ) |
Issuance of variable rate gas facility revenue bonds | | | - | | | | 122 | | | | - | | | | 161 | |
Other | | | - | | | | (1 | ) | |
Net cash flow used in financing activities | | | (528 | ) | | | (193 | ) | |
Net decrease in cash and cash equivalents | | | (4 | ) | | | - | | |
Issuance of treasury shares and other | | | | 5 | | | | 8 | |
Net cash flow (used in) provided by financing activities | | | | (367 | ) | | | 74 | |
Net increase (decrease) in cash and cash equivalents | | | | 5 | | | | (8 | ) |
Cash and cash equivalents at beginning of period | | | 16 | | | | 19 | | | | 16 | | | | 19 | |
Cash and cash equivalents at end of period | | $ | 12 | | | $ | 19 | | | $ | 21 | | | $ | 11 | |
Cash paid during the period for | | | | | | | | | | | | | | | | |
Interest | | $ | 47 | | | $ | 59 | | | $ | 74 | | | $ | 88 | |
Income taxes | | $ | 35 | | | $ | 24 | | | $ | 50 | | | $ | 27 | |
See Notes to Condensed Consolidated Financial Statements (Unaudited).
STATEMENTS (UNAUDITED)
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” mean consolidated AGL Resources Inc. and its subsidiaries (AGL Resources).
The year-end condensed statement of financial position data was derived from our audited financial statements, but does not include all disclosures required by GAAP. We have prepared the accompanying unaudited condensed consolidated financial statements under the rules of the SEC. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with GAAP. However, the condensed consolidated financial statements reflect all adjustments of a normal recurring nature that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods. For a glossary of key terms, and referenced accounting standards, see page 3. You should read these condensed consolidated financial statements in conjunction with our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.
Due to the seasonal nature of our business, our results of operations for the three and sixnine months ended JuneSeptember 30, 2009 and 2008, and our financial condition as of December 31, 2008, and JuneSeptember 30, 2009 and 2008, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.
Basis of Presentation
Our condensed consolidated financial statements 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 our subsidiaries’ accounts. We have eliminated any intercompany profits and transactions in consolidation; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process. Certain amounts from prior periods have been reclassified and revised to conform to the current period presentation.
Use of Accounting Estimates
The preparation of our financial statements in conformity with GAAP 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, and we evaluate our estimates on an ongoing basis. Each of our estimates involves complex situations requiring a high degree of judgment either in the application and interpretation of existing financial accounting literature or in the development of estimates that impact our financial statements. The most significant estimates include our PRP accruals, environmentalERC liability accruals, allowance for uncollectible accounts, and other allowance for contingencies, pension and postretirement obligations, derivative and hedging activities, unbilled revenues and provision for income taxes. Our actual results could differ from our estimates, and such differences could be material.
Energy Marketing Receivables and Payables
Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements, which enable wholesale services to net receivables and payables by counterparty. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. The amounts due from or owed to wholesale services’ counterparties are netted and recorded on our condensed consolidated statements of financial position as energy marketing receivables and energy marketing payables.
Our wholesale services segment has some trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. No collateral has been posted under such provisions since our credit ratings have always exceeded the minimum requirements. As of JuneSeptember 30, 2009, December 31, 2008 and JuneSeptember 30, 2008, the collateral that wholesale services would behave been required to post would not have had a material impact to our consolidated results of operations, cash flows or financial condition. However, if such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be impaired.
Regulatory Assets and Liabilities
We have recorded regulatory assets and liabilities in our condensed consolidated statements of financial position in accordance with SFAS 71. Ourauthoritative guidance related to regulated operations. These regulatory assets and liabilities, and associated liabilities for our unrecovered PRP costs, unrecovered ERC andalong with the associated assets and liabilities, for Elizabethtown Gas’ derivative financial instruments, are summarized in the following table. For more information on our derivative financial instruments, see Note 3.
| | June 30 | | | Dec. 31 | | | June 30 |
In millions | | 2009 | | | 2008 | | | 2008 |
Regulatory assets | | | | | | | | |
Unrecovered PRP costs | | $ | 215 | | | $ | 237 | | | $ | 253 | |
Unrecovered ERC | | | 160 | | | | 143 | | | | 150 | |
Unrecovered postretirement benefit costs | | | 10 | | | | 11 | | | | 11 | |
Unrecovered seasonal rates | | | - | | | | 11 | | | | - | |
Unrecovered natural gas costs | | | - | | | | 19 | | | | 22 | |
Elizabethtown Gas derivative financial instruments | | | - | | | | - | | | | 35 | |
Other | | | 28 | | | | 30 | | | | 28 | |
Total regulatory assets | | | 413 | | | | 451 | | | | 499 | |
Associated assets | | | | | | | | | | | | |
Elizabethtown Gas derivative financial instruments | | | 21 | | | | 23 | | | | - | |
Total regulatory and associated assets | | $ | 434 | | | $ | 474 | | | $ | 499 | |
Regulatory liabilities | | | | | | | | | | | | |
Accumulated removal costs | | $ | 199 | | | $ | 178 | | | $ | 175 | |
Deferred natural gas costs | | | 52 | | | | 25 | | | | 20 | |
Elizabethtown Gas derivative financial instruments | | | 21 | | | | 23 | | | | - | |
Deferred seasonal rates | | | 9 | | | | - | | | | 9 | |
Regulatory tax liability | | | 18 | | | | 19 | | | | 19 | |
Unamortized investment tax credit | | | 14 | | | | 14 | | | | 15 | |
Other | | | 17 | | | | 22 | | | | 20 | |
Total regulatory liabilities | | | 330 | | | | 281 | | | | 258 | |
Associated liabilities | | | | | | | | | | | | |
PRP costs | | | 163 | | | | 189 | | | | 210 | |
ERC | | | 120 | | | | 96 | | | | 97 | |
Elizabethtown Gas derivative financial instruments | | | - | | | | - | | | | 35 | |
Total associated liabilities | | | 283 | | | | 285 | | | | 342 | |
Total regulatory and associated liabilities | | $ | 613 | | | $ | 566 | | | $ | 600 | |
| | Sept. 30 | | | Dec. 31 | | | Sept. 30 |
In millions | | 2009 | | | 2008 | | | 2008 |
Regulatory assets | | | | | | | | |
Unrecovered PRP costs | | $ | 209 | | | $ | 237 | | | $ | 242 | |
Unrecovered ERC | | | 155 | | | | 143 | | | | 144 | |
Unrecovered postretirement benefit costs | | | 10 | | | | 11 | | | | 11 | |
Unrecovered seasonal rates | | | 10 | | | | 11 | | | | 10 | |
Unrecovered natural gas costs | | | - | | | | 19 | | | | 33 | |
Other | | | 27 | | | | 30 | | | | 31 | |
Total regulatory assets | | | 411 | | | | 451 | | | | 471 | |
Associated assets | | | | | | | | | | | | |
Derivative financial instruments | | | 13 | | | | 23 | | | | 15 | |
Total regulatory and associated assets | | $ | 424 | | | $ | 474 | | | $ | 486 | |
Regulatory liabilities | | | | | | | | | | | | |
Accumulated removal costs (1) | | $ | 194 | | | $ | 178 | | | $ | 176 | |
Deferred natural gas costs | | | 26 | | | | 25 | | | | 14 | |
Derivative financial instruments | | | 13 | | | | 23 | | | | 15 | |
Regulatory tax liability | | | 17 | | | | 19 | | | | 19 | |
Unamortized investment tax credit | | | 13 | | | | 14 | | | | 15 | |
Other | | | 18 | | | | 22 | | | | 21 | |
Total regulatory liabilities | | | 281 | | | | 281 | | | | 260 | |
Associated liabilities | | | | | | | | | | | | |
PRP costs | | | 155 | | | | 189 | | | | 195 | |
ERC | | | 118 | | | | 96 | | | | 95 | |
Total associated liabilities | | | 273 | | | | 285 | | | | 290 | |
Total regulatory and associated liabilities | | $ | 554 | | | $ | 566 | | | $ | 550 | |
(1) | Increase for 2009 primarily due to Virginia Natural Gas rate change based on most recently approved depreciation study. |
There have been no significant changes to our regulatory assets and liabilities as described in Note 1 to our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009. For more information on our derivative financial instruments, see Note 3.
Inventories
For our distribution operations segment, we record natural gas stored underground at the WACOG. For Sequent and SouthStar, we account for natural gas inventory at the lower of WACOG or market price.
Sequent and SouthStar evaluate the average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, we record adjustments to reduce the weighted average cost of the natural gas inventory to market price. SouthStar and Sequent did not record LOCOM adjustments in the three months ended September 30, 2009. SouthStar recorded LOCOM adjustments of $6 million in the sixnine months ended JuneSeptember 30, 2009 and did not record LOCOM adjustments$18 million in the sixthree and nine months ended JuneSeptember 30, 2008. Sequent recorded LOCOM adjustments of $8 million in the sixnine months ended JuneSeptember 30, 2009 and did not record LOCOM adjustments$34 million for the sixthree and nine months ended JuneSeptember 30, 2008.
Earnings per Common Share
We compute basic earnings per common share by dividing our net income attributable to our common shareholders by the daily weighted-average number of common shares outstanding. 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 adopted FSP EITF 03-6-1new authoritative guidance related to earnings per share on January 1, 2009, which provides2009. The effect of the guidance on the computation of earnings per share for unvested share awards outstanding that have the nonforfeitable right to receive dividends. The effects of this FSP weredividends was immaterial to our calculation of earnings per share.
We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options. The future issuance of shares underlying the restricted stock and restricted stock units depends on the satisfaction of certain performance criteria. The future issuance of shares underlying the outstanding stock options depends upon whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. The following table shows the calculation of our diluted shares for the periods presented, assuming restricted stock and restricted stock units currently awarded under the plan ultimately vest and stock options currently exercisable at prices below the average market prices are exercised.
| | Three months ended September 30, | |
In millions | | 2009 | | | 2008 | |
Denominator for basic earnings per share (1) | | | 76.9 | | | | 76.4 | |
Assumed exercise of restricted stock, restricted stock units and stock options | | | 0.3 | | | | 0.2 | |
Denominator for diluted earnings per share | | | 77.2 | | | | 76.6 | |
(1) Daily weighted-average shares outstanding. | |
| | Three months ended June 30, | | | Nine months ended September 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Denominator for basic earnings per share (1) | | | 76.7 | | | | 76.2 | | | | 76.7 | | | | 76.2 | |
Assumed exercise of restricted stock, restricted stock units and stock options | | | 0.2 | | | | - | | | | 0.2 | | | | 0.3 | |
Denominator for diluted earnings per share | | | 76.9 | | | | 76.2 | | | | 76.9 | | | | 76.5 | |
(1) Daily weighted-average shares outstanding. | (1) Daily weighted-average shares outstanding. | | (1) Daily weighted-average shares outstanding. | |
| | Six months ended June 30, | |
In millions | | 2009 | | | 2008 | |
Denominator for basic earnings per share (1) | | | 76.8 | | | | 76.2 | |
Assumed exercise of restricted stock, restricted stock units and stock options | | | 0.1 | | | | 0.2 | |
Denominator for diluted earnings per share | | | 76.9 | | | | 76.4 | |
(1) Daily weighted-average shares outstanding. | |
The following table contains the weighted average shares attributable to outstanding stock options that were excluded from the computation of diluted earnings per share because their effect would have been anti-dilutive, as the exercise prices were greater than the average market price:
| | June 30, | | | September 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Three months ended | | | 2.3 | | | | 1.7 | | | | 1.6 | | | | 2.1 | |
Six months ended | | | 2.2 | | | | 1.6 | | |
Nine months ended | | | | 2.2 | | | | 1.6 | |
| | | |
The increasedecrease of 0.60.5 million in anti-dilutive shares for the three and six months ended JuneSeptember 30, 2009, which were excluded from the computation of diluted earnings per share and considered anti-dilutive, was primarily a result of a decline in thehigher average market value of our common shares at Junecompared to the same period of 2008. The increase of 0.6 million in anti-dilutive shares for the nine months ended September 30, 2009, asis primarily a result of a lower average market value of our common shares compared to the same period of 2008.
Stock-Based Compensation
In the first nine months of 2009, we issued grants of approximately 250,000 stock options and 211,000 restricted stock units, which will result in the recognition of approximately $2 million of stock-based compensation expense in 2009. No material share awards have been granted to employees whose compensation is subject to capitalization. We use the Black-Scholes option pricing model to determine the fair value of the options granted. On an annual basis, we evaluate the assumptions and estimates used to calculate our stock-based compensation expense.
There have been no significant changes to our stock-based compensation, as described in Note 4 to our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.
Comprehensive Income
Our comprehensive income or loss includes net income plus OCI, which includes other gains and losses affecting equity that GAAP excludes from net income. Such items consist primarily of gains and losses on certain derivatives designated as cash flow hedges and unfunded or overfunded pension and postretirement obligation adjustments. Our cumulative comprehensive income or loss that has been excluded from net income is reported as accumulated other comprehensive loss within our condensed consolidated statement of equity.
Subsequent Events
In May 2009, the FASB issued authoritative guidance related to subsequent events, which is effective for reporting periods ending after June 30, 2008.15, 2009. The FASB establishes guidance for and disclosure of events that occur after the statement of financial position date, but before financial statements are issued, or are available to be issued. Prior guidance relating to subsequent events was primarily directed toward auditors, not management. However, the guidance should now be applied by management to the accounting for and disclosure of subsequent events, but does not apply to subsequent events or transactions that are within the scope of other applicable GAAP that provide different guidance. In accordance with the guidance, we evaluated subsequent events until the time that our financial statements were issued and filed with the SEC on October 29, 2009.
Accounting Developments
Recently issued
SFAS 166In June 2009, the FASB issued SFAS 166, which amends FAS 140-4, and requires improved disclosures about transfers of financial assets and removes the exception from applying FIN 46(R) to qualifying special purpose entities. SFAS 166 will be effective for us on January 1, 2010 and will have no effect on our consolidated results of operations, cash flows and financial position.
SFAS 167 In June 2009, the FASB issued SFAS 167, which provides new consolidationauthoritative guidance, for variable interest entities (VIE). SFAS 167 requires a company to assess the determination of the primary beneficiary of a VIE based on whether the company has the power to direct matters that most significantly impact the activities of the VIE, and the obligation to absorb losses or the right to receive benefits of the VIE. In addition, SFAS 167 requires ongoing reassessments of whether a company is the primary beneficiary of a VIE.
SFAS 167 will be effective for us beginning January 1, 2010. Earlier application is prohibited. We are currently evaluating the impact of this standard on our consolidated results of operations, cash flows and financial position.
SFAS 168 In June 2009, the FASB issued SFAS 168, which replaces SFAS 162the previous authoritative hierarchy aspect of GAAP. SFAS 168The guidance creates a two-level GAAP hierarchy - authoritative and non-authoritative - and establishes the FASB’s Accounting Standards Codification (Codification)guidance as the sole source of authoritative GAAP guidance for non-governmental entities, except for rules and releases by the SEC.
After July 1, 2009, all non-grandfathered, non-SEC accounting guidance not included in the Codificationauthoritative guidance is superseded and is deemed non-authoritative. SFAS 168The guidance is effective for financial statements issued for interim and annual periods ending after September 15, 2009. SFAS 168 will haveWe adopted the guidance on September 30, 2009, which had no impact on our condensed consolidated results of operations, cash flows andor financial position.
The carrying value of cash and cash equivalents, receivables, accounts payable, short-term debt, other current assets and liabilities, derivative financial instrument assets, derivative financial instrument liabilities and accrued interest approximate fair value. The following table shows the carrying amounts and fair values of our long-term debt including any current portions included in our condensed consolidated statements of financial position.
In millions | | Carrying amount | | | Estimated fair value | |
As of June 30, 2009 | | $ | 1,676 | | | $ | 1,725 | |
As of December 31, 2008 | | | 1,676 | | | | 1,647 | |
As of June 30, 2008 | | | 1,638 | | | | 1,635 | |
We estimate theNew authoritative guidance related to fair value of our long-term debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionalitymeasurements and risk profile. In determining the market interest yield curve, we considered our currently assigned ratings for unsecured debt of BBB+ by S&P, Baa1 by Moody’s and A- by Fitch.
SFAS 157disclosures was effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In December 2007, the FASB provided a one-year deferral of SFAS 157the guidance for nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value on a recurring basis, at least annually. We adopted SFAS 157this guidance on January 1, 2008, for our financial assets and liabilities, which primarily consist of derivatives we record in accordance with SFAS 133.the guidance related to derivatives and hedging. We adopted SFAS 157the guidance for our nonfinancial assets and liabilities on January 1, 2009, which had no impact to our condensed consolidated results of operations, cash flows andor financial condition.
FSP FAS 157-4In August 2009, the FASB updated this guidance to provide clarity on the methodologies and disclosures for fair value measurement estimates of liabilities that do not have a quoted price in an active market, level 3 liabilities (refer to Level 3 discussion contained in this Note). Any revisions due to a change in valuation technique, or its application, are to be accounted for as a change in accounting method. Disclosure is required for any change in valuation technique or related inputs resulting from the application of this update and the total effect would need to be quantified, if practicable. This FSP establishesupdate is effective for reporting periods ending after September 15, 2009, and had no financial impact to our condensed consolidated results of operations, cash flows or financial position.
Additional new authoritative guidance related to fair value measurements and disclosures established a two-step process to determine if the market for a financial asset is inactive and a transaction is not distressed. Step 1 provides factors that include, but are not limited to: transaction frequency, varying price quotations, index correlation, liquidity risk premiums, price spread increases and availability of public information. If a company determines the market is inactive, Step 2 must be applied.
In Step 2 an entity must presume that a quoted price is associated with a distressed transaction unless there was sufficient time before the measurement date to allow for usual and customary marketing activities, including multiple bidders. This FSPguidance is effective for interim and annual periods ending after June 15, 2009. We adopted this FSPguidance in the second quarter of 2009. Currently, this FSPguidance does not effectaffect us, as our financial assets are traded in active markets.
Level 1
Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 items consist of financial instruments with exchange-traded derivatives.
Level 2
Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the market place. As we aggregate our disclosures by counterparty, the underlying transactions for a given counterparty may be a combination of exchange-traded derivatives and values based on other sources. Instruments in this category include shorter tenor exchange-traded and non-exchange-traded derivatives such as OTC forwards and options.
Level 3
Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. We do not have any material assets or liabilities classified as level 3.
The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of JuneSeptember 30, 2009. As required by SFAS 157,the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
Our exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within level 1. Some exchange-traded derivatives are valued using broker or dealer quotation services, or market transactions in either the listed or OTC markets, which are classified within level 2.
The determination of the fair values in the following table incorporates various factors required under SFAS 157.the authoritative guidance related to fair value measurements and disclosures. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the effect of our nonperformance risk on our liabilities. For more information on our derivative financial instruments, see Note 3.
| | Recurring fair values Natural gas derivative financial instruments | |
| | September 30, 2009 | | | December 31, 2008 | | | September 30, 2008 | |
In millions | | Assets (1) | | | Liabilities | | | Assets (1) | | | Liabilities | | | Assets (1) | | | Liabilities | |
Quoted prices in active markets (Level 1) | | $ | 41 | | | $ | (78 | ) | | $ | 52 | | | $ | (117 | ) | | $ | 59 | | | $ | (32 | ) |
Significant other observable inputs (Level 2) | | | 115 | | | | (17 | ) | | | 154 | | | | (28 | ) | | | 102 | | | | (36 | ) |
Netting of cash collateral | | | 18 | | | | 64 | | | | 35 | | | | 89 | | | | 26 | | | | 26 | |
Total carrying value (2) | | $ | 174 | | | $ | (31 | ) | | $ | 241 | | | $ | (56 | ) | | $ | 187 | | | $ | (42 | ) |
Glossary(1) | $3 million premium at September 30, 2009, $4 million at December 31, 2008 and $1 million at September 30, 2008 associated with weather derivatives have been excluded as they are based on intrinsic value, not fair value. For more information see Note 3. |
(2) | There were no significant unobservable inputs (level 3) for any of the periods presented. |
| | Recurring fair values Natural gas derivative financial instruments | |
| | June 30, 2009 | | | December 31, 2008 | | | June 30, 2008 | |
In millions | | Assets | | | Liabilities | | | Assets (1) | | | Liabilities | | | Assets | | | Liabilities | |
Quoted prices in active markets (Level 1) | | $ | 34 | | | $ | (105 | ) | | $ | 52 | | | $ | (117 | ) | | $ | 28 | | | $ | (84 | ) |
Significant other observable inputs (Level 2) | | | 140 | | | | (18 | ) | | | 154 | | | | (28 | ) | | | 86 | | | | (118 | ) |
Netting of cash collateral | | | 40 | | | | 84 | | | | 35 | | | | 89 | | | | 18 | | | | 77 | |
Total carrying value (2) | | $ | 214 | | | $ | (39 | ) | | $ | 241 | | | $ | (56 | ) | | $ | 132 | | | $ | (125 | ) |
(1) $4 million premium associated with weather derivatives has been excluded as they are based on intrinsic value, not fair value. For more information see Note 3. (2) There were no significant unobservable inputs (level 3) for any of the periods presented. | |
Netting of Cash Collateral with Derivative Financial Instruments under Master Netting Arrangements
We maintain accounts with exchange brokers to facilitate financial derivative transactions in support of our energy marketing and risk management activities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts. We are required to offset this cash collateral with the associated fair value of the derivative financial instruments. Our cash collateral amounts are provided in the following table.
| | | | | As of | | | | | | | | | As of | | | | |
In millions | | June 30, 2009 | | | Dec. 31, 2008 | | | June 30, 2008 | | | Sept. 30, 2009 | | | Dec. 31, 2008 | | | Sept. 30, 2008 | |
Right to reclaim cash collateral | | $ | 124 | | | $ | 128 | | | $ | 103 | | | $ | 82 | | | $ | 128 | | | $ | 53 | |
Obligations to return cash collateral | | | - | | | | (4 | ) | | | (8 | ) | | | - | | | | (4 | ) | | | (1 | ) |
Total cash collateral | | $ | 124 | | | $ | 124 | | | $ | 95 | | | $ | 82 | | | $ | 124 | | | $ | 52 | |
Derivative Financial Instruments
Our risk management activities are monitored by our Risk Management Committee, which consists of members of senior management and is charged with reviewing and enforcing our risk management activities and policies. Our use of derivative financial instruments and physical transactions is limited to predefined risk tolerances associated with pre-existing or anticipated physical natural gas sales and purchases and system use and storage. We use the following types of derivative financial instruments and physical transactions to manage natural gas price, interest rate, weather, automobile fuel price and foreign currency risks:
· | weather derivative contracts |
· | storage and transportation capacity transactions |
· | foreign currency forward contracts |
Our derivative financial instruments do not contain any material credit-risk-related or other contingent features that could cause us to make acceleratedincrease the payments over and abovefor collateral we post in the normal course of business when our financial instruments are in net liability positions. For information on our energy marketing receivables and payables, which do have credit-risk-related or other contingent features, refer to Note 1. Our risk management activitiesderivatives are monitored by our Risk Management Committee, which consistsincluded within operating cash flows as a source of memberscash totaling $43 million in 2009 and a use of senior management and is charged with reviewing and enforcing our risk management activities and policies.cash totaling $86 million in 2008.
We adopted SFAS 161the new authoritative accounting guidance related to derivatives and hedging on January 1, 2009, which amends the disclosure requirements of SFAS 133 and requires specific disclosures regarding how and why we use derivative instruments; the accounting for derivative instruments and related hedged items; and how derivative instruments and related hedged items affect our financial position, results of operations and cash flows. As SFAS 161this guidance only requires additional disclosures concerning derivatives and hedging activities, this standardit did not have an impact on our condensed consolidated financial position, results of operations or cash flows.
We adopted FSP FAS 133-1 on January 1, 2009. This FSPAdditional new accounting guidance related to derivatives and hedging requires more detailed disclosures about credit derivatives, including the potential adverse effects of changes in credit risk on the financial position, financial performance and cash flows of the sellers of the instruments. This FSPauthoritative guidance had no financial impact to our condensed consolidated results of operations, cash flows or financial condition.
Natural Gas Derivative Financial Instruments
Activities associated withThe fair value of natural gas price risk management activities and derivative financial instruments are included as a component of cash flowswe use to manage exposures arising from operating activities in our condensed consolidated statements of cash flows. Our derivatives not designated as hedges under SFAS 133, are included within operating cash flows as a source of cash totaling $14 million in 2009changing natural gas prices 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 $51 million in 2008.indices to value substantially all the derivative financial instruments we use.
Distribution Operations In accordance with a directive from the New Jersey Commission,BPU, Elizabethtown Gas enters into derivative financial instruments to hedge the impact of market fluctuations in natural gas prices. Pursuant to SFAS 133,the authoritative guidance related to derivatives and hedging, such derivative transactions are accounted for at fair value each reporting period in our condensed consolidated statements of financial position. In accordance with regulatory requirements realized gains and losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. However, these derivative financial instruments are not designated as hedges in accordance with SFAS 133.the guidance. For more information on our regulatory assets and liabilities see Note 1.
Retail Energy Operations SouthStar uses natural gas derivative financial instruments (futures, options and swaps) to manage exposures arising from changing natural gas prices. SouthStar’s objective for holding these derivatives is to utilize the most effective method to reduce or eliminate the impact of this exposure. 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 derivative financial instruments we use. We have designated a portion of SouthStar’s derivative financial instruments, consisting of financial swaps to manage the natural gas risk associated with forecasted natural gas purchases and sales, of natural gas, as cash flow hedges under SFAS 133.the authoritative guidance related to derivatives and hedging. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period as the settlement of the underlying hedged item.
SouthStar currently has minimal hedge ineffectiveness defined as when the gains or losses on the hedging instrument do not offset and are greater than the losses or gains on the hedged item. This cash flow hedge ineffectiveness is recorded in cost of gas in our condensed consolidated statements of income in the period in which it occurs. We have not designated the remainder of SouthStar’s derivative financial instruments as hedges under SFAS 133the authoritative guidance related to derivatives and hedging and, accordingly, we record changes in their fair value within cost of gas in our condensed consolidated statements of income in the period of change. For more information on SouthStar’s gains and losses reported within comprehensive income that affectsaffect equity, see our condensed consolidated statements of comprehensive income.income (loss). SouthStar has hedged its exposures to natural gas price risk to varying degrees in the markets in which it serves retail, commercial and industrial customers. Approximately 66%42% of SouthStar’s purchase instruments and 58%46% of its sales instruments are scheduled to mature in 2009 and the remaining 34%58% and 42%54%, respectively, in less than 2 years.from January 2010 through March 2012.
SouthStar also enters into both exchange and OTC derivative financial instruments to hedge natural gas price risk. Credit risk is mitigated for exchange transactions through the backing of the NYMEX member firms. For OTC transactions, SouthStar utilizes master netting arrangements to reduce overall credit risk. As of JuneSeptember 30, 2009, SouthStar’s maximum exposure to any single OTC counterparty was $3$7 million.
Wholesale Services 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 derivative financial instruments we use.
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 can receive in the future, resulting in a positive net operating margin. We use NYMEX futures contracts and other OTC derivatives to sell natural gas at that future price to substantially lock in the operating margin we will ultimately realize when the stored natural gas is actually sold. These futures contracts meet the definition of derivatives under SFAS 133the authoritative guidance related to derivatives and hedging and are accounted for at fair value in our condensed consolidated statements of financial position, with changes in fair value recorded in our condensed consolidated statements of income in the period of change. However, these futures contracts are not designated as hedges in accordance with SFAS 133.the guidance.
The purchase, transportation, storage and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis we utilize for the derivatives used to mitigate the natural gas price risk associated with our storage portfolio. This difference in accounting can result in volatility in our reported earnings, even though the economic margin is essentially unchanged from the date the transactions were consummated. Approximately 96% of Sequent’s purchase instruments and 97% of its sales instruments are scheduled to mature in less than 2 years and the remaining 4% and 3%, respectively, in 3 to 9 years.
The changes in fair value of Sequent’s derivative instruments utilized in its energy marketing and risk management activities and contract settlements decreased the net fair value of its contracts outstanding by $26 million during the six months ended June 30, 2009 and by $153 million during the six months ended June 30, 2008.
Energy Investments Golden Triangle Storage uses derivative financial instruments to reduce its exposure during the construction of the storage caverns to the risk of changes in the pricesprice of natural gas associated with natural gas tothat will be purchased in future periods in connection with the construction of the storage caverns for pad gas. Pad gas which includes volumes of non-working natural gas used to maintain the operational integrity of the caverns. 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 derivative instruments.
We have designated all of Golden Triangle Storage’s derivative financial instruments, consisting of financial swaps to manage the natural gas price risk associated with forecasted purchases of natural gas for its pad gas, as cash flow hedges under SFAS 133. We record derivative gains or losses arising from cash flow hedges in OCIthe authoritative guidance related to derivatives and reclassify them into earnings in the same period as the pad gas is sold. Until the pad gas is sold, the gains and losses will remain in OCI sincehedging. The pad gas is considered to be a component of the storage cavern’s construction costs; as a result, any derivative gains or losses arising from the cash flow hedges will remain in OCI until the pad gas is sold, which will not occur until the storage caverns PP&E cost. Golden Triangle Storageare decommissioned. These derivative financial instruments currently hashave minimal hedge ineffectiveness. This cash flow hedge ineffectiveness which is recorded in cost of gas in our condensed consolidated statements of income in the period in which it occurs. Golden Triangle Storage began entering into these derivative financial transactions during the second quarter2009.
Weather Derivative Financial Instruments
In 2009 and 2008, SouthStar entered into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal and colder-than-normal weather in the heating season, primarily from November through March. SouthStar accounts for these contracts using the intrinsic value method under the guidelines of EITF 99-2,authoritative guidance related to financial instruments, and accordingly these weather derivative financial instruments are not designated as derivatives or hedges under SFAS 133. SouthStar had no active weather derivatives at June 30, 2009 or 2008. As a result, our condensed consolidated balance sheets reflect no amounts for this hedging activity as of June 30, 2009 and at June 30, 2008; however, SouthStar did recordhas recorded a current asset of $3 million at September 30, 2009, $4 million at December 31, 2008 and $1 million at September 30, 2008. SouthStar recognized losses on its weather derivative financial instruments of $4 million for the sixnine months ended JuneSeptember 30, 2009 and $5 million for the sixnine months ended JuneSeptember 30, 2008 which was reflected in cost of gas on our condensed consolidated statements of income.
Quantitative Disclosures Related to Derivative Financial Instruments
As of JuneSeptember 30, 2009, our derivative financial instruments were comprised of both long and short natural gas positions, whereby apositions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. As of JuneSeptember 30, 2009, we had net long natural gas contracts outstanding in the following quantities:
| | Natural gas contracts (in Bcf) | | | Natural gas contracts (in Bcf) | |
Hedge designation under SFAS 133 | | Distribution operations | | | Retail energy operations | | | Wholesale services | | | Consolidated | | |
Hedge designation | | | Distribution operations | | | Retail energy operations | | | Wholesale services | | | Energy investments | | | Consolidated | |
Cash flow | | | - | | | | 4 | | | | - | | | | 4 | | | | - | | | | 2 | | | | - | | | | 2 | | | | 4 | |
Not designated | | | 17 | | | | 8 | | | | 99 | | | | 124 | | | | 18 | | | | 9 | | | | 36 | | | | - | | | | 63 | |
Total | | | 17 | | | | 12 | | | | 99 | | | | 128 | | | | 18 | | | | 11 | | | | 36 | | | | 2 | | | | 67 | |
Derivative Financial Instruments on the Condensed Consolidated Statements of Income
The following table presents the gain or (loss) on derivative financial instruments in our condensed consolidated statements of income for the three and sixnine months ended JuneSeptember 30, 2009.
| | Three months ended June 30, 2009 | | | Six months ended June 30, 2009 | | | Three months ended September 30, 2009 | | | Nine months ended September 30, 2009 | |
In millions | | Retail energy operations | | | Wholesale services | | | Retail energy operations | | | Wholesale services | | | Retail energy operations | | | Wholesale services | | | Retail energy operations | | | Wholesale services | |
Designated as cash flow hedges under SFAS 133 | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Designated as cash flow hedges under authoritative guidance related to derivatives and hedging | | | | | | | | | | | | | |
Natural gas contracts – loss reclassified from OCI into cost of gas for settlement of hedged item | | $ | (12 | ) | | $ | - | | | $ | (16 | ) | | $ | - | | | $ | (8 | ) | | $ | - | | | $ | (25 | ) | | $ | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Not designated as hedges under SFAS 133: | | | | | | | | | | | | | | | | | |
Not designated as hedges under authoritative guidance related to derivatives and hedging: | | | | | | | | | | | | | | | | | |
Natural gas contracts – fair value adjustments recorded in operating revenues (1) | | | - | | | | 16 | | | | - | | | | 52 | | | | - | | | | 8 | | | | - | | | | 50 | |
Natural gas contracts – fair value adjustments recorded in cost of gas (2) | | | - | | | | - | | | | (1 | ) | | | - | | | | - | | | | - | | | | - | | | | - | |
Total (losses) gains on derivative instruments | | $ | (12 | ) | | $ | 16 | | | $ | (17 | ) | | $ | 52 | | | $ | (8 | ) | | $ | 8 | | | $ | (25 | ) | | $ | 50 | |
(1) Associated with the fair value of existing derivative instruments at JuneSeptember 30, 2009.
(2) Excludes $4 million of losses recorded in cost of gas associated with weather derivatives accounted for in accordance with EITF 99-2 for the sixnine months ended JuneSeptember 30, 2009.
In accordance with regulatory requirements, any realized gains and losses on derivative instruments used in our distribution operations segment are reflected in deferred natural gas costs within our condensed consolidated statements of financial position as indicated in the following table.
| | Three months ended June 30, | | | Six months ended June 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Elizabethtown Gas recognized (losses) gains on its derivative instruments reclassified to deferred natural gas costs | | $ | (7 | ) | | $ | 8 | | | $ | (20 | ) | | $ | 8 | |
The following amounts (pre-tax) represent the expected recognition in our condensed consolidated statements of income of the deferred losses recorded in OCI associated with retail energy operations’ derivative instruments, based upon the fair values of these financial instruments as of JuneSeptember 30, 2009:
In millions | | Retail energy operations | |
Designated as hedges under SFAS 133 | | | |
Natural gas contracts – expected net loss reclassified from OCI into cost of gas for settlement of hedged item: | | | |
Next twelve months | | $ | (18 | ) |
Thereafter | | | - | |
Total | | $ | (18 | ) |
In millions | | Retail energy operations | |
Designated as hedges under authoritative guidance related to derivatives and hedging | | | |
Natural gas contracts – expected net loss reclassified from OCI into cost of gas for settlement of hedged item over next twelve months | | $ | (11 | ) |
Derivative Financial Instruments on the Condensed Consolidated Statements of Financial Position
In accordance with regulatory requirements, any realized gains and losses on derivative financial instruments used in our distribution operations segment are reflected in deferred natural gas costs within our condensed consolidated statements of financial position as indicated in the following table.
In millions | | Three months ended September 30, 2009 | | | Nine months ended September 30, 2009 | |
Elizabethtown Gas recognized losses on its derivative financial instruments reclassified to deferred natural gas costs | | $ | (10 | ) | | $ | (30 | ) |
The following table presents the fair value and statements of financial position classification of our derivative financial instruments by operating segment.
| | | As of June 30, 2009 | | | | As of September 30, 2009 (2) | |
In millions | Statements of financial position location (1) | | Distribution operations | | | Retail energy operations | | | Wholesale services | | | Consolidated (2) | | Statements of financial position location (1) | | Distribution operations | | | Retail energy operations | | | Wholesale services | | | Energy investments | | | Consolidated | |
Designated as cash flow hedges under SFAS 133: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Designated as cash flow hedges under authoritative guidance related to derivatives and hedging | | Designated as cash flow hedges under authoritative guidance related to derivatives and hedging | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Asset Financial Instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current natural gas contracts | Derivative financial instruments assets and liabilities – current portion | | $ | - | | | $ | 13 | | | $ | - | | | $ | 13 | | Derivative financial instruments assets and liabilities – current portion | | $ | - | | | $ | 14 | | | $ | - | | | $ | - | | | $ | 14 | |
Noncurrent natural gas contracts | Derivative financial instruments assets and liabilities | | | - | | | | - | | | | - | | | | - | | Derivative financial instruments assets and liabilities | | | - | | | | - | | | | - | | | | 1 | | | | 1 | |
Liability Financial Instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current natural gas contracts | Derivative financial instruments assets and liabilities – current portion | | | - | | | | (18 | ) | | | - | | | | (18 | ) | Derivative financial instruments assets and liabilities – current portion | | | - | | | | (8 | ) | | | - | | | | - | | | | (8 | ) |
Noncurrent natural gas contracts | Derivative financial instruments assets and liabilities | | | - | | | | - | | | | - | | | | - | | Derivative financial instruments assets and liabilities | | | - | | | | - | | | | - | | | | - | | | | - | |
Total | | | | - | | | | (5 | ) | | | - | | | | (5 | ) | | | | - | | | | 6 | | | | - | | | | 1 | | | | 7 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Not designated as hedges under SFAS 133: | | | | | | | | | | | | | | | | | | |
Not designated as hedges under authoritative guidance related to derivatives and hedging: | | Not designated as hedges under authoritative guidance related to derivatives and hedging: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
Asset Financial Instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current natural gas contracts | Derivative financial instruments assets and liabilities – current portion | | | 20 | | | | 4 | | | | 393 | | | | 417 | | Derivative financial instruments assets and liabilities – current portion | | | 12 | | | | 3 | | | | 353 | | | | - | | | | 368 | |
Noncurrent natural gas contracts | Derivative financial instruments assets and liabilities | | | 1 | | | | - | | | | 63 | | | | 64 | | Derivative financial instruments assets and liabilities | | | 1 | | | | - | | | | 59 | | | | - | | | | 60 | |
Liability Financial Instruments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current natural gas contracts | Derivative financial instruments assets and liabilities – current portion | | | (20 | ) | | | (4 | ) | | | (368 | ) | | | (392 | ) | Derivative financial instruments assets and liabilities – current portion | | | (12 | ) | | | (4 | ) | | | (323 | ) | | | - | | | | (339 | ) |
Noncurrent natural gas contracts | Derivative financial instruments assets and liabilities | | | (1 | ) | | | - | | | | (32 | ) | | | (33 | ) | Derivative financial instruments assets and liabilities | | | (1 | ) | | | - | | | | (34 | ) | | | | | | | (35 | ) |
Total | | | | - | | | | - | | | | 56 | | | | 56 | | | | | - | | | | (1 | ) | | | 55 | | | | - | | | | 54 | |
Total derivative financial instruments | | | $ | - | | | $ | (5 | ) | | $ | 56 | | | $ | 51 | | Total derivative financial instruments | | $ | - | | | $ | 5 | | | $ | 55 | | | $ | 1 | | | $ | 61 | |
(1) | These amounts are netted within our condensed consolidated statements of financial position. Some of our derivative financial instruments have asset positions which are presented as a liability in our condensed consolidated statements of financial position, and we have derivative instruments that have liability positions which are presented as an asset in our condensed consolidated statements of financial position. |
(2) | As required by SFAS 161,the authoritative guidance related to derivatives and hedging, the fair value amounts above are presented on a gross basis. Additionally, the amounts above do not include $124$82 million of cash collateral held on deposit in broker margin accounts as of JuneSeptember 30, 2009. As a result, the amounts above will differ from the amounts presented on our condensed consolidated statements of financial position, and the fair value information presented for our derivative financial instruments in Note 2. |
FSP FAS 132(R)-1
This FSPThe authoritative guidance for retirement benefits requires additional disclosures relating to postretirement benefit plan assets to provide transparency regarding the types of assets and the associated risks within the types of plan assets. The required disclosures include:
· | How investment allocation decisions are made, including information that provides an understanding of investment policies and strategies, |
· | The major categories of plan assets, |
· | Inputs and valuation techniques used to measure the fair value of plan assets, including those measurements using significant unobservable inputs, on changes in plan assets for the period, and |
· | Significant concentrations of risk within plan assets. |
This FSPaccounting guidance is effective for fiscal years ending after December 15, 2009 and requires additional disclosures in our notes to condensed consolidated financial statements, but will not have a material impact on our condensed consolidated financial position, results of operations or cash flows.
Pension Benefits
We sponsor two tax-qualified defined benefit retirement plans for our eligible employees, the AGL Resources Inc. Retirement Plan and the Employees’ Retirement Plan of NUI Corporation. A defined benefit plan specifies the amount of benefits an eligible participant eventually will receive using information about the participant. Following are the combined cost components of our two defined pension plans for the periods indicated.
| | Three months ended June 30, | | | Three months ended September 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Service cost | | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 2 | |
Interest cost | | | 6 | | | | 6 | | | | 7 | | | | 7 | |
Expected return on plan assets | | | (8 | ) | | | (8 | ) | | | (6 | ) | | | (9 | ) |
Amortization of prior service cost | | | - | | | | - | | | | (1 | ) | | | - | |
Recognized actuarial loss | | | 3 | | | | 1 | | | | 2 | | | | - | |
Net pension benefit cost | | $ | 3 | | | $ | 1 | | | $ | 4 | | | $ | - | |
| | Six months ended June 30, | | | Nine months ended September 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Service cost | | $ | 4 | | | $ | 4 | | | $ | 6 | | | $ | 6 | |
Interest cost | | | 13 | | | | 13 | | | | 20 | | | | 20 | |
Expected return on plan assets | | | (15 | ) | | | (16 | ) | | | (21 | ) | | | (25 | ) |
Amortization of prior service cost | | | (1 | ) | | | (1 | ) | | | (2 | ) | | | (1 | ) |
Recognized actuarial loss | | | 5 | | | | 2 | | | | 7 | | | | 2 | |
Net pension benefit cost | | $ | 6 | | | $ | 2 | | | $ | 10 | | | $ | 2 | |
Our employees do not contribute to these retirement plans. We fund the plans by contributing at least the minimum amount required by applicable regulations and as recommended by our actuary. However, we may also contribute in excess of the minimum required amount. We calculate the minimum amount of funding using the projected unit credit cost method. The Pension Protection Act (the Act) of 2006 contained new funding requirements for single employer defined benefit pension plans. The Act establishesestablished a 100% funding target for plan years beginning after December 31, 2007. However, a delayed effective date of 2011 may apply if the pension plan meets the following targets: 92% funded in 2008; 94% funded in 2009; and 96% funded in 2010. In December 2008, the Worker, Retiree and Employer Recovery Act of 2008 allowed us to measure our 2008 and 2009 funding target at 92%. DuringIn the first sixnine months of 2009, we made $17contributed $21 million in contributions to our qualified plans.pension plans and we contributed an additional $3 million in October 2009. We do not expect to make any additional contributions to our pension plans of $15 million during the remainder of 2009. In 2008, we did not make a contribution, as one was not required for our pension plans.
Postretirement Benefits
The Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Postretirement Plan) covers all eligible AGL Resources employees who were employed as of June 30, 2002, if they reach retirement age while working for us. Eligibility for benefits under the AGL Postretirement Plan is based on age and years of service. The state regulatory commissions have approved phase-ins that defer a portion of other postretirement benefits expense for future recovery. Effective December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 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. Effective January 1, 2006, benefits for prescription drugs were not provided under the plan to individuals who are eligible to receive prescription drug benefits under Medicare Part D. Medicare-eligible participants in the AGL Postretirement Plan receive prescription drug benefits through a Medicare Part D plan offered by a third party and to which we subsidize participant premiums. Medicare-eligible retirees who opt out of the AGL Postretirement Plan are eligible to receive a cash subsidy which may be used towards eligible prescription drug expenses. As of July 1, 2009, we discontinued providing medical coverage for our Medicare eligible retirees, affecting over 80% of our approximately 2,400 retirees. Those eligible retirees now receive a contribution toward coverage obtained from independent providers. Contributions are $120 per month to $240 per month depending on the coverage. We continue to provide medical coverage to pre-Medicare eligible retirees.
Following are the cost components of the AGL Postretirement Plan for the periods indicated.
| | Three months ended June 30, | | | Three months ended September 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Service cost | | $ | - | | | $ | 1 | | | $ | - | | | $ | - | |
Interest cost | | | 2 | | | | 2 | | | | 1 | | | | 1 | |
Expected return on plan assets | | | (1 | ) | | | (2 | ) | | | (1 | ) | | | (1 | ) |
Amortization of prior service cost | | | (1 | ) | | | (1 | ) | | | (1 | ) | | | (1 | ) |
Recognized actuarial loss | | | - | | | | - | | | | 1 | | | | - | |
Net postretirement benefit cost | | $ | - | | | $ | - | | | $ | - | | | $ | (1 | ) |
| | Six months ended June 30, | | | Nine months ended September 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Service cost | | $ | - | | | $ | 1 | | | $ | - | | | $ | 1 | |
Interest cost | | | 3 | | | | 3 | | | | 4 | | | | 4 | |
Expected return on plan assets | | | (2 | ) | | | (3 | ) | | | (3 | ) | | | (4 | ) |
Amortization of prior service cost | | | (2 | ) | | | (2 | ) | | | (3 | ) | | | (3 | ) |
Recognized actuarial loss | | | 1 | | | | - | | | | 2 | | | | - | |
Net postretirement benefit cost | | $ | - | | | $ | (1 | ) | | $ | - | | | $ | (2 | ) |
Employee Savings Plan Benefits
We sponsor the Retirement Savings Plus Plan (RSP Plan), a defined contribution benefit plan that allows eligible participants to make contributions to their accounts up to specified limits. Under the RSP Plan, we made $4$5 million in matching contributions to participant accounts in the first sixnine months of 2009 and $3$5 million in the same period last year.
In June 2009, the FASB issued an amendment to the guidance related to transfers and servicing of financial assets and interests in a variable interest entity (VIE) that requires improved disclosures about transfers of financial assets and removes the exception from applying the guidance related to consolidations specifically for VIE’s to qualifying special purpose entities. The amendment to the guidance will be effective for us on January 1, 2010 and it will have no effect on our consolidated results of operations, cash flows or financial position.
In June 2009, the FASB issued new consolidation guidance for a VIE. The guidance requires a company to assess the determination of the primary beneficiary of a VIE based on whether the company has the power to direct matters that most significantly impact the activities of the VIE and has the obligation to absorb losses or the right to receive benefits of the VIE. In addition, the guidance requires ongoing reassessments of whether a company is the primary beneficiary of a VIE. The guidance will be effective for us on January 1, 2010. Earlier application is prohibited. We are currently evaluating the impact of this guidance on our consolidated results of operations, cash flows and financial position.
Noncontrolling Interests
We currently own a noncontrolling 70% financial interest in SouthStar, a joint venture with Piedmont who owns the remaining 30%. Our 70% interest is noncontrolling because all significant management decisions require approval by both owners. Although our ownership interest in the SouthStar partnership is 70%, under an amended and restated joint venture agreement executed in March 2004, SouthStar's earnings are currently allocated 75% to us and 25% to Piedmont except for earnings related to customers in Ohio and Florida, which are currently allocated 70% to us and 30% to Piedmont.
We are the primary beneficiary of SouthStar’s activities and have determined that SouthStar is a variable interest entityVIE as defined by FIN 46R,the authoritative guidance related to consolidations, which requires us to consolidate the variable interest entity.VIE. The assets, liabilities, and noncontrolling interests of a consolidated variable interest entityVIE are accounted for in our condensed consolidated financial statements as if the entity were consolidated based on voting interests.
The CompanyWe determined that SouthStar was a variable interest entityVIE because itsour equal voting rights with Piedmont are not proportional to itsour economic obligation to absorb 75% of any losses or residual returns from SouthStar, except those losses and returns related to customers in Ohio and Florida. In addition, SouthStar obtains substantially all its transportation capacity for delivery of natural gas through our wholly-owned subsidiary, Atlanta Gas Light.
On January 1, 2009, we adopted SFAS 160,additional authoritative guidance relating to consolidations, and applied the presentation and disclosure requirements retrospectively for all periods presented. SFAS 160The additional guidance does not change the requirements of FIN 46R and providesprior guidance but requires that the noncontrolling interest should be reported as a separate component of equity on our condensed consolidated statements of financial position.
Additionally, prior to adoption of SFAS 160,the guidance, we recorded our earnings allocated to Piedmont as a component of earnings before income taxes in our condensed consolidated statements of income. SFAS 160The additional guidance requires that any net income attributable to the noncontrolling interest be presented separately in our condensed consolidated statements of income. As a result, net income from noncontrolling interest is reported after net income in order to report net income attributable to the parent and the noncontrolling interest. The adoption of SFAS 160 hasthis guidance had no effect on our calculation of basic or diluted earnings per share amounts, which will continue to be based upon amounts attributable to AGL Resources.
Stock-Based Compensation
In the first six months of 2009, we issued grants of approximately 250,000 stock options and 211,000 restricted stock units, which will result in the recognition of approximately $2 million of stock-based compensation expense in 2009. No material share awards have been granted to employees whose compensation is subject to capitalization. We use the Black-Scholes pricing model to determine the fair value of the options granted. On an annual basis, we evaluate the assumptions and estimates used to calculate our stock-based compensation expense.
There have been no significant changes to our stock-based compensation, as described in Note 4 to our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.
Comprehensive Income
Our comprehensive income or loss includes net income plus OCI, which includes other gains and losses affecting equity that GAAP excludes from net income. Such items consist primarily of gains and losses on certain derivatives designated as cash flow hedges and unfunded or overfunded pension and postretirement obligation adjustments. Our cumulative comprehensive income or loss that has been excluded from net income is reported as accumulated other comprehensive loss within our condensed consolidated statement of equity.
Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by, or filings with, state and federal regulatory bodies, including state public service commissions, the SEC and the FERC pursuant to the Energy Policy Act of 2005. The following table provides information onshows the carrying amounts of our variouslong-term debt securities.included in our condensed consolidated statements of financial position. We estimate the fair value using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. In determining the market interest yield curve, we considered our currently assigned ratings for unsecured debt of BBB+ by S&P, Baa1 by Moody’s and A- by Fitch. For more information on our debt, see Note 6 in our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.
| | | | | | | | | | | Outstanding as of | |
In millions | | Year(s) due | | | Weighted average interest rate (1) | | | Interest rate (2) | | | September 30, 2009 | | | December 31, 2008 | | | September 30, 2008 | |
Short-term debt | | | | | | | | | | | | | | | | | | |
Commercial paper | | 2009 | | | | 0.8 | % | | | 0.6 | % | | $ | 309 | | | $ | 273 | | | $ | 198 | |
Capital leases | | 2009 | | | | 4.9 | | | | 4.9 | | | | 1 | | | | 1 | | | | 1 | |
Credit Facility | | | - | | | | - | | | | - | | | | - | | | | 500 | | | | 485 | |
SouthStar line of credit | | | - | | | | - | | | | - | | | | - | | | | 75 | | | | 55 | |
Sequent lines of credit (3) | | | - | | | | - | | | | - | | | | - | | | | 17 | | | | 20 | |
Pivotal Utility line of credit (3) | | | - | | | | - | | | | - | | | | - | | | | - | | | | 10 | |
Total short-term debt | | | | | | | 0.9 | % | | | 0.6 | % | | $ | 310 | | | $ | 866 | | | $ | 769 | |
Long-term debt - net of current portion | | | | | | | | | | | | | | | | | | | | | | | | |
Senior notes | | 2011-2034 | | | | 5.9 | % | | | 4.5-7.1 | % | | $ | 1,575 | | | $ | 1,275 | | | $ | 1,275 | |
Gas facility revenue bonds | | 2022-2033 | | | | 1.2 | | | | 0.2-5.3 | | | | 200 | | | | 200 | | | | 200 | |
Medium-term notes | | 2012-2027 | | | | 7.8 | | | | 6.6-9.1 | | | | 196 | | | | 196 | | | | 196 | |
Capital leases | | 2013 | | | | 4.9 | | | | 4.9 | | | | 4 | | | | 4 | | | | 4 | |
Total long-term debt (4) | | | | | | | 5.5 | % | | | 5.5 | % | | $ | 1,975 | | | $ | 1,675 | | | $ | 1,675 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total debt | | | | | | | 4.6 | % | | | 4.8 | % | | $ | 2,285 | | | $ | 2,541 | | | $ | 2,444 | |
| | | | | | | | | | | Outstanding as of | |
In millions | | Year(s) due | | | Interest rate (1) | | | Weighted average interest rate(2) | | | June 30, 2009 | | | Dec. 31, 2008 | | | June 30, 2008 | |
Short-term debt | | | | | | | | | | | | | | | | | | |
Commercial paper | | 2009 | | | | 0.6 | % | | | 0.9 | % | | $ | 417 | | | $ | 273 | | | $ | 465 | |
Credit Facilities | | | - | | | | - | | | | - | | | | - | | | | 500 | | | | - | |
SouthStar line of credit | | | - | | | | - | | | | - | | | | - | | | | 75 | | | | - | |
Sequent lines of credit (3) | | | - | | | | - | | | | - | | | | - | | | | 17 | | | | 38 | |
Pivotal Utility line of credit | | | - | | | | - | | | | - | | | | - | | | | - | | | | 9 | |
Capital leases | | | 2009 | | | | 4.9 | | | | 4.9 | | | | 1 | | | | 1 | | | | 1 | |
Total short-term debt | | | | | | | 0.6 | % | | | 1.0 | % | | $ | 418 | | | $ | 866 | | | $ | 513 | |
Long-term debt - net of current portion | | | | | | | | | | | | | | | | | | | | | | | | |
Senior notes | | 2011-2034 | | | | 4.5-7.1 | % | | | 5.9 | % | | $ | 1,275 | | | $ | 1,275 | | | $ | 1,275 | |
Gas facility revenue bonds | | 2022-2033 | | | | 0.1-5.3 | | | | 1.3 | | | | 200 | | | | 200 | | | | 161 | |
Medium-term notes | | 2012-2027 | | | | 6.6-9.1 | | | | 7.8 | | | | 196 | | | | 196 | | | | 196 | |
Capital leases | | 2013 | | | | 4.9 | | | | 4.9 | | | | 4 | | | | 4 | | | | 5 | |
Total long-term debt | | | | | | | 5.5 | % | | | 5.5 | % | | $ | 1,675 | | | $ | 1,675 | | | $ | 1,637 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total debt | | | | | | | 4.5 | % | | | 4.5 | % | | $ | 2,093 | | | $ | 2,541 | | | $ | 2,150 | |
(1) As of June 30, 2009. | | | | | | | | | | | | | | | | | |
(2) For the six months ended June 30, 2009. | | | | | | | | | | | | | | | | | |
(3) In June 2009, Sequent’s $25 million unsecured line of credit expired. | | | | | | | | | | | | | | | | | |
(1) | For the nine months ended September 30, 2009. |
(2) | As of September 30, 2009. |
(3) | Sequent’s $25 million line of credit expired in June 2009. Pivotal Utility’s $15 million line of credit expired in October 2008. |
(4) | Our estimated fair value was $2,116 million as of September 30, 2009, $1,647 million as of December 31, 2008 and $1,671 million as of September 30, 2008. |
In August 2009, AGL Capital issued $300 million of 10-year senior notes at an interest rate of 5.25%. The net proceeds from the offering were approximately $297 million. We used the net proceeds from the sale of the senior notes to repay a portion of our short-term debt.
Default Events
Our Credit Facility financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%; however, our goal is to maintain this ratio at levels between 50% and 60%. Our ratio of total debt to total capitalization calculation contained in our debt covenant includes standby letters of credit, surety bonds and the exclusion of other comprehensive income pension adjustments. Adjusting for these items, our debt-to-equity calculation, as defined by our Credit Facility, was 55% at September 30, 2009, 59% at December 31, 2008 and 58% at September 30, 2008. These amounts are within our required and targeted ranges. Our debt-to-equity calculation, as calculated from our condensed consolidated statements of financial position, was 57% at September 30, 2009, 60% at December 31, 2008 and 58% at September 30, 2008.
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 have no 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.
Contractual Obligations and Commitments
We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities that are reasonably likely to have a material effect on liquidity or the availability of capital resources. 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. As we do for other subsidiaries, we provide guarantees to certain gas suppliers for SouthStar in support of payment obligations. There were no significant changes to our contractual obligations described in Note 7 to our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.
Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur 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 contingent financial commitments as of JuneSeptember 30, 2009.
| | Commitments due before December 31, | | | Commitments due before December 31, | |
In millions | | Total | | | 2009 | | | 2010 & thereafter | | | Total | | | 2009 | | | 2010 & thereafter | |
Standby letters of credit and performance and surety bonds | | $ | 23 | | | $ | 15 | | | $ | 8 | | | $ | 26 | | | $ | 9 | | | $ | 17 | |
Litigation
We are involved in litigation arising in the normal course of business. The ultimate resolution of such litigation is not expected to have a material adverse effect on our condensed consolidated financial position, results of operations or cash flows.
Information on the Jefferson Island Storage & Hub, LLC vs. State of Louisiana litigation is described in Note 7 to our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009. In April 2009, the trial court ruled that the legislation that restricted Jefferson Island’s ability to use water from the Chicot aquifer to expand its existing storage facility is unconstitutional and invalid.
In addition,August 2009, Jefferson Island announced that it had negotiated a tentative agreement with the state of Louisiana that, subject to approval, would resolve the pending lawsuit between the parties over a disputed mineral lease. A finalized agreement will enable Jefferson Island to resume its plan to expand the existing natural gas storage facility. The state Mineral Board must approve the agreement in order for it to be valid, and a decision could come during the fourth quarter of 2009. The parties also jointly requested that the trial court delay the previously scheduled a trial in September 2009 ontrial date which would have resolved Jefferson Island’s claim that it is authorized to expand the facility under its mineral lease.lease while the parties work through this approval process. The ultimate resolution of such litigation cannot be determined, but it is not expected to have a material adverse effect on our condensed consolidated financial position, results of operations or cash flows.
In February 2008, the consumer affairs staff of the Georgia Commission alleged that GNG charged its customers on variable rate plans prices for natural gas that were in excess of the published price, that it failed to give proper notice regarding the availability of potentially lower price plans and that it changed its methodology for computing variable rates. GNG asserted that it fully complied with all applicable rules and regulations, that it properly charged its customers on variable rate plans the rates on file with the Georgia Commission, and that, consistent with its terms and conditions of service, it routinely switched customers who requested to move to another price plan for which they qualified. In order to resolve this matter GNG agreed to pay $2.5approximately $3 million in the form of credits to customers, or as directed by the Georgia Commission, which was recorded in our statements of consolidated income for the year ended December 31, 2008.
In February 2008, a class action lawsuit was filed in the Superior Court of Fulton County in the State of Georgia against GNG containing similar allegations to those asserted by the Georgia Commission staff and seeking damages on behalf of a class of GNG customers. This lawsuit was dismissed in September 2008. The plaintiffs appealed the dismissal of the lawsuit and, in May 2009, the Georgia Court of Appeals reversed the lower court’s order. In June 2009, GNG filed a petition for reconsideration with the Georgia Supreme Court. In October 2009 the Georgia Supreme Court and GNG is waitingagreed to hear whether it will review the Court of Appeals’ decision. If the Court of Appeals’ decision is not reversed, the parties will proceed with the litigation at the trial court.
In March 2008, a second class action suit was filed against GNG in the State Court of Fulton County in the State of Georgia, regarding monthly service charges. This lawsuit alleges that GNG arbitrarily assigned customer service charges rather than basing each customer service charge on a specific credit score. GNG asserts that no violation of law or Georgia Commission rules has occurred, that this lawsuit is without merit and has filed motions to dismiss this class action suit on various grounds. This lawsuit was dismissed with prejudice in March 2009. In April 2009, the plaintiffs appealed the decision but in June 2009, the plaintiffs withdrew their appeal of the courts dismissal order in exchange for GNG withdrawing and dropping all claims for attorney’s fees and costs in connection with the trial and appellate proceedings.
In March 2009, Piedmont filed a lawsuit in the Court of Chancery of the State of Delaware against us asking the court to enter a judgment declaring that our right to purchase Piedmont’s ownership interest in SouthStar expires on November 1, 2009. We reached a settlement agreement with Piedmont that dismissed the lawsuit and will result in a restructuring of the ownership interests in the SouthStar joint venture. Under the terms of the agreement, which has been approved by the boards of directors of both companies, we will purchase an additional 15% ownership share in the joint venture from Piedmont for $58 million. As a result, we will own 85% of the SouthStar joint venture, and will be entitled to 85% of the annual earnings from the business, while Piedmont will retain the remaining 15% share. As part of the agreement, our interest will remain a noncontrolling interest and we will not have any further option rights to Piedmont’s remaining 15% ownership interest. The effective date of the transaction will be January 1, 2010. The agreement was approved by the Georgia Commission in October 2009.
In May 2009, Pivotal Utility Holdings Inc., through its operating entity Elizabethtown Gas, was served as a responsible party, along with several hundred other entities, in litigation associated with the investigation and cleanup of the Passaic River and Newark Bay in New Jersey. The Plaintiffs, Maxus Energy Corporation and Tierra Solutions, Inc., who are among parties who have been ordered to address contamination in those water bodies, assert that historical operations of Elizabethtown Gas' former manufactured gas plants contributed to contamination at issue. We have not evaluated Plaintiffs' claims but do not believe that Elizabethtown Gas' historical operations would have had any significant impact in either the Passaic River or Newark Bay. At the present time, the Companywe cannot estimate the amount of any loss, if any, associated with this claim. In addition, we believe that any amounts associated with this claim would be subject to our Remediation Adjustment ClauseElizabethtown Gas’ remediation adjustment clause that covers,allows it to recover through the rate mechanism, subject to stated limitations, costs associated with environmental remediation cost investigation and cleanup.
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. For more information on our environmental remediation costs, see Note 7 in our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.The following table provides more information on our former operating sites:
Atlanta Gas Light In millions | | Cost estimate range | | | Amount recorded | | | Expected costs over next twelve months | |
Georgia and Florida | | $ | 53 - 98 | | | $ | 53 | | | $ | 10 | |
New Jersey | | | 65 - 110 | | | | 65 | | | | 9 | |
North Carolina | | | 12 - 21 | | | | 12 | | | | 2 | |
Total | | $ | 130 - 229 | | | $ | 130 | | | $ | 21 | |
We have identified ten13 former operating sites in Georgia and three sites of predecessor companies in Florida where the CompanyAtlanta Gas Light owned or operated all or part of these sites. We are required to investigate possible environmental contamination at those sites and, if necessary, clean up any contamination. As of December 31, 2008, the soil and sediment remediation program was complete for all Georgia sites, although groundwater cleanup continues. For elements of the program where we still cannot provide engineering cost estimates, considerable variability remains in future cost estimates. As of June 30, 2009
Additionally, we have recorded a liability equal to the low end of the range of $56 million, an $18 million increase from December 31, 2008. Atlanta Gas Light expects $10 million to be incurred over the next 12 months.
Elizabethtown Gas We are associated withidentified 6 former operating sites in New Jersey North Carolina and other states.where Elizabethtown Gas owned or operated all or part of these sites. Material cleanups of these sites have not been completed nor are precise estimates available for future cleanup costs and therefore considerable variability remains in future cost estimates. For the New Jersey sites, cleanup cost estimates range from $65 million to $110 million. As of June 30, 2009, weWe have recorded a liability equal to the low end of the range of $65 million, a $7 million increase from December 31, 2008. Elizabethtown Gas expects $7 million to be incurred over the next 12 months.
We also ownidentified a site in Elizabeth City, North Carolina, thatwhich is subject to a remediation order by the North Carolina Department of Energy and Natural Resources. Cleanup cost estimates range from $12 million to $21 million. As of June 30, 2009, we had recorded a liability equal to the low end of the range of $12 million, a $2 million increase from December 31, 2008. We expect $2 million to be incurred over the next 12 months. ThereResources, and there are currently no cost recovery mechanisms for the environmental remediation sites in North Carolina.remediation.
Review of Compliance with FERC Regulations
In 2008 we conducted an internal review of our compliance with FERC interstate natural gas pipeline capacity release rules and regulations. Independent of our internal review, we also received data requests from FERC’s Office of Enforcement relating specifically to compliance with the FERC’s capacity release posting and bidding requirements. In June 2009, we reached a settlement agreement with the FERC. This settlement agreement did not have a material financial impact to our condensed consolidated results of operations, cash flows or financial position.
We are an energy services holding company whose principal business is the distribution of natural gas in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia. We generate nearly all our operating revenues through the sale, distribution, transportation and storage of natural gas. We are involved in several related and complementary businesses, including retail natural gas marketing to end-use customers primarily in Georgia; natural gas asset management and related logistics activities for each of our utilities as well as for nonaffiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability natural gas storage assets. We manage these businesses through four operating segments – distribution operations, retail energy operations, wholesale services and energy investments and a nonoperating corporate segment which includes intercompany eliminations.
We evaluate segment performance based primarily on the non-GAAP measure of EBIT, which includes the effects of corporate expense allocations. EBIT is a non-GAAP measure that includes operating income and other income and expenses. Items we do not include in EBIT are financing costs, including interest and debt expense and income taxes, 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 attributable to AGL Resources Inc. as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The following table contains the reconciliations of EBIT to operating income, earnings (loss) before income taxes and net income (loss) attributable to AGL Resources Inc. for the three and sixnine months ended JuneSeptember 30, 2009 and 2008.
| | Three months ended June 30, | | | Three months ended September 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Operating revenues | | $ | 377 | | | $ | 444 | | | $ | 307 | | | $ | 539 | |
Operating expenses | | | 322 | | | | 438 | | | | 264 | | | | 413 | |
Operating income | | | 55 | | | | 6 | | | | 43 | | | | 126 | |
Other income | | | 3 | | | | 3 | | | | 2 | | | | 2 | |
EBIT | | | 58 | | | | 9 | | | | 45 | | | | 128 | |
Interest expense, net | | | (24 | ) | | | (26 | ) | | | (26 | ) | | | (29 | ) |
Earnings (loss) before income taxes | | | 34 | | | | (17 | ) | |
Income tax expense (benefit) | | | 13 | | | | (7 | ) | |
Net income (loss) | | | 21 | | | | (10 | ) | |
Net income attributable to the noncontrolling interest | | | 1 | | | | 1 | | |
Net income (loss) attributable to AGL Resources Inc. | | $ | 20 | | | $ | (11 | ) | |
Earnings before income taxes | | | | 19 | | | | 99 | |
Income tax expense | | | | 7 | | | | 39 | |
Net income | | | | 12 | | | | 60 | |
Net loss attributable to the noncontrolling interest | | | | - | | | | (5 | ) |
Net income attributable to AGL Resources Inc. | | | $ | 12 | | | $ | 65 | |
| | Six months ended June 30, | | | Nine months ended September 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Operating revenues | | $ | 1,372 | | | $ | 1,456 | | | $ | 1,679 | | | $ | 1,995 | |
Operating expenses | | | 1,087 | | | | 1,262 | | | | 1,351 | | | | 1,675 | |
Operating income | | | 285 | | | | 194 | | | | 328 | | | | 320 | |
Other income | | | 5 | | | | 4 | | | | 7 | | | | 6 | |
EBIT | | | 290 | | | | 198 | | | | 335 | | | | 326 | |
Interest expense, net | | | (49 | ) | | | (56 | ) | | | (75 | ) | | | (85 | ) |
Earnings before income taxes | | | 241 | | | | 142 | | | | 260 | | | | 241 | |
Income tax expense | | | 85 | | | | 47 | | | | 92 | | | | 86 | |
Net income | | | 156 | | | | 95 | | | | 168 | | | | 155 | |
Net income attributable to the noncontrolling interest | | | 17 | | | | 17 | | | | 17 | | | | 12 | |
Net income attributable to AGL Resources Inc. | | $ | 139 | | | $ | 78 | | | $ | 151 | | | $ | 143 | |
Information by segment on our statement of financial position at December 31, 2008, is as follows:
In millions | | Identifiable and total assets (1) | | | Goodwill | |
Distribution operations | | $ | 5,138 | | | $ | 404 | |
Retail energy operations | | | 315 | | | | - | |
Wholesale services | | | 970 | | | | - | |
Energy investments | | | 353 | | | | 14 | |
Corporate and intercompany eliminations (2) | | | (66 | ) | | | - | |
Consolidated AGL Resources Inc. | | $ | 6,710 | | | $ | 418 | |
(1) | Identifiable assets are those assets used in each segment’s operations. |
(2) | Our corporate segment’s assets consist primarily of cash and cash equivalents and property, plant and equipment and reflect the effect of intercompany eliminations. |
Summarized income statement information, identifiable and total assets, goodwill and property, plant and equipment expenditures as of and for the three and sixnine months ended JuneSeptember 30, 2009 and 2008, by segment, are shown in the following tables.
Three months ended JuneSeptember 30, 2009
In millions | | Distribution operations | | | Retail energy operations | | | Wholesale services | | | Energy investments | | | Corporate and intercompany eliminations (3) | | | Consolidated AGL Resources | | | Distribution operations | | | Retail energy operations | | | Wholesale services | | | Energy investments | | | Corporate and intercompany eliminations (3) | | | Consolidated AGL Resources | |
Operating revenues from external parties | | $ | 240 | | | $ | 125 | | | $ | 2 | | | $ | 10 | | | $ | - | | | $ | 377 | | | $ | 184 | | | $ | 100 | | | $ | 10 | | | $ | 11 | | | $ | 2 | | | $ | 307 | |
Intercompany revenues (1) | | | 35 | | | | - | | | | - | | | | - | | | | (35 | ) | | | - | | | | 35 | | | | - | | | | - | | | | - | | | | (35 | ) | | | - | |
Total operating revenues | | | 275 | | | | 125 | | | | 2 | | | | 10 | | | | (35 | ) | | | 377 | | | | 219 | | | | 100 | | | | 10 | | | | 11 | | | | (33 | ) | | | 307 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost of gas | | | 85 | | | | 102 | | | | - | | | | - | | | | (35 | ) | | | 152 | | | | 46 | | | | 86 | | | | - | | | | - | | | | (33 | ) | | | 99 | |
Operation and maintenance | | | 88 | | | | 16 | | | | 11 | | | | 7 | | | | (3 | ) | | | 119 | | | | 84 | | | | 15 | | | | 12 | | | | 5 | | | | (1 | ) | | | 115 | |
Depreciation and amortization | | | 33 | | | | 1 | | | | 1 | | | | 1 | | | | 3 | | | | 39 | | | | 34 | | | | 1 | | | | - | | | | 3 | | | | 2 | | | | 40 | |
Taxes other than income taxes | | | 9 | | | | 1 | | | | 1 | | | | - | | | | 1 | | | | 12 | | | | 9 | | | | - | | | | - | | | | - | | | | 1 | | | | 10 | |
Total operating expenses | | | 215 | | | | 120 | | | | 13 | | | | 8 | | | | (34 | ) | | | 322 | | | | 173 | | | | 102 | | | | 12 | | | | 8 | | | | (31 | ) | | | 264 | |
Operating income (loss) | | | 60 | | | | 5 | | | | (11 | ) | | | 2 | | | | (1 | ) | | | 55 | | | | 46 | | | | (2 | ) | | | (2 | ) | | | 3 | | | | (2 | ) | | | 43 | |
Other income | | | 3 | | | | - | | | | - | | | | - | | | | - | | | | 3 | | | | 2 | | | | - | | | | - | | | | - | | | | - | | | | 2 | |
EBIT | | $ | 63 | | | $ | 5 | | | $ | (11 | ) | | $ | 2 | | | $ | (1 | ) | | $ | 58 | | | $ | 48 | | | $ | (2 | ) | | $ | (2 | ) | | $ | 3 | | | $ | (2 | ) | | $ | 45 | |
Capital expenditures for property, plant and equipment | | $ | 89 | | | $ | 1 | | | $ | - | | | $ | 17 | | | $ | 3 | | | $ | 110 | | | $ | 73 | | | $ | - | | | $ | - | | | $ | 32 | | | $ | 2 | | | $ | 107 | |
Three months ended JuneSeptember 30, 2008
In millions | | Distribution operations | | | Retail energy operations | | | Wholesale services | | | Energy investments | | | Corporate and intercompany eliminations (3) | | | Consolidated AGL Resources | | | Distribution operations | | | Retail energy operations | | | Wholesale services | | | Energy investments | | | Corporate and intercompany eliminations (3) | | | Consolidated AGL Resources | |
Operating revenues from external parties | | $ | 299 | | | $ | 177 | | | $ | (51 | ) | | $ | 19 | | | $ | - | | | $ | 444 | | | $ | 237 | | | $ | 149 | | | $ | 138 | | | $ | 13 | | | $ | 2 | | | $ | 539 | |
Intercompany revenues (1) | | | 46 | | | | - | | | | - | | | | - | | | | (46 | ) | | | - | | | | 35 | | | | - | | | | - | | | | - | | | | (35 | ) | | | - | |
Total operating revenues | | | 345 | | | | 177 | | | | (51 | ) | | | 19 | | | | (46 | ) | | | 444 | | | | 272 | | | | 149 | | | | 138 | | | | 13 | | | | (33 | ) | | | 539 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost of gas | | | 165 | | | | 153 | | | | 2 | | | | 1 | | | | (46 | ) | | | 275 | | | | 101 | | | | 154 | | | | 37 | | | | 3 | | | | (34 | ) | | | 261 | |
Operation and maintenance | | | 83 | | | | 16 | | | | 10 | | | | 6 | | | | (1 | ) | | | 114 | | | | 72 | | | | 15 | | | | 13 | | | | 6 | | | | (2 | ) | | | 104 | |
Depreciation and amortization | | | 31 | | | | 1 | | | | 2 | | | | 2 | | | | 2 | | | | 38 | | | | 32 | | | | 1 | | | | 1 | | | | 1 | | | | 3 | | | | 38 | |
Taxes other than income taxes | | | 9 | | | | 1 | | | | - | | | | - | | | | 1 | | | | 11 | | | | 9 | | | | - | | | | 1 | | | | - | | | | - | | | | 10 | |
Total operating expenses | | | 288 | | | | 171 | | | | 14 | | | | 9 | | | | (44 | ) | | | 438 | | | | 214 | | | | 170 | | | | 52 | | | | 10 | | | | (33 | ) | | | 413 | |
Operating income (loss) | | | 57 | | | | 6 | | | | (65 | ) | | | 10 | | | | (2 | ) | | | 6 | | | | 58 | | | | (21 | ) | | | 86 | | | | 3 | | | | - | | | | 126 | |
Other income | | | - | | | | - | | | | - | | | | - | | | | 3 | | | | 3 | | | | 1 | | | | - | | | | - | | | | - | | | | 1 | | | | 2 | |
EBIT | | $ | 57 | | | $ | 6 | | | $ | (65 | ) | | $ | 10 | | | $ | 1 | | | $ | 9 | | | $ | 59 | | | $ | (21 | ) | | $ | 86 | | | $ | 3 | | | $ | 1 | | | $ | 128 | |
Capital expenditures for property, plant and equipment | | $ | 64 | | | $ | 1 | | | $ | - | | | $ | 18 | | | $ | 3 | | | $ | 86 | | | $ | 62 | | | $ | - | | | $ | - | | | $ | 23 | | | $ | 3 | | | $ | 88 | |
SixNine months ended JuneSeptember 30, 2009
In millions | | Distribution operations | | | Retail energy operations | | | Wholesale services | | | Energy investments | | | Corporate and intercompany eliminations (3) | | | Consolidated AGL Resources | | | Distribution operations | | | Retail energy operations | | | Wholesale services | | | Energy investments | | | Corporate and intercompany eliminations (3) | | | Consolidated AGL Resources | |
Operating revenues from external parties | | $ | 812 | | | $ | 468 | | | $ | 70 | | | $ | 20 | | | $ | 2 | | | $ | 1,372 | | | $ | 996 | | | $ | 568 | | | $ | 80 | | | $ | 31 | | | $ | 4 | | | $ | 1,679 | |
Intercompany revenues (1) | | | 70 | | | | - | | | | - | | | | - | | | | (70 | ) | | | - | | | | 105 | | | | - | | | | - | | | | - | | | | (105 | ) | | | - | |
Total operating revenues | | | 882 | | | | 468 | | | | 70 | | | | 20 | | | | (68 | ) | | | 1,372 | | | | 1,101 | | | | 568 | | | | 80 | | | | 31 | | | | (101 | ) | | | 1,679 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost of gas | | | 440 | | | | 361 | | | | 9 | | | | - | | | | (69 | ) | | | 741 | | | | 486 | | | | 447 | | | | 9 | | | | - | | | | (102 | ) | | | 840 | |
Operation and maintenance | | | 171 | | | | 36 | | | | 30 | | | | 12 | | | | (5 | ) | | | 244 | | | | 255 | | | | 51 | | | | 42 | | | | 17 | | | | (6 | ) | | | 359 | |
Depreciation and amortization | | | 65 | | | | 2 | | | | 2 | | | | 3 | | | | 6 | | | | 78 | | | | 99 | | | | 3 | | | | 2 | | | | 6 | | | | 8 | | | | 118 | |
Taxes other than income taxes | | | 18 | | | | 1 | | | | 2 | | | | 1 | | | | 2 | | | | 24 | | | | 27 | | | | 1 | | | | 2 | | | | 1 | | | | 3 | | | | 34 | |
Total operating expenses | | | 694 | | | | 400 | | | | 43 | | | | 16 | | | | (66 | ) | | | 1,087 | | | | 867 | | | | 502 | | | | 55 | | | | 24 | | | | (97 | ) | | | 1,351 | |
Operating income (loss) | | | 188 | | | | 68 | | | | 27 | | | | 4 | | | | (2 | ) | | | 285 | | | | 234 | | | | 66 | | | | 25 | | | | 7 | | | | (4 | ) | | | 328 | |
Other income | | | 5 | | | | - | | | | - | | | | - | | | | - | | | | 5 | | | | 7 | | | | - | | | | - | | | | - | | | | - | | | | 7 | |
EBIT | | $ | 193 | | | $ | 68 | | | $ | 27 | | | $ | 4 | | | $ | (2 | ) | | $ | 290 | | | $ | 241 | | | $ | 66 | | | $ | 25 | | | $ | 7 | | | $ | (4 | ) | | $ | 335 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Identifiable and total assets (2) | | $ | 4,972 | | | $ | 182 | | | $ | 686 | | | $ | 386 | | | $ | (106 | ) | | $ | 6,120 | | | $ | 4,996 | | | $ | 182 | | | $ | 651 | | | $ | 415 | | | $ | (61 | ) | | $ | 6,183 | |
Goodwill | | $ | 404 | | | $ | - | | | $ | - | | | $ | 14 | | | $ | - | | | $ | 418 | | | $ | 404 | | | $ | - | | | $ | - | | | $ | 14 | | | $ | - | | | $ | 418 | |
Capital expenditures for property, plant and equipment | | $ | 158 | | | $ | 1 | | | $ | - | | | $ | 40 | | | $ | 8 | | | $ | 207 | | | $ | 231 | | | $ | 1 | | | $ | - | | | $ | 72 | | | $ | 10 | | | $ | 314 | |
SixNine months ended JuneSeptember 30, 2008
In millions | | Distribution operations | | | Retail energy operations | | | Wholesale services | | | Energy investments | | | Corporate and intercompany eliminations (3) | | | Consolidated AGL Resources | | | Distribution operations | | | Retail energy operations | | | Wholesale services | | | Energy investments | | | Corporate and intercompany eliminations (3) | | | Consolidated AGL Resources | |
Operating revenues from external parties | | $ | 909 | | | $ | 552 | | | $ | (34 | ) | | $ | 30 | | | $ | (1 | ) | | $ | 1,456 | | | $ | 1,146 | | | $ | 701 | | | $ | 104 | | | $ | 43 | | | $ | 1 | | | $ | 1,995 | |
Intercompany revenues (1) | | | 112 | | | | - | | | | - | | | | - | | | | (112 | ) | | | - | | | | 147 | | | | - | | | | - | | | | - | | | | (147 | ) | | | - | |
Total operating revenues | | | 1,021 | | | | 552 | | | | (34 | ) | | | 30 | | | | (113 | ) | | | 1,456 | | | | 1,293 | | | | 701 | | | | 104 | | | | 43 | | | | (146 | ) | | | 1,995 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost of gas | | | 593 | | | | 446 | | | | 4 | | | | 1 | | | | (112 | ) | | | 932 | | | | 694 | | | | 600 | | | | 41 | | | | 4 | | | | (146 | ) | | | 1,193 | |
Operation and maintenance | | | 169 | | | | 35 | | | | 22 | | | | 10 | | | | (3 | ) | | | 233 | | | | 241 | | | | 50 | | | | 35 | | | | 16 | | | | (5 | ) | | | 337 | |
Depreciation and amortization | | | 62 | | | | 2 | | | | 3 | | | | 3 | | | | 4 | | | | 74 | | | | 94 | | | | 3 | | | | 4 | | | | 4 | | | | 7 | | | | 112 | |
Taxes other than income taxes | | | 18 | | | | 1 | | | | 1 | | | | 1 | | | | 2 | | | | 23 | | | | 27 | | | | 1 | | | | 2 | | | | 1 | | | | 2 | | | | 33 | |
Total operating expenses | | | 842 | | | | 484 | | | | 30 | | | | 15 | | | | (109 | ) | | | 1,262 | | | | 1,056 | | | | 654 | | | | 82 | | | | 25 | | | | (142 | ) | | | 1,675 | |
Operating income (loss) | | | 179 | | | | 68 | | | | (64 | ) | | | 15 | | | | (4 | ) | | | 194 | | | | 237 | | | | 47 | | | | 22 | | | | 18 | | | | (4 | ) | | | 320 | |
Other income | | | 1 | | | | - | | | | - | | | | - | | | | 3 | | | | 4 | | | | 2 | | | | - | | | | - | | | | - | | | | 4 | | | | 6 | |
EBIT | | $ | 180 | | | $ | 68 | | | $ | (64 | ) | | $ | 15 | | | $ | (1 | ) | | $ | 198 | | | $ | 239 | | | $ | 47 | | | $ | 22 | | | $ | 18 | | | $ | - | | | $ | 326 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Identifiable and total assets (2) | | $ | 4,805 | | | $ | 253 | | | $ | 1,361 | | | $ | 306 | | | $ | (134 | ) | | $ | 6,591 | | | $ | 4,992 | | | $ | 271 | | | $ | 1,007 | | | $ | 322 | | | $ | (88 | ) | | $ | 6,504 | |
Goodwill | | $ | 406 | | | $ | - | | | $ | - | | | $ | 14 | | | $ | - | | | $ | 420 | | | $ | 404 | | | $ | - | | | $ | - | | | $ | 14 | | | $ | - | | | $ | 418 | |
Capital expenditures for property, plant and equipment | | $ | 123 | | | $ | 7 | | | $ | - | | | $ | 29 | | | $ | 7 | | | $ | 166 | | | $ | 196 | | | $ | 7 | | | $ | - | | | $ | 44 | | | $ | 7 | | | $ | 254 | |
(1) | Intercompany revenues – wholesale services records its energy marketing and risk management revenues on a net basis, which includes intercompany revenues of $92$75 million and $303$289 million for the three months ended JuneSeptember 30, 2009 and 2008, respectively; and $257$332 million and $517$806 million for the sixnine months ended JuneSeptember 30, 2009 and 2008, respectively. |
(2) | Identifiable assets are those used in each segment’s operations. |
(3) | Our corporate segment’s assets consist primarily of cash and cash equivalents, property, plant and equipment and reflect the effect of intercompany eliminations. |
In May 2009, the FASB issued SFAS 165, which is effective for reporting periods ending after June 15, 2009. SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the statement of financial position date, but before financial statements are issued, or are available to be issued. Prior to SFAS 165, guidance relating to subsequent events was contained in AU Section 560, “Subsequent Events,” (AU 560) of the auditing literature, which was primarily directed toward auditors, not management. SFAS 165 should be applied by management to the accounting for and disclosure of subsequent events, but does not apply to subsequent events or transactions that are within the scope of other applicable GAAP that provide different guidance. In accordance with SFAS 165, we evaluated subsequent events until the time that our financial statements were issued and filed with the SEC on July 30, 2009, and identified the following subsequent events.
In March 2009, Piedmont filed a lawsuit in the Court of Chancery of the State of Delaware against us asking the court to enter a judgment declaring that our right to purchase Piedmont’s ownership interest in SouthStar expires on November 1, 2009. We have reached a settlement agreement that will dismiss the lawsuit and will result in a restructuring of the ownership interests in the SouthStar joint venture. Under the terms of the agreement, which has been approved by the boards of directors of both companies, we will purchase an additional 15% ownership share in the joint venture from Piedmont for $58 million. As a result, we will own 85% of the SouthStar joint venture, and will be entitled to 85% of the annual earnings from the business, while Piedmont will retain the remaining 15% share. As part of the agreement, our interest will remain a noncontrolling interest and we will not have any further option rights to Piedmont’s remaining 15% ownership interest. The effective date of the transaction will be January 1, 2010, and the agreement is subject to approval by the Georgia Commission.
In July 2009, Atlanta Gas Light filed a request with the Georgia Commission to postpone its scheduled filing of a rate case in November 2009 until as late as June 2010. In July 2009, the Georgia Commission approved the request to postpone the filing until April 1, 2010, but no later than June 1, 2010.
Certain expectations and projections regarding our future performance referenced in this Management’s Discussion and Analysis of Financial Condition and Results of Operations section and elsewhere in this report, as well as in other reports and proxy statements we file with the SEC or otherwise release to the public and on our website are forward-looking statements. Senior 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, and because these statements involve anticipated events or conditions, forward-looking statements often include words such as "anticipate," "assume," “believe,” "can," "could," "estimate," "expect," "forecast," "future," “goal,” "indicate," "intend," "may," “outlook,” "plan," “potential,” "predict," "project,” "seek," "should," "target," "would," or similar expressions. You are cautioned not to place undue reliance on our forward-looking statements. Our expectations are not guarantees 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 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 our 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 including any changes related to climate change; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; the impact on cost and timeliness of construction projects by government and other approvals, development project delays, adequacy of supply of diversified vendors, unexpected change in project costs, including the cost of funds to finance these projects; the impact of acquisitions and divestitures; direct or indirect effects on our 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, including recent disruptions in the capital markets and lending environment and the current economic downturn; and general economic conditions; uncertainties about environmental issues and the related impact of such issues; the impact of changes in weather, including climate change, on the temperature-sensitive portions of our 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 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 Item 1A, “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2008, among others, could cause our business, results of operations or financial condition in 2009 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 our Form 10-K or 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. We do not update these statements to reflect subsequent circumstances or events.
We are an energy services holding company whose principal business is the distribution of natural gas through our regulated natural gas distribution business and the sale of natural gas to end-use customers primarily in Georgia through our retail natural gas marketing business. As of JuneSeptember 30, 2009, our six utilities serve approximately 2.3 million end-use customers, making us the largest distributor of natural gas in the southeastern and mid-Atlantic regions of the United States based on customer count. Although our retail natural gas marketing business is not subject to the same regulatory framework as our utilities, it is an integral part of the framework for providing natural gas service to end-use customers in Georgia.
We also engage in natural gas asset management and related logistics activities for our own utilities as well as for non-affiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability underground natural gas storage assets. 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 profit-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 company. We manage these businesses through four operating segments - distribution operations, retail energy operations, wholesale services, energy investments and a non-operating corporate segment.
We intend to continue executing our plan for long-term earnings and dividend growth. Central to that plan is the execution of our regulatory planning through the filing of rate cases and other regulatory requests to recover the investments we have made, and should continue to make, to enhance our infrastructure and improve customer service. Further, we are collaborating with regulatory agencies and other companies to promote and encourage conservation through innovative rate design mechanisms that we believe are positioning our utility businesses to benefit in an economic recovery.
We continue to explore select opportunities to expand our businesses in strategic areas and maintain a disciplined approach around current capital projects. Our major capital projects - our Golden Triangle Storage natural gas storage facility project and our Hampton Roads Crossing and Magnolia pipeline connection projects - are on scheduleexpected to be completed by year-end and be within budget. In these challenging economic conditions, we continue to aggressively focus on capital discipline and cost control, while moving ahead with projects and initiatives that we expect to have current and future benefits and provide an appropriate return on capital.
During the last half of 2008 and continuing into 2009, natural gas prices declined significantly, reflecting the decline in the United States economy, increasing natural gas supplies and above-average storage volumes, among other factors. These lower gas prices resulted in significantly lower levels of working capital necessary for our operating segments to purchase their natural gas inventories as compared to recent inventory injection seasons. We may experience increased pressure on our working capital requirements and borrowing capacity under our existing Credit Facility should natural gas prices return to levels experienced in 2008.
Our distribution operations segment is the largest component of our business and includes six natural gas local distribution utilities. These utilities construct, manage and maintain intrastate natural gas pipelines and distribution facilities and include:
· | Atlanta Gas Light in Georgia |
· | Chattanooga Gas in Tennessee |
· | Elizabethtown Gas in New Jersey |
· | Florida City Gas in Florida |
· | Virginia Natural Gas in Virginia |
Each utility operates subject to regulations of the state regulatory agencies 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 generally should allow us to recover all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return for our shareholders. Rate base generally consists of the original cost of utility plant in service, working capital and certain other assets; less accumulated depreciation on utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.
Customer growth declined slightly in our distribution operations segment in the first sixnine months of 2009 relative to last year, a trend we expect to continue through the end of 2009. For the sixnine months ended JuneSeptember 30, 2009, our year-over-year consolidated utility customer growth rate was slightly negative or (0.3)%, compared to 0.3%0.1% positive growth for the same period of 2008. We anticipate overall customer growth in 2009 to be flat to negative, primarily as a result of much slower growth in the residential housing markets throughout most of our service territories and the effects of a weak economy on our commercial and industrial customers. Over the lastAs compared to 3 years ago, we have reduced our customer attrition rates. As a result, we believe we should be well positioned when the economy recovers.
The weak economy also impactedis expected to continue to impact a significantly larger portion of consumer household incomes during the most recentupcoming winter heating season. As aHowever, natural gas prices and the WACOG of our natural gas inventories have declined significantly since last year, which is expected will result we incurred additionalin lower average customer bills and no significant increases in our bad debt expense and increased customer conservation. We expect these factors may continue to adversely impact our results of operations during the current economic situation. However, we expect operational and collections efforts combined with regulatory mechanisms in place in most of our jurisdictions to help mitigate some of our exposure to these factors.
The 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. In addition, customers in Georgia buy their natural gas from Marketers rather than from Atlanta Gas Light. Our credit exposure at Atlanta Gas Light is primarily related to the provision of services to the Marketers, but that exposure is mitigated, because we obtain security support in an amount equal to a minimum of no less than two times a Marketer’s highest month’s estimated bill. At our other utilities, while customer conservation could adversely impact our operating margins, we utilize measures to collect delinquent accounts and continue to be rigorous in monitoring and mitigating the impact of these expenses. Due to the timing of usage and billing, the full effects of the most recent heating season will not be known until several months following the end of the heating season.
We workedwork with regulators and state agencies in each of our jurisdictions to educate customers about higher energy costs in advance of the winter heating season, in particular, to ensure that those customers qualifiedqualifying for the Low Income Home Energy Assistance Program and other similar programs receive any needed assistance and we expect to continue this focus for the foreseeable future.
Distribution Operations - regulatory planning
In 2010 and 2011, we expect to file base rate cases in three of our six jurisdictions. Over the past several years our utilities have been fulfilling their long-term commitments to rate freezes, which beginbegan expiring in 2009. As these rate cases are filed, we plan to seek rate reforms that encourage conservation and “decoupling.” In traditional rate designs, our utilities’ recovery of a significant portion of their fixed customer service costs is tied to assumed natural gas volumes used by our customers. We believe separating, or decoupling, the recovery of these fixed costs from the natural gas deliveries will align the interests of our customers and utilities by encouraging energy conservation, achieving rate stability for our customers and ensuring stable returns for our shareholders. These rate case filings are required due to settlements we reached with the applicable state authority in previous rate case or acquisition proceedings. The expected filing dates and dates for which current rates are expected to be effective are outlined in the chart below:
Company | | Expected filing date (2) | | | Current rates effective until | |
Atlanta Gas Light (1) | | | Q2 2010 | | | | Q2Q4 2010 | |
Virginia Natural Gas | | | Q2 2010 | | | | Q3 2011 | |
Chattanooga Gas | | | Q2 2010 | | | | Q1 2011 | |
Virginia Natural Gas | | | Q1 2011 | | | | Q3 2011 | |
(1) | In July 2009, Atlanta Gas Light filed a request with the Georgia Commission to postpone its scheduled filing of a rate case in November 2009. This2009.This request was approved by the Georgia Commission which agreed to postpone the filing until April 1, 2010, but no later than June 1, 2010. |
Elizabethtown Gas After a 5-year rate freeze and in accordance with the New Jersey Commission’sBPU’s order, we filed a rate case in March 2009 with a proposed effective date of January 1, 2010. Our initial request was an annual increase to base rates of $25 million. The filing also included energy conservation programs and a proposed Efficiency Usage and Adjustment mechanism (EUA), which is a form of decoupling, including weather normalization. In traditional rate designs, our utilities’ recovery of a significant portion of their fixed customer service costs is tied to assumed natural gas volumes used by our customers. We believe separating, or decoupling, the recovery of these fixed costs from the natural gas deliveries will align the interests of our customers and utilities by encouraging energy conservation, achieving rate stability for our customers and ensuring stable returns for our shareholders. If the EUA is approved, the current weather normalization clause would be suspended.
In June 2009, and in accordance with New Jersey rate case rules that require the filing of quarterly updates to a case, we filed a revised request for a $17 million annual increase to base rates. The primary driver of the reduced request was a revision to our depreciation rates. Our revised requested increase consists of:
· | increased carrying costs associated with increased rate base ($9 million) |
· | increased operating expenses, including higher bad debt expenses and other ($5 million) |
· | increased return on equity from 10% to 11.25% and return on rate base from 7.95% to 8.41% ($3 million) |
In August 2009, the New Jersey Department of the Public Counsel, Division of Rate Counsel (Rate Counsel) filed testimony recommending a base rate decrease of $13 million. We are currently in settlement discussions with the Rate Counsel and the New Jersey BPU’s staff, and we expect all parties to come to an acceptable agreement that will be considered by the New Jersey BPU before the end of 2009.
Distribution Operations - capital projects
In June 2009, Atlanta Gas Light filed a request for a Strategic Infrastructure Development and Enhancement (STRIDE) program with the Georgia Commission to upgrade its distribution system and liquefied natural gas facilities to improve system reliability and create a platform to meet operational flexibility needs and forecasted growth. Under the program, Atlanta Gas Light would be required to file a ten-year infrastructure plan every three years for review and approval by the Georgia Commission. The program merges with Atlanta Gas Light’s existing Pipeline Replacement Program (PRP), which was initiated in 1998 and is scheduled to end in December 2013.
In October 2009, the Georgia Commission approved the initial three years of the STRIDE program, estimated at approximately $176 million, which will increase the existing $1.95 monthly PRP charge for Atlanta Gas Light’s customers by $0.39 beginning in October 2009. Beginning October 2010, the rates will increase by an additional $0.39 for a total of $0.78 per month, and beginning in October 2011, the rates will increase by an additional $0.40 per month for a total of $1.18 per month. The increased charges are subject to review and modification by the Georgia Commission every three years. Further, in October 2009 and subsequent to the Georgia Commission’s approval of the STRIDE program, an organization representing members in Georgia has filed a Motion for Reconsideration of the order approving the program with the Georgia Commission, as well as an appeal to the State Superior Court for a review of the Georgia Commission’s ruling that the organization did not have discovery rights in the STRIDE program proceeding. Pursuant to the Georgia Commission’s approval order, neither of these filings prevents the STRIDE program from going into effect. We cannot predict what action, if any, the Georgia Commission or the State Superior Court will take in response to these filings. For more information on Atlanta Gas Light’s PRP program, see Note 1 in our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.
In April 2009, the New Jersey CommissionBPU approved an accelerated $60 million enhanced infrastructure program for Elizabethtown Gas which is expected to startstarted this year and is scheduled to be completed in 2011. This program was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. A regulatory cost recovery mechanism will be established with estimated rates put into effect at the beginning of each year. At the end of the program the regulatory cost recovery mechanism will be trued-up and any remaining costs not previously collected will be included in base rates. Elizabethtown Gas expects that approximately $20$18 million in capital expenditures for this program will occur in 2009.
In June 2009, Atlanta Gas Light filed a request for a Strategic Infrastructure Development and Enhancement (STRIDE) program with the Georgia Commission to upgrade its distribution system and liquefied natural gas facilities to improve system reliability and create a platform to meet operational flexibility needs and forecasted growth. Under the program, Atlanta Gas Light would be required to file a ten-year infrastructure plan every three years for review and approval by the Georgia Commission. Atlanta Gas Light is seeking approval of the initial three years of the program through 2012, which includes infrastructure improvements of approximately $176 million.
In July 2009, the Georgia Commission established a procedural schedule to consider our STRIDE program request. Under such schedule, we expect a decision by the end of this year. If approved, the program would merge with Atlanta Gas Light’s existing Pipeline Replacement Program (PRP), which was initiated in 1998 and is scheduled to end in December 2013. Under the proposed STRIDE program, the existing $1.95 monthly PRP charge for residential customers would increase by 95 cents beginning in October 2009. Small commercial customers, who pay $5.85 per month under the current PRP rate design set by the Georgia Commission, would pay an additional $2.85 per month. The increased charges would be in effect subject to review and modification by the Georgia Commission every three years. For more information on Atlanta Gas Light’s PRP program, see Note 1 in our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.
Our retail energy operations segment consists of SouthStar, a joint venture currently owned 70% by us and 30% by Piedmont. SouthStar markets natural gas and related services to retail customers on an unregulated basis, principally in Georgia, as well as to commercial and industrial customers in Alabama, Florida, Ohio, Tennessee, North Carolina and South Carolina. SouthStar is the largest marketer of natural gas in Georgia with an approximate 33% market share based on customer count.
Although our ownership interest in the SouthStar partnership is currently 70%, the majority of SouthStar's earnings in Georgia are currently allocated, by contract, 75% to us and 25% to Piedmont. SouthStar’s earnings related to customers in Ohio and Florida are currently allocated 70% to us and 30% to Piedmont. We record the earnings allocated to Piedmont as a noncontrolling interest in our condensed consolidated statements of income, and we record Piedmont’s portion of SouthStar’s capital as a noncontrolling interest in our condensed consolidated statements of financial position. The majority of SouthStar’s earnings allocated to us for the three and sixnine months ended JuneSeptember 30, 2009, were largely at the 75% contractual rate.
In March 2009, Piedmont filed a lawsuit in the Court of Chancery of the State of Delaware against us asking the court to enter a judgment declaring that our right to purchase Piedmont’s ownership interest in SouthStar expires on November 1, 2009. We have reached a settlement agreement with Piedmont that will dismissdismissed the lawsuit and will result in a restructuring of the ownership interests in the SouthStar joint venture. Under the terms of the agreement, which has been approved by the boards of directors of both companies, we will purchase an additional 15% ownership share in the joint venture from Piedmont for $58 million. As a result, we will own 85% of the SouthStar joint venture, and will be entitled to 85% of the annual earnings from the business, while Piedmont will retain the remaining 15% share. As part of the agreement, our interest will remain a noncontrolling interest and we will not have any further option rights to Piedmont’s remaining 15% ownership interest. The agreement was approved by the Georgia Commission in October 2009 and the effective date of the transaction will be January 1, 2010, and the agreement is subject to approval by the Georgia Commission.
2010.
SouthStar’s operations are sensitive to seasonal weather, natural gas prices, retail pricing plans and strategies, customer growth and consumption patterns similar to those affecting our utility operations. SouthStar’s retail pricing strategies and use of various economic hedging strategies, such as futures, options, swaps, weather derivative instruments and other risk management tools, help to ensure retail customer costs are covered to mitigate the potential effect of these issues on its operations.
In the Georgia market, SouthStar continues to experience the negative impact to operating margins from increased competition and an increase in the number of customers shopping for lower retail natural gas prices. Further, the number of customers switching Marketers in the Georgia market has increased in part due to customers seeking the most competitive price plans.
SouthStar continues to use a variety of targeted marketing programs to attract new customers and to retain existing ones. Despite these efforts we have seen a 4% decline in average customer count and a 6% decline in market share for the sixnine months ended JuneSeptember 30, 2009, as compared to the same period of 2008. We believe this decline reflects some of the same economic conditions that have affected our utility businesses as well as the more competitive retail pricing market for natural gas in Georgia.
SouthStar may also be affected by the conservation and bad debt trends, but its overall exposure is partially mitigated by the high credit quality of SouthStar’s customer base, lower wholesale natural gas prices in 2009, disciplined collection practices and the unregulated pricing structure in Georgia.
SouthStar continues to expand its business in other states as well. We are currently focusing these efforts on the Ohio and Florida markets, which are growing more rapidly than anticipated.markets.
Our wholesale services segment consists primarily of Sequent, our subsidiary involved in asset management and optimization, storage, transportation, producer and peaking services and wholesale marketing. Sequent seeks asset optimization opportunities, which focus on capturing the value from idle or underutilized assets, typically by participating in transactions to take advantage of pricing differences between varying markets and time horizons within the natural gas supply, storage and transportation markets to generate earnings. These activities are generally referred to as arbitrage opportunities.
Sequent’s profitability is driven by volatility in the natural gas marketplace. Volatility arises from a number of factors such as weather fluctuations or the change in supply of, or demand for, natural gas in different regions of the United States. Sequent seeks to capture value from the price disparity across geographic locations and various time horizons (location and seasonal spreads). In doing so, Sequent also seeks to mitigate the risks associated with this volatility and protect its margin through a variety of risk management and economic hedging activities.
Sequent provides its customers with natural gas from the major producing regions and market hubs in the United States and Canada. Sequent acquires 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 other alternatives available to its customers.
During the third quarter of 2008, Sequent negotiated an agreement for 0.04 Bcf per day of transportation capacity for a period of 25 years beginning in August 2009. This agreement was executed in April 2009, and as a result, we have included approximately $89 million of future demand payments associated with this capacity within our unrecorded contractual obligations and commitment disclosures. As with its other transportation capacity agreements, Sequent has and will identify opportunities to lock-in economic value associated with this capacity through the use of financial hedges. Since the duration of this agreement is significantly longer than the average duration of Sequent’s portfolio, the hedging of the capacity has increased our exposure to hedge gains and losses as well as impacting Sequent’s VaR.
During the second half of 2008, we began executing hedging transactions related to this transportation capacity. As a result of changes in the fair value of these hedges, Sequent reported no hedge gains of $4 millionduring the three months ending September 30, 2009 and $22 million during the three and sixnine months ending JuneSeptember 30, 2009. There was no significant impact to VaR during these periods.For transportation-related hedge gains or losses, no corresponding loss or gain is recognized on the hedged transportation transactions since the underlying transportation contracts are not recorded at fair value. The gains or losses on the transportation agreements would be recognized in the period they are realized, which is the period the transportation capacity is available for our use.
Asset management transactions Sequent’s asset management customers include affiliated utilities, nonaffiliated utilities, municipal utilities, power generators and large industrial customers. These customers, due to seasonal demand or levels of activity, may have contracts for transportation and storage capacity, which may exceed their actual requirements. Sequent enters into structured agreements with these customers, whereby Sequent, on behalf of the customer, optimizes the transportation and storage capacity during periods when customers do not use it for their own needs. Sequent may capture incremental operating margin through optimization, and either share margins with the customers or pay them a fixed amount.
The following table provides updated information on Sequent’s asset management agreements with its affiliated utilities, including amended or extended agreements in 2008 and 2009 with Florida City Gas, Chattanooga Gas, Elizabethtown Gas and Virginia Natural Gas.
| Expiration | | % of shared | |
| Expiration date | | profits or annual fee | |
Chattanooga Gas | March 2011 | | | 50% (A) | |
Elizabethtown Gas | March 2011 | | (A) (B) | |
Atlanta Gas Light | March 2012 | | up to 60% (A) | |
Virginia Natural Gas | March 2012 | | (A) (B) | |
Florida City Gas | March 2013 | | | 50% | |
(A) | Includes aggregate annual minimum payments of $14 million for Atlanta Gas Light, Chattanooga Gas, Elizabethtown Gas and Virginia Natural Gas. |
(B) | Shared on a tiered structure. |
Storage inventory outlook The following graph presents the NYMEX forward natural gas prices as of JuneSeptember 30, 2009, March 31,June 30, 2009 and December 31, 2008, for the period of JulyOctober 2009 through JuneSeptember 2010, and reflects the prices at which Sequent could buy natural gas at the Henry Hub for delivery in the same time period. The Henry Hub is the largest centralized point for natural gas spot and futures trading in the United States. The 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.
During the last half of 2008 and continuing into 2009, natural gas prices declined significantly, reflecting the decline in the United States economy, increasing natural gas supplies and above-average storage volumes, among other factors. These lower gas prices resulted in significantly lower levels of working capital necessary for Sequent to purchase its natural gas inventories as compared to 2008, which saw significantly higher prices.
Sequent’s expected natural gas withdrawals from physical salt dome and reservoir storage are presented in the following table along with the operating revenues expected at the time of withdrawal. Sequent’s expected operating revenues are net of the estimated impact of regulatory sharing and reflect the amounts that are realizable in future periods based on its inventory withdrawal schedule and forward natural gas prices at JuneSeptember 30, 2009. Sequent’s storage inventory is economically hedged with futures contracts, which results in an overall locked-in margin, timing notwithstanding.
| | | | | Withdrawal schedule (in Bcf) | | | Withdrawal schedule (in Bcf) | | | | |
| | Salt dome (WACOG $3.65) | | | Reservoir (WACOG $3.38) | | | Expected operating revenues (in millions) | | | Salt dome (WACOG $3.48) | | | Reservoir (WACOG $3.36) | | | Expected operating revenues (in millions) | |
2009 | | | | | | | | | | | | | | | | | | |
Third quarter | | | 1 | | | | 7 | | | $ | 2 | | |
Fourth quarter | | | 3 | | | | 6 | | | | 12 | | | | 3 | | | | 11 | | | $ | 23 | |
2010 | | | | | | | | | | | | | | | | | | | | | | | | |
First quarter | | | - | | | | 5 | | | | 8 | | | | - | | | | 10 | | | | 18 | |
Second quarter | | | - | | | | 1 | | | | 1 | | | | - | | | | 1 | | | | 3 | |
Third quarter | | | | - | | | | 1 | | | | 1 | |
Total | | | 4 | | | | 19 | | | $ | 23 | | | | 3 | | | | 23 | | | $ | 45 | |
If Sequent’s storage withdrawals associated with existing inventory positions are executed as planned, it expects operating revenues from storage withdrawals of approximately $23$45 million during the next twelve months. This could change as Sequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months and as forward NYMEX prices fluctuate. Based upon Sequent’s current projection of year-end storage positions at December 31, 2009, a $1.00 increase in the first quarter 2010 forward NYMEX prices could result in a $9 million reduction to Sequent’s reported operating revenues for the year ending December 31, 2009, after regulatory sharing. A $1.00 decrease in forward NYMEX prices would result in a $9 million positive impact to Sequent’s reported operating revenues; however additional LOCOM adjustments could potentially offset a portion of the positive impact. This amount does not include operating expenses that will be incurred to realize this amount.For more information on Sequent’s energy marketing and risk management activities, see Item 3, Quantitative and Qualitative Disclosures About Market Risk - Natural Gas Price Risk.
Our energy investments segment includes a number of businesses that are related or complementary to our primary business. The most significant of these businesses is our natural gas storage business, Jefferson Island, which operates a high-deliverability salt-dome storage facility in the Gulf Coast region of the U.S. While our salt-dome storage business also can generate additional revenue during times of peak market demand for natural gas storage services, the majority of its storage services are covered under medium to long-term contracts at a fixed market rate.
We are actively pursuing litigation againsta settlement with the State of Louisiana to obtain a court order or settlement confirmingcomplete an operating agreement allowing Jefferson Island’s rightIsland to expand its existing facility. In August 2009, Jefferson Island announced that it had negotiated a tentative agreement with the state of Louisiana that, subject to approval, would resolve the pending lawsuit between the parties over a disputed mineral lease. A finalized agreement will enable Jefferson Island to resume its plan to expand the existing natural gas storage facility. The state Mineral Board must approve the agreement in order for it to be valid, and a decision could come within the fourth quarter of 2009. The parties also jointly requested that the trial court delay the previously scheduled September 2009 trial date which would have resolved Jefferson Island’s claim that it is authorized to expand the facility under its mineral lease while the parties work through this approval process. The ultimate resolution cannot be determined, but it is not expected to have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
Jefferson Island’s litigation with the State of Louisiana is described in further detail in Note 7 in our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009. In April 2009, the trial court ruled that the legislation restricting water usage from the Chicot aquifer to expand its existing storage facility is unconstitutional and invalid. In addition, the court scheduled a trial for September 28, 2009 on Jefferson Island’s claim that it is authorized to expand the facility under its mineral lease. The ultimate resolution of such trial cannot be determined, but it is not expected to have a material adverse effect on our consolidated financial condition, results of operations or cash flows
Our Golden Triangle Storage project will consist of a new salt-dome storage facility in the Gulf Coast region of the U.S. with 12 Bcf of working natural gas capacity and total cavern capacity of 1718 Bcf. In May 2008, Golden Triangle Storage started construction on both caverns. We expect the first cavern with 6 Bcf of working capacity to be in service in the third or fourth quarter of 2010 and the second cavern with 6 Bcf of working capacity to be in service in the second quarter ofmid 2012.
We previously estimated, based on then current prices for labor, materials and pad gas that costs to construct the two caverns would be approximately $265 million. However, prices for labor and materials have risen significantly in the ensuing months, increasing the estimated construction cost by approximately 10%18% to 20%.$314 million. The actual project costs depend upon the facility’s configuration, materials, drilling costs, financing costs and the amount and cost of pad gas, which includes volumes of non-working natural gas used to maintain the operational integrity of the cavern facility. The costs for approximately 49%70% of these items have not been fixed and are not subject to continued variability during the period of construction.construction period. Further, since we are not able to predict whether these costs of construction will continue to increase, moderate or decrease from current levels, we believe that there could be continued volatility in the construction cost estimates.
We also own and operate a telecommunications business, AGL Networks, which constructs and operates conduit and fiber infrastructure within select metropolitan areas in the United States.
Our corporate segment includes our nonoperating business units, including AGL Services Company and AGL Capital.
We allocate substantially all of our corporate segment’s operating expenses and interest costs to our operating segments in accordance with state regulations. Our corporate segment results include the impact of these allocations to the various operating segments. Our corporate segment also includes intercompany eliminations for transactions between our operating segments.
Operating margin and EBITWe evaluate segment performance using the measures of operating margin and EBIT, which include the effects of corporate expense allocations. Our operating margin and EBIT are not measures that are considered to be calculated in accordance with GAAP. Operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of gas, which excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain or loss on the sale of our assets; these items are included in our calculation of operating income as reflected in our condensed consolidated statements of income. EBIT is also a non-GAAP measure that includes operating income, other income and expenses. Items that we do not include in EBIT are financing costs, including interest and debt expense and income taxes, each of which we evaluate on a consolidated level.
We believe operating margin is a better indicator than operating revenues for the contribution resulting from customer growth in our distribution operations segment since the cost of gas can vary significantly and is generally billed 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 operating margin 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.
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 attributable to AGL Resources Inc. as determined in accordance with GAAP. In addition, our operating margin or EBIT measures may not be comparable to similarly titled measures from other companies.
Income taxes As a result of our adoption of SFAS 160,new authoritative guidance related to consolidations, income tax expense and our effective tax rate are determined from earnings before income tax less net income (loss) attributable to the noncontrolling interest. For more information on our adoption of SFAS 160,this guidance, see Note 5.
Seasonality The operating revenues and EBIT of our distribution operations, retail energy operations and wholesale services segments are seasonal. During the heating season, natural gas usage and operating revenues are generally higher because more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather than in periods of warmer weather. Occasionally in the summer, Sequent’s operating margins are impacted due to peak usage by power generators in response to summer energy demands. 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 statement of financial position items, such as receivables, inventories and short-term debt across quarters. However, these items are comparable when reviewing our annual results. Accordingly, we have presented the condensed consolidated statement of financial position as of JuneSeptember 30, 2008, to provide comparisons of these items to December 31, 2008, and JuneSeptember 30, 2009.
Hedging Changes in natural gas prices subject a significant portion of our operations to earnings variability. Our nonutility businesses principally use physical and financial arrangements economically to hedge the risks associated with seasonal fluctuations in market conditions, changing natural gas prices and weather. In addition, because these economic hedges may not qualify, or are not designated, for hedge accounting treatment, our reported earnings for the wholesale services and retail energy operations segments include the changes in the fair values of certain financial derivatives. These values may change significantly from period to period and are reflected as fair value adjustments within our operating margin.
Elizabethtown Gas utilizes certain financial derivatives in accordance with a directive from the New Jersey CommissionBPU to create a hedging program to hedge the impact of market fluctuations in natural gas prices. These derivative products are accounted for at fair value each reporting period. In accordance with regulatory requirements, realized gains and losses related to these financial derivatives are reflected in deferred natural gas costs and ultimately included in billings to customers. Unrealized gains and losses are reflected as a regulatory asset or liability, as appropriate, in our condensed consolidated statements of financial position.
The following table sets forth a reconciliation of our operating margin and EBIT to our operating income, earnings (loss) before income taxes and net income (loss) attributable to AGL Resources Inc., together with other consolidated financial information for the three and sixnine months ended JuneSeptember 30, 2009 and 2008.
| | Three months ended June 30, | | | Six months ended June 30, | | Three months ended September 30, | | | Nine months ended September 30, | |
In millions, except per share data | In millions, except per share data | 2009 | | | 2008 | | | Change | | | 2009 | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
Operating revenues | | $ | 377 | | | $ | 444 | | | $ | (67 | ) | | $ | 1,372 | | | $ | 1,456 | | | $ | (84 | ) | | $ | 307 | | | $ | 539 | | | $ | (232 | ) | | $ | 1,679 | | | $ | 1,995 | | | $ | (316 | ) |
Cost of gas | | | 152 | | | | 275 | | | | (123 | ) | | | 741 | | | | 932 | | | | (191 | ) | | | 99 | | | | 261 | | | | (162 | ) | | | 840 | | | | 1,193 | | | | (353 | ) |
Operating margin (1) | | | 225 | | | | 169 | | | | 56 | | | | 631 | | | | 524 | | | | 107 | | | | 208 | | | | 278 | | | | (70 | ) | | | 839 | | | | 802 | | | | 37 | |
Operating expenses | | | 170 | | | | 163 | | | | 7 | | | | 346 | | | | 330 | | | | 16 | | | | 165 | | | | 152 | | | | 13 | | | | 511 | | | | 482 | | | | 29 | |
Operating income | | | 55 | | | | 6 | | | | 49 | | | | 285 | | | | 194 | | | | 91 | | | | 43 | | | | 126 | | | | (83 | ) | | | 328 | | | | 320 | | | | 8 | |
Other income | | | 3 | | | | 3 | | | | - | | | | 5 | | | | 4 | | | | 1 | | | | 2 | | | | 2 | | | | - | | | | 7 | | | | 6 | | | | 1 | |
EBIT (1) | | | 58 | | | | 9 | | | | 49 | | | | 290 | | | | 198 | | | | 92 | | | | 45 | | | | 128 | | | | (83 | ) | | | 335 | | | | 326 | | | | 9 | |
Interest expense, net | | | 24 | | | | 26 | | | | (2 | ) | | | 49 | | | | 56 | | | | (7 | ) | | | 26 | | | | 29 | | | | (3 | ) | | | 75 | | | | 85 | | | | (10 | ) |
Earnings (loss) before income taxes | | | 34 | | | | (17 | ) | | | 51 | | | | 241 | | | | 142 | | | | 99 | | |
Income tax expense (benefit) | | | 13 | | | | (7 | ) | | | 20 | | | | 85 | | | | 47 | | | | 38 | | |
Net income (loss) | | | 21 | | | | (10 | ) | | | 31 | | | | 156 | | | | 95 | | | | 61 | | |
Net income attributable to the noncontrolling interest | | | 1 | | | | 1 | | | | - | | | | 17 | | | | 17 | | | | - | | |
Net income (loss) attributable to AGL Resources Inc. | | $ | 20 | | | $ | (11 | ) | | $ | 31 | | | $ | 139 | | | $ | 78 | | | $ | 61 | | |
Earnings before income taxes | | | | 19 | | | | 99 | | | | (80 | ) | | | 260 | | | | 241 | | | | 19 | |
Income tax expense | | | | 7 | | | | 39 | | | | (32 | ) | | | 92 | | | | 86 | | | | 6 | |
Net income | | | | 12 | | | | 60 | | | | (48 | ) | | | 168 | | | | 155 | | | | 13 | |
Net (loss) income attributable to the noncontrolling interest | | | | - | | | | (5 | ) | | | (5 | ) | | | 17 | | | | 12 | | | | 5 | |
Net income attributable to AGL Resources Inc. | | | $ | 12 | | | $ | 65 | | | $ | (53 | ) | | $ | 151 | | | $ | 143 | | | $ | 8 | |
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Earnings (loss) per common share | | | | | | | | | | | | | | | | | | | | | | | |
Earnings per common share | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic – attributable to AGL Resources Inc. common shareholders | | $ | 0.26 | | | $ | (0.15 | ) | | $ | 0.41 | | | $ | 1.81 | | | $ | 1.02 | | | $ | 0.79 | | | $ | 0.16 | | | $ | 0.85 | | | $ | (0.69 | ) | | $ | 1.97 | | | $ | 1.87 | | | $ | 0.10 | |
Diluted – attributable to AGL Resources Inc. common shareholders | | $ | 0.26 | | | $ | (0.15 | ) | | $ | 0.41 | | | $ | 1.81 | | | $ | 1.01 | | | $ | 0.80 | | | $ | 0.16 | | | $ | 0.85 | | | $ | (0.69 | ) | | $ | 1.97 | | | $ | 1.87 | | | $ | 0.10 | |
Weighted-average number of common shares outstanding | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | | 76.7 | | | | 76.2 | | | | 0.5 | | | | 76.8 | | | | 76.2 | | | | 0.6 | | | | 76.9 | | | | 76.4 | | | | 0.5 | | | | 76.7 | | | | 76.2 | | | | 0.5 | |
Diluted | | | 76.9 | | | | 76.2 | | | | 0.7 | | | | 76.9 | | | | 76.4 | | | | 0.5 | | | | 77.2 | | | | 76.6 | | | | 0.6 | | | | 76.9 | | | | 76.5 | | | | 0.4 | |
(1) | These are non-GAAP measurements. |
For the secondthird quarter of 2009, net income attributable to AGL Resources Inc. increaseddecreased by $31$53 million or 82% and earnings per share attributable to AGL Resources Inc. increaseddecreased by $0.41$0.69 per basic and diluted share compared to the same period last year. The variance betweenwas primarily the two quartersresult of lower operating margins at wholesale services and corporate, offset by higher operating margins at retail energy operations, distribution operations and energy investments. Our operating expenses were higher primarily due to increased pension and postretirement benefit costs, payroll and incentive compensation and depreciation expenses at distribution operations.
For the nine months ended September 30, 2009, net income attributable to AGL Resources Inc. increased by $8 million or 6% and earnings per share attributable to AGL Resources Inc. increased by $0.10 per basic and diluted share compared to the same period last year. The variance was primarily the result of higher operating margins at distribution operations, and wholesale services, offset by lower operating margins atretail energy investments. Additionally, this increase was offset by higher operating expenses due to increased environmental remediation costs, pension and postretirement benefit costs and depreciation expenses at distribution operations.
For the six months ended June 30, 2009, net income attributable to AGL Resources Inc. increased by $61 million and earnings per share attributable to AGL Resources Inc. increased by $0.79 per basic and $0.80 per diluted share compared to the same period last year. The variance between the two periods was primarily the result of higher operating margins at distribution operations and wholesale services offset by lower operating margins at energy investments and higher operating expenses primarily at wholesale services and distribution operations.all our segments.
Interest expense for the third quarter of 2009 decreased by $3 million or 10% from the third quarter of 2008, resulting from a decrease in short-term interest rates and lower average debt outstanding. Interest expense for the nine months ended September 30, 2009 decreased by $10 million or 12% from the same period last year, resulting from a decrease in short-term interest rates, partially offset by higher average debt outstanding. More information about our average debt and rates are indicated in the following table.
| | Three months ended September 30, | | | Nine months ended September 30, | |
In millions | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
Average debt outstanding (1) | | $ | 2,203 | | | $ | 2,225 | | | $ | (22 | ) | | $ | 2,156 | | | $ | 2,046 | | | $ | 110 | |
Average rate | | | 4.7 | % | | | 5.2 | % | | | (0.5 | )% | | | 4.6 | % | | | 5.5 | % | | | (0.9 | )% |
(1) Daily average of all outstanding debt.
Selected weather, customer and volume metrics, which we consider to be some of the key performance indicators for our operating segments, for the three and sixnine months ended JuneSeptember 30, 2009 and 2008, are presented in the following tables. We measure the effects of weather on our business through heating degree days. Generally, increased heating degree days result in greater demand for gas on our distribution systems. However, extended and unusually mild weather during the heating season can have a significant negative impact on demand for natural gas. Our marketing and customer retention initiatives are measured by our customer metrics which can be impacted by natural gas prices, economic conditions and competition from alternative fuels. Volume metrics for distribution operations and retail energy operations present the effects of weather and our customers’ demand for natural gas. Wholesale services’ daily physical sales represent the daily average natural gas volumes sold to its customers.
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Weather | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Heating degree days (1) | Heating degree days (1) | | | | | | | | | | | | | | | | | Heating degree days (1) | | | | | | |
| | Three months ended June 30, | | | 2009 vs. normal colder | | | 2009 vs. 2008 colder | | | Six months ended June 30, | | 2009 vs. normal colder | | | | | | | | Nine months ended September 30, | | | 2009 vs. normal colder | | | 2009 vs. 2008 colder |
| | Normal | | | 2009 | | | 2008 | | | (warmer) | | | | (warmer) | | Normal | | | 2009 | | | 2008 | | | | (warmer) | | | (warmer) | | | | | Normal | | | 2009 | | | 2008 | | | (warmer) | | | (warmer) |
Georgia | | | | 1,600 | | | | 1,621 | | | | 1,654 | | | | 1 | % | | | (2 | )% |
New Jersey | | | | 3,058 | | | | 3,137 | | | | 2,918 | | | | 3 | % | | | 8 | % |
Virginia | | | | 2,083 | | | | 2,247 | | | | 1,880 | | | | 8 | % | | | 20 | % |
Florida | | | 17 | | | | 21 | | | | 18 | | | | 24 | % | | | 17 | % | | | 349 | | | | 390 | | | | 215 | | | | 12 | % | | | 81 | % | | | 349 | | | | 390 | | | | 215 | | | | 12 | % | | | 81 | % |
Georgia | | | 152 | | | | 181 | | | | 144 | | | | 19 | % | | | 26 | % | | | 1,593 | | | | 1,615 | | | | 1,654 | | | | 1 | % | | | (2 | )% | |
Tennessee | | | | 1,824 | | | | 1,871 | | | | 1,888 | | | | 3 | % | | | (1 | )% |
Maryland | | | 505 | | | | 473 | | | | 471 | | | | (6 | )% | | | - | | | | 3,015 | | | | 3,085 | | | | 2,810 | | | | 2 | % | | | 10 | % | | | 3,052 | | | | 3,118 | | | | 2,828 | | | | 2 | % | | | 10 | % |
New Jersey | | | 501 | | | | 473 | | | | 475 | | | | (6 | )% | | | - | | | | 3,028 | | | | 3,100 | | | | 2,897 | | | | 2 | % | | | 7 | % | |
Tennessee | | | 176 | | | | 200 | | | | 167 | | | | 14 | % | | | 20 | % | | | 1,816 | | | | 1,864 | | | | 1,888 | | | | 3 | % | | | (1 | )% | |
Virginia | | | 277 | | | | 256 | | | | 279 | | | | (8 | )% | | | (8 | )% | | | 2,077 | | | | 2,244 | | | | 1,880 | | | | 8 | % | | | 19 | % | |
(1) Obtained from weather stations relevant to our service areas at the National Oceanic and Atmospheric Administration, National Climatic Data Center. Normal represents ten-year averages from 2000 through 2009. | (1) Obtained from weather stations relevant to our service areas at the National Oceanic and Atmospheric Administration, National Climatic Data Center. Normal represents ten-year averages from 2000 through 2009. | (1) Obtained from weather stations relevant to our service areas at the National Oceanic and Atmospheric Administration, National Climatic Data Center. Normal represents ten-year averages from 2000 through 2009. |
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Customers | | Three months ended September 30, | | | | | | Nine months ended September 30, | | | | |
| | 2009 | | | 2008 | | | % change | | | 2009 | | | 2008 | | | % change | |
Distribution Operations | | | | | | | | | | | | | | | | | | |
Average end-use customers (in thousands) | | | | | | | | | | | | | | | | | | |
Atlanta Gas Light | | | 1,525 | | | | 1,536 | | | | (0.7 | )% | | | 1,556 | | | | 1,564 | | | | (0.5 | )% |
Elizabethtown Gas | | | 272 | | | | 272 | | | | - | | | | 274 | | | | 273 | | | | 0.4 | % |
Virginia Natural Gas | | | 269 | | | | 268 | | | | 0.4 | % | | | 272 | | | | 271 | | | | 0.4 | % |
Florida City Gas | | | 103 | | | | 103 | | | | - | | | | 103 | | | | 104 | | | | (1.0 | )% |
Chattanooga Gas | | | 60 | | | | 60 | | | | - | | | | 61 | | | | 61 | | | | - | |
Elkton Gas | | | 6 | | | | 6 | | | | - | | | | 6 | | | | 6 | | | | - | |
Total | | | 2,235 | | | | 2,245 | | | | (0.4 | )% | | | 2,272 | | | | 2,279 | | | | (0.3 | )% |
Operation and maintenance expense per customer | | $ | 38 | | | $ | 32 | | | | 19 | % | | $ | 112 | | | $ | 106 | | | | 6 | % |
EBIT per customer | | $ | 21 | | | $ | 26 | | | | (19 | )% | | $ | 106 | | | $ | 105 | | | | 1 | % |
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Retail Energy Operations | | | | | | | | | | | | | | | | | | | | | | | | |
Average customers in Georgia (in thousands) | | | 496 | | | | 518 | | | | (4 | )% | | | 508 | | | | 529 | | | | (4 | )% |
Market share in Georgia | | | 33 | % | | | 34 | % | | | (3 | )% | | | 33 | % | | | 35 | % | | | (6 | )% |
| |
Volumes In billion cubic feet (Bcf) | | Three months ended September 30, | | | | | | Nine months ended September 30, | | | | |
| | 2009 | | | 2008 | | | % change | | | 2009 | | | 2008 | | | % change | |
Distribution Operations | | | | | | | | | | | | | | | | | | |
Firm | | | 20 | | | | 20 | | | | - | | | | 148 | | | | 147 | | | | 1 | % |
Interruptible | | | 23 | | | | 24 | | | | (4 | )% | | | 72 | | | | 78 | | | | (8 | )% |
Total | | | 43 | | | | 44 | | | | (2 | )% | | | 220 | | | | 225 | | | | (2 | )% |
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Retail Energy Operations | | | | | | | | | | | | | | | | | | | | | | | | |
Georgia firm | | | 3 | | | | 3 | | | | - | | | | 26 | | | | 27 | | | | (4 | )% |
Ohio and Florida | | | 1 | | | | - | | | | 100 | % | | | 8 | | | | 3 | | | | 167 | % |
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Wholesale Services | | | | | | | | | | | | | | | | | | | | | | | | |
Daily physical sales (Bcf/day) | | | 2.7 | | | | 2.6 | | | | 4 | % | | | 2.8 | | | | 2.5 | | | | 12 | % |
| |
Customers | | Three months ended | | Six months ended | |
| | June 30, | | June 30, | |
| | | 2009 | | | | 2008 | | | | % change | | | | 2009 | | | | 2008 | | | | % change | | |
Distribution Operations | | | | | | | | | | | | | | | | | | | | | | | | | |
Average end-use customers (in thousands) | | | | | | | | | | | | | | | | | | | | | | | | | |
Atlanta Gas Light | | | 1,565 | | | | 1,574 | | | | (0.6 | )% | | | 1,571 | | | | 1,578 | | | | (0.4 | )% | |
Chattanooga Gas | | | 62 | | | | 62 | | | | - | | | | 62 | | | | 62 | | | | - | | |
Elizabethtown Gas | | | 274 | | | | 273 | | | | 0.4 | % | | | 274 | | | | 274 | | | | - | | |
Elkton Gas | | | 6 | | | | 6 | | | | - | | | | 6 | | | | 6 | | | | - | | |
Florida City Gas | | | 103 | | | | 104 | | | | (1.0 | )% | | | 103 | | | | 104 | | | | (1.0 | )% | |
Virginia Natural Gas | | | 272 | | | | 272 | | | | - | | | | 274 | | | | 273 | | | | 0.4 | % | |
Total | | | 2,282 | | | | 2,291 | | | | (0.4 | )% | | | 2,290 | | | | 2,297 | | | | (0.3 | )% | |
Operation and maintenance per customer | | $ | 39 | | | $ | 36 | | | | 8 | % | | $ | 75 | | | $ | 74 | | | | 1 | % | |
EBIT per customer | | $ | 28 | | | $ | 25 | | | | 12 | % | | $ | 84 | | | $ | 78 | | | | 8 | % | |
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Retail Energy Operations | | | | | | | | | | | | | | | | | | | | | | | | | |
Average customers in Georgia (in thousands) | | | 510 | | | | 535 | | | | (5 | )% | | | 514 | | | | 535 | | | | (4 | )% | |
Market share in Georgia | | | 33 | % | | | 35 | % | | | (6 | )% | | | 33 | % | | | 35 | % | | | (6 | )% | |
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| | Three months ended | | | Six months ended | |
Volumes | | June 30, | | | June 30, | |
In billion cubic feet (Bcf) | | 2009 | | | 2008 | | | % change | | | 2009 | | | 2008 | | | % change | |
Distribution Operations | | | | | | | | | | | | | | | | | | |
Firm | | | 29 | | | | 29 | | | | - | | | | 128 | | | | 127 | | | | 1 | % |
Interruptible | | | 23 | | | | 25 | | | | (8 | )% | | | 49 | | | | 54 | | | | (9 | )% |
Total | | | 52 | | | | 54 | | | | (4 | )% | | | 177 | | | | 181 | | | | (2 | )% |
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Retail Energy Operations | | | | | | | | | | | | | | | | | | | | | | | | |
Georgia firm | | | 5 | | | | 5 | | | | - | | | | 23 | | | | 24 | | | | (4 | )% |
Ohio and Florida | | | 2 | | | | 1 | | | | 100 | % | | | 7 | | | | 3 | | | | 133 | % |
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Wholesale Services | | | | | | | | | | | | | | | | | | | | | | | | |
Daily physical sales (Bcf/day) | | | 2.6 | | | | 2.4 | | | | 8 | % | | | 2.8 | | | | 2.5 | | | | 12 | % |
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Second quarterThree months ended September 30, 2009 compared to second quarterthree months ended September 30, 2008
Segment information Operating revenues, operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the three months ended JuneSeptember 30, 2009 and 2008.
In millions | | Operating revenues | | | Operating margin (1) | | | Operating expenses | | | EBIT (1) | | | Operating margin (1) | | | Operating expenses | | | EBIT (1) | |
2009 | | | | | | | | | | | | | | | | | | | | | |
Distribution operations | | $ | 275 | | | $ | 190 | | | $ | 130 | | | $ | 63 | | | $ | 173 | | | $ | 127 | | | $ | 48 | |
Retail energy operations | | | 125 | | | | 23 | | | | 18 | | | | 5 | | | | 14 | | | | 16 | | | | (2 | ) |
Wholesale services | | | 2 | | | | 2 | | | | 13 | | | | (11 | ) | | | 10 | | | | 12 | | | | (2 | ) |
Energy investments | | | 10 | | | | 10 | | | | 8 | | | | 2 | | | | 11 | | | | 8 | | | | 3 | |
Corporate (2) | | | (35 | ) | | | - | | | | 1 | | | | (1 | ) | | | - | | | | 2 | | | | (2 | ) |
Consolidated | | $ | 377 | | | $ | 225 | | | $ | 170 | | | $ | 58 | | | $ | 208 | | | $ | 165 | | | $ | 45 | |
In millions | | Operating revenues | | | Operating margin (1) | | | Operating expenses | | | EBIT (1) | |
2008 | | | | | | | | | | | | |
Distribution operations | | $ | 345 | | | $ | 180 | | | $ | 123 | | | $ | 57 | |
Retail energy operations | | | 177 | | | | 24 | | | | 18 | | | | 6 | |
Wholesale services | | | (51 | ) | | | (53 | ) | | | 12 | | | | (65 | ) |
Energy investments | | | 19 | | | | 18 | | | | 8 | | | | 10 | |
Corporate (2) | | | (46 | ) | | | - | | | | 2 | | | | 1 | |
Consolidated | | $ | 444 | | | $ | 169 | | | $ | 163 | | | $ | 9 | |
(1) | These are non-GAAP measures. A reconciliation of operating margin and EBIT to our operating
income, earnings before income taxes and net income attributable to AGL Resources Inc. is located in
“Results of Operations” herein.
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(2) | Includes intercompany eliminations. |
Operating margin Our operating margin for the second quarter of 2009 increased by $56 million or 33% compared to the same period last year. This increase was primarily due to increased operating margins at wholesale services and distribution operations, offset by lower operating margins at energy investments.
Distribution operations’ operating margin increased by $10 million or 6% compared to last year. The following table indicates the significant changes in distribution operations’ operating margin for the three months ended June 30, 2009 compared to the prior year period.
In millions | | | |
Operating margin for second quarter of 2008 | | $ | 180 | |
Increased margins from gas storage carrying amounts at Atlanta Gas Light | | | 4 | |
Prior year revision in estimated unbilled natural gas volumes and slightly higher customer growth and usage at Elizabethtown Gas | | | 4 | |
Higher PRP revenues at Atlanta Gas Light | | | 1 | |
Other | | | 1 | |
Operating margin for second quarter of 2009 | | $ | 190 | |
Retail energy operations’ operating margin decreased by $1 million or 4%. The following table indicates the significant changes in retail energy operations’ operating margin for the three months ended June 30, 2009 compared to 2008.
In millions | | | |
Operating margin for second quarter of 2008 | | $ | 24 | |
Higher contributions from the management of storage and transportation assets largely due to declining natural gas prices in 2009 offset by a prior year favorable pipeline rate order true-up | | | 3 | |
Lower operating margins in Ohio and Florida | | | (1 | ) |
Change in retail pricing plan mix and decrease in average number of customers | | | (3 | ) |
Operating margin for second quarter of 2009 | | $ | 23 | |
Wholesale services’ operating margin increased $55 million compared to the second quarter of 2008 primarily due to $13 million in reported hedge gains as a result of decreases in forward NYMEX natural gas prices and the narrowing of transportation basis spreads in the current period, compared to $55 million in reported hedge losses due to rising forward NYMEX natural gas prices and expanding transportation basis spreads in 2008. In addition, commercial activity decreased $13 million due to lower volatility in the marketplace during the quarter as compared to last year. The following table indicates the components of wholesale services’ operating margin for the three months ended June 30, 2009 and 2008.
In millions | | 2009 | | | 2008 | |
Commercial activity | | $ | (11 | ) | | $ | 2 | |
Gain (loss) on transportation hedges | | | 11 | | | | (7 | ) |
Gain (loss) on storage hedges | | | 2 | | | | (48 | ) |
Operating margin | | $ | 2 | | | $ | (53 | ) |
Energy investments’ operating margin decreased by $8 million or 44% compared to last year. The following table indicates the significant changes in energy investments’ operating margin for the three months ended June 30, 2009 compared to the prior year period.
In millions | | | |
Operating margin for second quarter of 2008 | | $ | 18 | |
Decreased operating margin contribution at AGL Networks, primarily as a result of a network expansion project completed in 2008 | | | (7 | ) |
Decreased interruptible margins at Jefferson Island | | | (1 | ) |
Operating margin for second quarter of 2009 | | $ | 10 | |
Operating expenses Our operating expenses for the second quarter of 2009 increased $7 million or 4% as compared to the second quarter of 2008. The following table indicates the significant changes in our operating expenses.
In millions | | | | |
Operating expenses for second quarter of 2008 | | $ | 163 | |
Increased environmental remediation costs at distribution operations | | | 2 | |
Increased pension and postretirement expenses at distribution operations | | | 2 | |
Increased depreciation expense at distribution operations and energy investments | | | 2 | |
Other | | | 1 | |
Operating expenses for second quarter of 2009 | | $ | 170 | |
Interest expense Interest expense decreased by $2 million or 8% for the three months ended June 30, 2009, primarily due to the decrease in short-term interest rates partially offset by higher average debt outstanding as indicated in the following table.
| | Three months ended June 30, | |
In millions | | 2009 | | | 2008 | | | Change | |
Average debt outstanding (1) | | $ | 1,996 | | | $ | 1,853 | | | $ | 143 | |
Average rate | | | 4.8 | % | | | 5.6 | % | | | (0.8 | )% |
(1) Daily average of all outstanding debt.
Six months 2009 compared to six months 2008
Segment information Operating revenues, operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the six months ended June 30, 2009 and 2008.
In millions | | Operating revenues | | | Operating margin (1) | | | Operating expenses | | | EBIT (1) | |
2009 | | | | | | | | | | | | |
Distribution operations | | $ | 882 | | | $ | 442 | | | $ | 254 | | | $ | 193 | |
Retail energy operations | | | 468 | | | | 107 | | | | 39 | | | | 68 | |
Wholesale services | | | 70 | | | | 61 | | | | 34 | | | | 27 | |
Energy investments | | | 20 | | | | 20 | | | | 16 | | | | 4 | |
Corporate (2) | | | (68 | ) | | | 1 | | | | 3 | | | | (2 | ) |
Consolidated | | $ | 1,372 | | | $ | 631 | | | $ | 346 | | | $ | 290 | |
In millions | | Operating revenues | | | Operating margin (1) | | | Operating expenses | | | EBIT (1) | | | Operating margin (1) | | | Operating expenses | | | EBIT (1) | |
2008 | | | | | | | | | | | | | | | | | | | | | |
Distribution operations | | $ | 1,021 | | | $ | 428 | | | $ | 249 | | | $ | 180 | | | $ | 171 | | | $ | 113 | | | $ | 59 | |
Retail energy operations | | | 552 | | | | 106 | | | | 38 | | | | 68 | | | | (5 | ) | | | 16 | | | | (21 | ) |
Wholesale services | | | (34 | ) | | | (38 | ) | | | 26 | | | | (64 | ) | | | 101 | | | | 15 | | | | 86 | |
Energy investments | | | 30 | | | | 29 | | | | 14 | | | | 15 | | | | 10 | | | | 7 | | | | 3 | |
Corporate (2) | | | (113 | ) | | | (1 | ) | | | 3 | | | | (1 | ) | | | 1 | | | | 1 | | | | 1 | |
Consolidated | | $ | 1,456 | | | $ | 524 | | | $ | 330 | | | $ | 198 | | | $ | 278 | | | $ | 152 | | | $ | 128 | |
(1) | These are non-GAAP measures. A reconciliation of operating margin and EBIT to our operating income, earnings before income taxes and net income attributable to AGL Resources Inc. is located in “Results of Operations” herein. |
(2) | Includes intercompany eliminations. |
Operating margin Our operating margin for the six months ended June 30, 2009, increasedDistribution operations’ EBIT decreased by $107$11 million or 20% compared to the same period last year. This increase was primarily due to increased operating margins at wholesale services and distribution operations, partially offset by lower operating margin at energy investments.
Distribution operations’ operating margin increased by $14 million or 3%19% compared to last year. Theyear as shown in the following table indicates the significant changes in distribution operations’ operating margin for the six months ended June 30, 2009 compared to 2008.table.
In millions | | | |
Operating margin for six months of 2008 | | $ | 428 | |
Increased margins from gas storage carrying amounts at Atlanta Gas Light | | | 7 | |
Higher PRP revenues at Atlanta Gas Light | | | 3 | |
Prior year revision in estimated unbilled natural gas volumes at Elizabethtown Gas | | | 3 | |
All other, net | | | 1 | |
Operating margin for six months of 2009 | | $ | 442 | |
In millions | | | | | | |
EBIT for third quarter of 2008 | | | | | $ | 59 | |
| | | | | | | |
Operating margin | | | | | | | |
Increased margins from gas storage carrying amounts at Atlanta Gas Light | | $ | 2 | | | | | |
Higher PRP revenues at Atlanta Gas Light | | | 1 | | | | | |
Other | | | (1 | ) | | | | |
Increase in operating margin | | | | | | | 2 | |
| | | | | | | | |
Operating expenses | | | | | | | | |
Increased pension and postretirement expenses | | $ | 6 | | | | | |
Increased payroll and incentive expenses | | | 4 | | | | | |
Increased depreciation expenses | | | 3 | | | | | |
Other | | | 1 | | | | | |
Increase in operating expenses | | | | | | | (14 | ) |
Increase in other income | | | | | | | 1 | |
EBIT for third quarter of 2009 | | | | | | $ | 48 | |
Retail energy operations’ operating marginEBIT increased by $1$19 million or 1%. The90% as shown in the following table indicates the significant changes in retail energy operations’ operating margin for the six months ended June 30, 2009 compared to 2008.table.
In millions | | | |
Operating margin for six months of 2008 | | $ | 106 | |
Higher contributions from the management of storage and transportation assets largely due to declining natural gas prices in 2009 offset by a prior year favorable pipeline rate order true-up | | | 15 | |
2008 pricing settlement with Georgia Commission | | | 3 | |
Higher operating margins in Ohio and Florida | | | 2 | |
Average customer usage | | | 2 | |
Change in retail pricing plan mix and decrease in average number of customers | | | (15 | ) |
Inventory LOCOM | | | (6 | ) |
Operating margin for six months of 2009 | | $ | 107 | |
In millions | | | | | | |
EBIT for third quarter of 2008 | | | | | $ | (21 | ) |
| | | | | | | |
Operating margin | | | | | | | |
LOCOM adjustment in 2008 | | $ | 18 | | | | | |
Increased contributions from the management of storage and transportation assets offset by higher fixed interstate transportation costs | | | 1 | | | | | |
Increased Ohio and interruptible operating margins | | | 2 | | | | | |
Change in retail pricing plan mix and decrease in average number of customers | | | (2 | ) | | | | |
Increase in operating margin | | | | | | | 19 | |
| | | | | | | | |
Operating expenses | | | | | | | | |
Increased marketing and direct selling expenses | | $ | 2 | | | | | |
Decreased customer care and outside services expenses | | | (2 | ) | | | | |
Net change in operating expenses | | | | | | | - | |
EBIT for third quarter of 2009 | | | | | | $ | (2 | ) |
Wholesale services’ operating margin increased $99EBIT decreased by $88 million compared to the six months ended June 30, 2009, primarily due to $50 million in reported hedge gains as a result of decreases in forward NYMEX natural gas prices and the narrowing of transportation basis spreads in the current period, compared to $70 million in reported hedge losses due to rising forward NYMEX natural gas prices and expanding transportation basis spreads in 2008. This increase was partially offset by a reduction in commercial activity of $18 million due to lower volatility in the marketplace during the period asor 102% compared to last year. In addition,year as shown in the falling gas prices during the first quarterfollowing table.
In millions | | | | | | |
EBIT for third quarter of 2008 | | | | | $ | 86 | |
| | | | | | | |
Operating margin | | | | | | | |
Change on storage hedges as a result of forward NYMEX natural gas prices increasing this quarter as opposed to a significant decrease in the prior quarter | | $ | (110 | ) | | | | |
Lower commercial activity from reduced volatility in the marketplace and mild weather | | | (17 | ) | | | | |
Increased gains on transportation hedges from the narrowing of transportation basis spreads | | | 2 | | | | | |
LOCOM adjustment in the third quarter of 2008, no adjustment was taken in the third quarter of 2009 | | | 34 | | | | | |
Decrease in operating margin | | | | | | | (91 | ) |
| | | | | | | | |
Operating expenses | | | | | | | | |
Decreased incentives and other expenses primarily associated with the decline in reported results | | $ | (3 | ) | | | | |
Decrease in operating expenses | | | | | | | 3 | |
EBIT for third quarter of 2009 | | | | | | $ | (2 | ) |
The following table indicates the components of wholesale services’ operating margin for the sixthree months ended JuneSeptember 30, 2009 and 2008.
In millions | | 2009 | | | 2008 | |
Gain (loss) on transportation hedges | | $ | 32 | | | $ | (11 | ) |
Gain (loss) on storage hedges | | | 18 | | | | (59 | ) |
Commercial activity | | | 14 | | | | 32 | |
Inventory LOCOM, net of estimated hedging recoveries | | | (3 | ) | | | - | |
Operating margin | | $ | 61 | | | $ | (38 | ) |
In millions | | 2009 | | | 2008 | |
Gain on transportation hedges | | $ | 14 | | | $ | 12 | |
Commercial activity recognized | | | 1 | | | | 18 | |
(Loss) gain on storage hedges | | | (5 | ) | | | 105 | |
Inventory LOCOM, net of hedging recoveries | | | - | | | | (34 | ) |
Operating margin | | $ | 10 | | | $ | 101 | |
Energy investments’ EBIT was flat compared to last year as shown in the following table.
In millions | | | | | | |
EBIT for third quarter of 2008 | | | | | $ | 3 | |
| | | | | | | |
Operating margin | | | | | | | |
Increased operating revenues at AGL Networks | | $ | 1 | | | | | |
Increase in operating margin | | | | | | | 1 | |
| | | | | | | | |
Operating expenses | | | | | | | | |
Increased legal expenses and other outside services related to Jefferson Island litigation and increased depreciation expense at Golden Triangle Storage | | $ | 1 | | | | | |
Increase in operating expenses | | | | | | | (1 | ) |
EBIT for third quarter of 2009 | | | | | | $ | 3 | |
Nine months ended September 30, 2009 compared to nine months ended September 30, 2008
Segment information Operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the nine months ended September 30, 2009 and 2008.
In millions | | Operating margin (1) | | | Operating expenses | | | EBIT (1) | |
2009 | | | | | | | | | |
Distribution operations | | $ | 615 | | | $ | 381 | | | $ | 241 | |
Retail energy operations | | | 121 | | | | 55 | | | | 66 | |
Wholesale services | | | 71 | | | | 46 | | | | 25 | |
Energy investments | | | 31 | | | | 24 | | | | 7 | |
Corporate (2) | | | 1 | | | | 5 | | | | (4 | ) |
Consolidated | | $ | 839 | | | $ | 511 | | | $ | 335 | |
In millions | | Operating margin (1) | | | Operating expenses | | | EBIT (1) | |
2008 | | | | | | | | | |
Distribution operations | | $ | 599 | | | $ | 362 | | | $ | 239 | |
Retail energy operations | | | 101 | | | | 54 | | | | 47 | |
Wholesale services | | | 63 | | | | 41 | | | | 22 | |
Energy investments | | | 39 | | | | 21 | | | | 18 | |
Corporate (2) | | | - | | | | 4 | | | | - | |
Consolidated | | $ | 802 | | | $ | 482 | | | $ | 326 | |
(1) | These are non-GAAP measures. A reconciliation of operating margin and EBIT to our operating income, earnings before income taxes and net income attributable to AGL Resources Inc. is located in “Results of Operations” herein. |
(2) | Includes intercompany eliminations. |
Distribution operations’ EBIT increased by $2 million or 1% compared to last year as shown in the following table.
In millions | | | | | | |
EBIT for nine months of 2008 | | | | | $ | 239 | |
| | | | | | | |
Operating margin | | | | | | | |
Increased margins from gas storage carrying amounts at Atlanta Gas Light | | $ | 9 | | | | | |
Higher PRP revenues at Atlanta Gas Light | | | 5 | | | | | |
Increased customer growth and increased usage at Virginia Natural Gas | | | 4 | | | | | |
Change in estimated unbilled natural gas volumes recorded in prior year at Elizabethtown Gas | | | 3 | | | | | |
Decreased customer growth and usage at Chattanooga Gas and Florida City Gas | | | (2 | ) | | | | |
Decreased customer growth and reduced service fees at Atlanta Gas Light | | | (3 | ) | | | | |
Increase in operating margin | | | | | | | 16 | |
| | | | | | | | |
Operating expenses | | | | | | | | |
Increased pension and postretirement expenses | | $ | 9 | | | | | |
Increased payroll and incentive expenses | | | 7 | | | | | |
Increased depreciation expenses | | | 6 | | | | | |
Increased environmental expenses | | | 2 | | | | | |
Decreased marketing, outside services, facilities and vehicle fuel expenses | | | (5 | ) | | | | |
Increase in operating expenses | | | | | | | (19 | ) |
Increase in other income, primarily from regulatory allowance for funds used during construction of Hampton Roads pipeline project at Virginia Natural Gas | | | | | | | 5 | |
EBIT for nine months of 2009 | | | | | | $ | 241 | |
Energy investments’ operating margin decreasedRetail energy operations’ EBIT increased by $9$19 million or 31%40% as shown in the following table.
In millions | | | | | | |
EBIT for nine months of 2008 | | | | | $ | 47 | |
| | | | | | | |
Operating margin | | | | | | | |
Increased contributions from the management of storage and transportation assets largely due to declining natural gas prices in 2009 offset by a prior year favorable pipeline rate order true-up | | $ | 16 | | | | | |
Change in LOCOM adjustment | | | 12 | | | | | |
Increased operating margins in Ohio | | | 4 | | | | | |
2008 pricing settlement with Georgia Commission | | | 3 | | | | | |
Increased average customer usage | | | 2 | | | | | |
Change in retail pricing plan mix and decrease in average number of customers | | | (17 | ) | | | | |
Increase in operating margin | | | | | | | 20 | |
| | | | | | | | |
Operating expenses | | | | | | | | |
Increased marketing and direct selling expenses | | $ | 2 | | | | | |
Increased incentive compensation costs due to higher earnings | | | 1 | | | | | |
Decreased customer care expenses | | | (3 | ) | | | | |
Other | | | 1 | | | | | |
Increase in operating expenses | | | | | | | (1 | ) |
EBIT for nine months of 2009 | | | | | | $ | 66 | |
Wholesale services’ EBIT increased $3 million or 14% compared to last year. year as shown in the following table.
In millions | | | | | | |
EBIT for nine months of 2008 | | | | | $ | 22 | |
| | | | | | | |
Operating margin | | | | | | | |
Increased gains on transportation hedges from the continued narrowing of basis spreads | | $ | 43 | | | | | |
Change in LOCOM adjustment net of estimated hedging recoveries | | | 34 | | | | | |
Lower commercial activity from reduced volatility in the marketplace and mild weather | | | (21 | ) | | | | |
Gains on storage hedges in the prior year due to decreases in forward NYMEX natural gas prices compared to storage hedge losses in the current year | | | (48 | ) | | | | |
Increase in operating margin | | | | | | | 8 | |
| | | | | | | | |
Operating expenses | | | | | | | | |
Increased incentive compensation costs reflecting additional value captured in storage transactions and other accrued expenses | | $ | 5 | | | | | |
Increase in operating expenses | | | | | | | (5 | ) |
EBIT for nine months of 2009 | | | | | | $ | 25 | |
The following table indicates the significant changes in energy investments’components of wholesale services’ operating margin for the sixnine months ended JuneSeptember 30, 2009 compared toand 2008.
In millions | | | |
Operating margin for six months of 2008 | | $ | 29 | |
Decreased operating margins at AGL Networks, primarily as a result of an expansion project completed in 2008 | | | (7 | ) |
All other including slightly lower interruptible operating margins at Jefferson Island | | | (2 | ) |
Operating margin for six months of 2009 | | $ | 20 | |
Operating expenses Our operating expenses for the six months ended June 30, 2009, increased $16 million or 5% as compared to the same period last year. The following table indicates the significant changes in our operating expenses.
In millions | | | | |
Operating expenses for six months of 2008 | | $ | 330 | |
Increased incentive compensation costs at wholesale services and retail energy operations due to increased earnings | | | 7 | |
Increased depreciation expense primarily at distribution operations, retail energy operations and energy investments | | | 4 | |
Increased pension and postretirement expense at distribution operations | | | 2 | |
Increased environmental remediation costs at distribution operations | | | 2 | |
Increased bad debt expense at distribution operations | | | 1 | |
Increased legal expenses and other outside services related to Jefferson Island litigation | | | 1 | |
Decreased outside services, marketing and other expenses at distribution operations | | | (3 | ) |
Other | | | 2 | |
Operating expenses for six months of 2009 | | $ | 346 | |
In millions | | 2009 | | | 2008 | |
Gain on transportation hedges | | $ | 44 | | | $ | 1 | |
Commercial activity recognized | | | 29 | | | | 50 | |
(Loss) gain on storage hedges | | | (2 | ) | | | 46 | |
Inventory LOCOM, net of hedging recoveries | | | - | | | | (34 | ) |
Operating margin | | $ | 71 | | | $ | 63 | |
Interest expense Interest expenseEnergy investments’ EBIT decreased by $7$11 million or 13% for the six months ended June 30, 2009, primarily due61% compared to the decrease in short-term interest rates partially offset by higher average debt outstandinglast year as indicatedshown in the following table.
| | Six months ended June 30, | |
In millions | | 2009 | | | 2008 | | | Change | |
Average debt outstanding (1) | | $ | 2,155 | | | $ | 1,933 | | | $ | 222 | |
Average rate | | | 4.5 | % | | | 5.8 | % | | | (1.3 | )% |
(1) Daily average of all outstanding debt.In millions | | | | | | |
EBIT for nine months of 2008 | | | | | $ | 18 | |
| | | | | | | |
Operating margin | | | | | | | |
Decreased operating margin at AGL Networks, primarily as a result of a network expansion project completed in 2008 | | $ | (5 | ) | | | | |
All other primarily due to decreased interruptible margins at Jefferson Island | | | (3 | ) | | | | |
Decrease in operating margin | | | | | | | (8 | ) |
| | | | | | | | |
Operating expenses | | | | | | | | |
Increased legal expenses and other outside services related to Jefferson Island litigation | | $ | 1 | | | | | |
Increased depreciation, property taxes and other operating expenses primarily at Golden Triangle Storage | | | 2 | | | | | |
Increase in operating expenses | | | | | | | (3 | ) |
EBIT for nine months of 2009 | | | | | | $ | 7 | |
Our primary sources of liquidity are cash provided by operating activities, short-term borrowings under our commercial paper program (which is supported by our Credit Facilities)Facility) and borrowings under subsidiary lines of credit. Additionally, from time to time, we raise funds from the public debt and equity capital markets to fund our liquidity and capital resource needs.
Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by, or filings with, state and federal regulatory bodies including state public service commissions, the SEC and the FERC. Furthermore, a substantial portion of our consolidated assets, earnings and 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.
We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by rating agencies and other factors. See Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the year ended December 31, 2008, for additional information on items that could impact our liquidity and capital resource requirements. The following table provides a summary of our operating, investing and financing activities.
| | Six months ended June. 30, | | | Nine months ended September 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Net cash provided by (used in): | | | | | | | | | | | | |
Operating activities | | $ | 731 | | | $ | 359 | | | $ | 686 | | | $ | 172 | |
Investing activities | | | (207 | ) | | | (166 | ) | | | (314 | ) | | | (254 | ) |
Financing activities | | | (528 | ) | | | (193 | ) | | | (367 | ) | | | 74 | |
Net decrease in cash and cash equivalents | | $ | (4 | ) | | $ | - | | |
Net increase (decrease) in cash and cash equivalents | | | $ | 5 | | | $ | (8 | ) |
Cash Flow from Operating Activities In the first sixnine months of 2009, our net cash flow provided from operating activities was $731$686 million, an increase of $372$514 million or 104%299% from the same period in 2008. This increase was primarily a result of a larger decreasethe recovery of working capital during 2009 that was deployed in inventory in 2009 than 2008 primarily relateddue to higher natural gas commodity prices. A primary contributor to the higher costrecovery of working capital was a $272 million increase in cash from our inventory soldwithdrawals and $125 million increase in 2009. This was partially offset by increasedcash from the collection of our natural gas receivables. In addition, we received $101 million from decreased cash collateral requirements for our derivative financial instrument activities at Sequent and SouthStar due to the change in hedge values due to the downward shift in theas forward NYMEX curve prices shifted downward in 2009.
The downward shift in the forward curve results in unrealized losses on the hedging instruments, comprised primarily of exchange traded derivatives, associated with anticipated natural gas purchases. We maintain accounts with brokers to facilitate financial derivative transactions in support of our energy marketing and risk management activities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts. These unrealized losses are substantially offset by gains on derivative instruments utilized to hedge the price risk associated with the anticipated sale of these natural gas purchases. The anticipated economics of these transactions will ultimately be realized in the period when the natural gas is bought and sold.
Cash Flow from Investing Activities Our investing activities consisted of PP&E expenditures of $207$314 million for the sixnine months ended JuneSeptember 30, 2009 and $166$254 million for the same period in 2008. The increase of $41$60 million or 25%24% in PP&E expenditures was primarily due to a $35 million increase at distribution operations which included higherand a $28 million increase at energy investments.
The increased expenditures at distribution operations include $43 million in increased spending primarily forat Virginia Natural Gas’ Hampton Roads Crossing pipeline project connecting its northern and southern systems. In addition, Elizabethtown Gas’ enhanced infrastructure program resulted in a $10 million increase compared to 2008, as the program started earlier this year. These increases were offset by reduced expenditures of $16 million for the PRP at Atlanta Gas Light.
Additionally, ourThe increases at energy investments’ PP&E expenditures increased $11 millioninvestments were primarily from increased expenditures atdue to Golden Triangle Storage on our plannedStorage’s natural gas storage facilityfacility. The increases at distribution operations and energy investments were partially offset by decreased telecommunication expenditures at AGL Networks which expanded its Phoenix network in 2008. These PP&E expenditure increases were partially offset by decreased expenditures at retail energy operations of $6 million primarily due to decreased spending on information technology assets compared to 2008, when the segmentGNG transitioned to a new customer care and call center vendor.
Cash Flow from Financing Activities Our cash used in financing activities arewas $367 million for the nine months ended September 30, 2009 compared to cash provided of $74 million for the same period in 2008. The increased cash use of $441 million was primarily composed of borrowings and payments ofdue to increased short-term debt payments of medium-term notes, issuances$556 million in 2009 compared to net borrowings of $189 million for the same period in 2008. This was partially offset by our issuance of $300 million of senior notes distributions to noncontrolling interests, cash dividends on our common stock, and purchases and issuances of treasury shares. in August 2009.
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 of the percentage of total debt relative to total capitalization, appropriate mix of debt with fixed to floating interest rates (our variable-rate debt target is 20% to 45% of total debt), as well as the term and interest rate profile of our debt securities. As of JuneSeptember 30, 2009, our variable-rate debt was 28%21% of our total debt, compared to 29%38% as of JuneSeptember 30, 2008. We may issue additional long-term debt in 2009 in consideration of our working capital needs and capital expenditure plans to maintain an appropriate mix of fixed to floating debt.
We also work to maintain or improve our credit ratings to manage our existing financing costs effectively and enhance our ability to raise additional capital on favorable terms. Factors we consider important in assessing our credit ratings include our statements of financial position 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 agreements that would require us to issue equity based on credit ratings or other trigger events. The following table summarizes our credit ratings as of JuneSeptember 30, 2009, and reflects no change from December 31, 2008.
| | S&P | | | Moody’s | | | Fitch | |
Corporate rating | | | A- | | | | | | | |
Commercial paper | | | A-2 | | | | P-2 | | | | F-2 | |
Senior unsecured | | BBB+ | | | Baa1 | | | | A- | |
Ratings outlook | | Stable | | | Stable | | | Stable | |
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.
Default events 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 a maximum leverage ratio, insolvency events, nonpayment of scheduled principal or interest payments, and acceleration of other financial obligations and change of control provisions.
Our Credit Facilities haveFacility has financial covenants that require us to maintain a ratio of total debt to total capitalization of no greater than 70%; however, our goal is to maintain this ratio at levels between 50% and 60%. Our ratio of total debt to total capitalization calculation contained in our debt covenant includes noncontrolling interest, standby letters of credit, surety bonds and the exclusion of other comprehensive income pension adjustments. Our debt to total capitalization calculation, as defined by our Credit FacilitiesFacility was 53%55% at JuneSeptember 30, 2009, and 59% at December 31, 2008 and 56%58% at JuneSeptember 30, 2008. These amounts are within our required and targeted ranges. Our debt to total capitalization ratios as calculated from our condensed consolidated statements of financial position, as of the dates indicated, are summarized in the following table.
| | June 30, 2009 | | | Dec. 31, 2008 | | | June 30, 2008 | | | Sept. 30, 2009 | | | Dec. 31, 2008 | | | Sept. 30, 2008 | |
Short-term debt | | | 11 | % | | | 20 | % | | | 13 | % | | | 8 | % | | | 20 | % | | | 18 | % |
Long-term debt | | | 43 | | | | 40 | | | | 43 | | | | 49 | | | | 40 | | | | 40 | |
Total debt | | | 54 | | | | 60 | | | | 56 | | | | 57 | | | | 60 | | | | 58 | |
Equity | | | 46 | | | | 40 | | | | 44 | | | | 43 | | | | 40 | | | | 42 | |
Total capitalization | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % |
We believe that accomplishing our 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. We currently comply with all existing debt provisions and covenants. For more information on our debt, see Note 6 “Debt.”
Short-term debt Our short-term debt is composed of borrowings and payments under our Credit FacilitiesFacility and commercial paper program, lines of credit and the current portion of 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. We 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 heating season.
Our short-term borrowings, as of JuneSeptember 30, 2009, decreased $95$459 million or 19%60% compared to the same period last year. This was primarily a result of paying down short-term debt with a portion of the proceeds received from the issuance of $300 million of senior notes in August 2009, and reduced working capital requirements as a result of lower natural gas prices. This was offset by increased property, plant and equipment expenditures of $41 million and a $29 million increase in our margin requirements for our energy marketing and risk management activities compared to the prior year. More information on our short-term debt as of June 30, 2009, which we consider one of our primary sources of liquidity, is presented in the following table:
In millions | | Capacity | | | Outstanding | |
Credit Facilities (1) | | $ | 1,140 | | | $ | 417 | |
SouthStar line of credit (2) | | | 74 | | | | - | |
Sequent lines of credit | | | 5 | | | | - | |
Total | | $ | 1,219 | | | $ | 417 | |
(1) | Supported by our $1.0 billion and $140 million Credit Facilities,
and includes $417 million of commercial paper borrowings.
|
(2) | Capacity reduced by $1 million letter of credit. |
$60 million.
Our commercial paper borrowings are supported by our $1 billion Credit Facility which expires in August 2011 and a2011. Our supplemental $140 million Credit Facility, that expireswhich we completed last year to provide additional liquidity for working capital and capital expenditure needs, expired in September 2009. We have the option to request an increase in the aggregate principal amount available for borrowing under the $1 billion Credit Facility to $1.25 billion on not more than three occasions during each calendar year. SouthStar has a $75 million line of credit which is used for its working capital and general corporate needs. Additionally, Sequent has a $5 million line of credit that is used solely for the posting of margin deposits for NYMEX transactions. Both of these lines of credit had no amounts outstanding as of September 30, 2009.
The $140 millionlenders under our Credit Facility allows for the option to request an increaseand lines of credit are major financial institutions with committed balances and investment grade credit ratings as of September 30, 2009 as indicated in the borrowing capacityfollowing table. Investment grade, in the context of bond ratings, is the rating level above which institutional investors are authorized to $150 million. invest (a bond judged likely enough to meet payment obligations that banks and pensions are allowed to invest in it).
Lender rating (S&P / Moody’s) | | | Amount committed (in millions) | | | % of total | |
AAA / Aaa | | | $ | - | | | | - | |
AA / Aa | | | | 328 | | | | 31 | % |
A / A | | | | 582 | | | | 54 | % |
BBB / Baa | | | | 165 | | | | 15 | % |
Total | | | $ | 1,075 | | | | 100 | % |
Based on current credit market conditions, it is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal.
As of JuneSeptember 30, 2009 and June 30, 2008 we had no outstanding borrowings under our Credit Facilities.Facility. As of December 31, 2008, we had $500 million of outstanding borrowings under the Credit Facilities.Facility. Additionally, at September 30, 2008, we had $485 million of outstanding borrowings under the Credit Facility. We normally access the commercial paper markets to finance our working capital needs. However, during the third and fourth quarters of 2008, adverse developments in the global financial and credit markets made it more difficult for us to access the commercial paper market at reasonable rates. In 2009, the credit markets have improved, allowing us to resume our commercial paper borrowings.
Long-term debt Our long-term debt matures more than one year from the date of our statements of financial position and consists of medium-term notes, senior notes, gas facility revenue bonds, and capital leases. In August 2009, AGL Capital issued $300 million of 10-year senior notes at an interest rate of 5.25%. The net proceeds from the offering were approximately $297 million. We used the net proceeds from the sale of the senior notes to repay a portion of our short-term debt.
For information on the maturity of our long-term debt see Note 6 to our recast consolidated financial statements, as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.
Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operating 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 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.
In the first sixnine months of 2009, we contributed $17$21 million to our qualified pension plans. We contributed an additional $3 million in October 2009; however, we do not expect to make any additional contributions to our pension plans of $15 million in 2009 for2009. In 2008, we did not make a total of $32 million.contribution, as one was not required. We previously expected that our total required and additional contributions to our pension plans would be approximately $68 million to preserve the current levels of benefits under our pension plans and in accordance with the funding requirements of the Pension Protection Act. The reduction in our expected contributions are a result of a notice from the Internal Revenue Service with respect to proposed changes to the pension funding rules that resulted in the use ofallowed using a discount rate that was higher than the discount rate we used in our previous estimate. Consequently, our pension liabilities as calculated under the funding rules were reduced and the 2009 funding requirements decreased to maintain current benefits levels.
The following table illustrates our expected future contractual obligation payments such as debt and lease agreements, and commitments and contingencies as of JuneSeptember 30, 2009.
| | | | | | | | 2010 & | | | 2012 & | | | 2014 & | | | | | | | | | 2010 & | | | 2012 & | | | 2014 & | |
In millions | | Total | | | 2009 | | | 2011 | | | 2013 | | | thereafter | | | Total | | | 2009 | | | 2011 | | | 2013 | | | thereafter | |
Recorded contractual obligations: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Long-term debt | | $ | 1,675 | | | $ | - | | | $ | 302 | | | $ | 241 | | | $ | 1,132 | | | $ | 1,975 | | | $ | - | | | $ | 301 | | | $ | 242 | | | $ | 1,432 | |
Short-term debt | | | 418 | | | | 418 | | | | - | | | | - | | | | - | | | | 310 | | | | 309 | | | | 1 | | | | - | | | | - | |
PRP costs (1) | | | 163 | | | | 23 | | | | 91 | | | | 49 | | | | - | | | | 155 | | | | 14 | | | | 93 | | | | 48 | | | | - | |
Environmental remediation liabilities (1) | | | 133 | | | | 10 | | | | 43 | | | | 53 | | | | 27 | | | | 130 | | | | 7 | | | | 43 | | | | 53 | | | | 27 | |
Total | | $ | 2,389 | | | $ | 451 | | | $ | 436 | | | $ | 343 | | | $ | 1,159 | | | $ | 2,570 | | | $ | 330 | | | $ | 438 | | | $ | 343 | | | $ | 1,459 | |
Unrecorded contractual obligations and commitments (2): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Pipeline charges, storage capacity and gas supply (3) | | $ | 1,705 | | | $ | 289 | | | $ | 690 | | | $ | 373 | | | $ | 353 | | | $ | 1,712 | | | $ | 151 | | | $ | 755 | | | $ | 390 | | | $ | 416 | |
Interest charges (4) | | | 909 | | | | 47 | | | | 166 | | | | 135 | | | | 561 | | | | 1,043 | | | | 28 | | | | 198 | | | | 167 | | | | 650 | |
Operating leases | | | 125 | | | | 15 | | | | 47 | | | | 26 | | | | 37 | | | | 122 | | | | 9 | | | | 49 | | | | 27 | | | | 37 | |
Asset management agreements (5) | | | 33 | | | | 8 | | | | 23 | | | | 2 | | | | - | | | | 41 | | | | 6 | | | | 33 | | | | 2 | | | | - | |
Standby letters of credit, performance / surety bonds | | | 23 | | | | 15 | | | | 7 | | | | 1 | | | | - | | | | 26 | | | | 9 | | | | 16 | | | | 1 | | | | - | |
Total | | $ | 2,795 | | | $ | 374 | | | $ | 933 | | | $ | 537 | | | $ | 951 | | | $ | 2,944 | | | $ | 203 | | | $ | 1,051 | | | $ | 587 | | | $ | 1,103 | |
(1) | Includes charges recoverable through rate rider mechanisms. |
(2) | In accordance with GAAP, these items are not reflected in our condensed consolidated statements of financial position. |
(3) | Charges recoverable through a natural gas cost recovery mechanism or alternatively billed to Marketers, and includes demand charges associated with Sequent. Also includes SouthStar’s gas natural gas purchase commitments of 1820 Bcf at floating gas prices calculated using forward natural gas prices as of JuneSeptember 30, 2009, and are valued at $73$78 million. Additionally, includes amounts associated with a subsidiary of NUI which 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 141,the authoritative guidance related to business combinations, we valued the contracts at fair value and established a long-term liability of $38 million for the excess liability that will be amortized to our consolidated statements of income over the remaining lives of the contracts of $2 million annually through November 2023 and $1 million annually from November 2023 to November 2028. |
(4) | Floating rate debt is based on the interest rate as of JuneSeptember 30, 2009, and the maturity of the underlying debt instrument. As of JuneSeptember 30, 2009, we have $35$33 million of accrued interest on our condensed consolidated statements of financial position that will be paid in over the next twelve12 months. |
(5) | Represent fixed-fee minimum payments for Sequent’s asset management agreements. |
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 base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. We evaluate our estimates on an ongoing basis, and our actual results may differ from these estimates. Our critical accounting policies used in the preparation of our condensed consolidated financial statements include the following:
· | Pipeline Replacement Program |
· | Environmental Remediation Liabilities |
· | Derivatives and Hedging Activities |
· | Pension and Other Postretirement Plans |
Each of our critical accounting policies and estimates 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. There have been no significant changes to our critical accounting policies from those disclosed in our recast Management’s Discussion and Analysis of Financial Condition and Results of Operation as filed on Form 8-K with the SEC on July 13, 2009.
Previously discussedSubsequent Events
In May 2009, the FASB issued additional authoritative guidance for and disclosure of events that occur after the statement of financial position date, but before financial statements are issued, or are available to be issued. In accordance with the additional guidance, we evaluated and disclosed in Note 1 subsequent events until the time that our financial statements were issued and filed with the SEC on October 29, 2009.
Fair Value Measurements
In April 2009, additional authoritative guidance related to fair value measurements and disclosures established a two-step process to determine if the market for a financial asset is inactive and a transaction is not distressed. Currently, this authoritative guidance does not affect us, as our derivative financial instruments are traded in active markets.
In August 2009, the FASB updated the fair value measurement guidance to provide clarity on the methodologies and disclosures for fair value estimates of liabilities that do not have a quoted price in an active market or, level 3 liabilities. Any revisions due to a change in valuation technique, or its application, are to be accounted for as a change in accounting method. Disclosure is required for any change in valuation technique or related inputs resulting from the application of this update and the total effect would need to be quantified, if practicable. This update is effective for reporting periods ending after September 15, 2009, and had no financial impact to our condensed consolidated results of operations, cash flows or financial position. Our fair value measurements are described in further detail in Note 2 and Note 6.
Derivative Financial Instruments
SFAS 160 SFAS 160 requires usThe amendment to present our minority interest, as noncontrolling interest, separately within the capitalization section of our condensed consolidated statements of financial position. We adopted SFAS 160 on January 1, 2009. More information on our adoption of SFAS 160 is discussed in Note 5.
SFAS 161 SFAS 161 amends the disclosure requirements of SFAS 133authoritative guidance related to providederivatives and hedging provides an enhanced understanding of how and why derivative instruments are used, how they are accounted for and their effect on an entity’sour financial condition, performance and cash flows. We adopted SFAS 161this guidance on January 1, 2009, and provided the required additional disclosures, but it had no financial impact to our condensed consolidated results of operations, cash flows or financial condition.More information on our adoption of SFAS 161 is discussed in Note 3.
FSP EITF 03-6-1 This FSP became effective on January 1,In 2009, and providesadditional authoritative guidance on the computation of earnings per share for unvested share awards outstanding that have the nonforfeitable right to receive dividends. The effects of this FSP were immaterial to our calculation of earnings per share.
FSP FAS 133-1 This FSP requiresrequiring more detailed disclosures about credit derivatives, including the potential adverse effects of changes in credit risk on the financial position, financial performance and cash flows of the sellers of the instruments.instruments was issued. This FSPguidance had no financial impact to our condensed consolidated results of operations, cash flows or financial condition. We adopted FSP FAS 133-1this authoritative guidance on January 1, 2009. Our derivative financial instruments are described in further detail in Note 3.
FSP FAS 132(R)-1 This FSPEmployee Benefit Plans
Additional authoritative guidance related to retirement benefits requires additional disclosures relating to postretirement benefit plan assets to provide transparency regarding the types of assets and the associated risks within the types of plan assets. The required disclosures include:
· | How investment allocation decisions are made, including information that provides an understanding of investment policies and strategies, |
· | The major categories of plan assets, |
· | Inputs and valuation techniques used to measure the fair value of plan assets, including those measurements using significant unobservable inputs, on changes in plan assets for the period, and |
· | Significant concentrations of risk within plan assets. |
This FSPauthoritative guidance is effective for fiscal years ending after December 15, 2009 and requires additional disclosures in our notes to condensed consolidated financial statements, but will not have a material impact on our financial position, consolidated results of operations or cash flows. Our employee benefit plans are described in further detail in Note 4.
Recently issuedVariable Interest Entity
SFAS 165 In May 2009, the FASB issued SFAS 165, which is effective for reporting periods ending after June 15, 2009. SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the statement of financial position date, but before financial statements are issued, or are available to be issued. Prior to SFAS 165, guidance relating to subsequent events was contained in AU Section 560, “Subsequent Events,” (AU 560) of the auditing literature, which was primarily directed toward auditors, not management. SFAS 165 should be applied by management to the accounting for and disclosure of subsequent events, but does not apply to subsequent events or transactions that are within the scope of other applicable GAAP that provide different guidance. In accordance with SFAS 165, we have evaluated and disclosed in Note 9 subsequent events until the time that our financial statements were issued and filed with the SEC on July 30, 2009.
SFAS 166In June 2009, the FASB issued SFAS 166,guidance, which amends FSP FAS 140-4,amended the guidance related to transfers and servicing. This guidance requires improved disclosures about transfers of financial assets and removes the exception from applying FIN 46(R)the guidance related to consolidations specifically for variable interest entities (VIE) to qualifying special purpose entities. SFAS 166This amendment will be effective for us on January 1, 2010 and it will have no effect on our consolidated results of operations, cash flow andflows or financial position.
SFAS 167In June 2009, the FASB issued SFAS 167, which provides newadditional consolidation guidance for variable interest entities (VIE). SFAS 167VIE. The guidance requires a companyus to assess the determination of the primary beneficiary of a VIE based on whether the company haswe have the power to direct matters that most significantly impact the activities of the VIE, and has the obligation to absorb losses or the right to receive benefits of the VIE. In addition, SFAS 167the guidance requires ongoing reassessments of whether a company iswe are the primary beneficiary of a VIE.
SFAS 167 The guidance will be effective for us beginning January 1, 2010. Earlier application is prohibited. We are currently evaluating the impact of this standardguidance on our consolidated results of operations, cash flows and financial position. Our VIE is described in further detail in Note 5.
General Principles
SFAS 168In June 2009, the FASB issued SFAS 168,the authoritative guidance, which replaces SFAS 162the previous authoritative hierarchy aspect of GAAP. SFAS 168The guidance creates a two-level GAAP hierarchy - authoritative and non-authoritative - and establishes the FASB’s Accounting Standards Codification (Codification)guidance as the sole source of authoritative GAAP for non-governmental entities, except for rules and releases by the SEC.
After July 1, 2009, all non-grandfathered, non-SEC accounting guidance not included in the Codificationauthoritative guidance is superseded and is deemed non-authoritative. SFAS 168The guidance is effective for financial statements issued for interim and annual periods ending after September 15, 2009. SFAS 168The guidance will have no impact on our consolidated results of operations, cash flows andor financial position.
FSP FAS 157-4 This FSP establishes a two-step process to determine if the market for a financial asset is inactive and a transaction is not distressed. Step 1 provides factors that include, but are not limited to: transaction frequency, varying price quotations, index correlation, liquidity risk premiums, price spread increases and availability of public information. If a company determines the market is inactive, Step 2 must be applied.
In Step 2 an entity must presume that a quoted price is associated with a distressed transaction unless there was sufficient time before the measurement date to allow for usual and customary marketing activities, including multiple bidders. This FSP is effective for interim and annual periods ending after June 15, 2009. We adopted this FSP in the second quarter of 2009. Currently, this FSP does not effect us, as our financial assets are traded in active markets.
About Market Risk
We are exposed to risks associated with natural gas prices, interest rates and credit. Natural gas price risk is defined as the potential loss that we may incur as a result of changes in the fair value of natural gas. 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 risk management policies and monitoring compliance with, and adherence to, the terms within these policies, including approval and authorization levels and delegation of these levels. Our RMC consists of members of senior management who monitor open natural gas price risk positions and other types of risk, corporate exposures, credit exposures and overall results of our risk management activities. 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 treatmentstreatment for our derivative financial instruments are described in further detail in Note 3.
Natural Gas Price Risk
Retail Energy Operations SouthStar’s use of derivative instruments is governed by a risk management policy, approved and monitored by its Finance and Risk Asset Management Committee, which prohibits the use of derivatives for speculative purposes.
SouthStar routinely utilizes various types of derivative financial instruments to mitigate certain natural gas price and weather risk inherent in the natural gas industry. This includes the active management of storage positions through a variety of hedging transactions for the purpose of managing exposures arising from changing natural gas prices. SouthStar uses these hedging instruments to lock in economic margins (as spreads between wholesale and retail natural gas prices widen between periods) and thereby minimize its exposure to declining operating margins.
The following tables illustrate the change in the net fair value of the derivative financial instruments during the three and sixnine months ended JuneSeptember 30, 2009 and 2008, and provide details of the net fair value of derivative financial instruments outstanding as of JuneSeptember 30, 2009.
| | Three months ended June 30, | | | Three months ended Sept. 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Net fair value of derivative financial instruments outstanding at beginning of period | | $ | (22 | ) | | $ | 6 | | | $ | (5 | ) | | $ | 8 | |
Derivative financial instruments realized or otherwise settled during period | | | 17 | | | | (1 | ) | | | 9 | | | | (4 | ) |
Change in net fair value of derivative financial instruments | | | - | | | | 3 | | | | 4 | | | | 8 | |
Net fair value of derivative financial instruments outstanding at end of period(1) | | | (5 | ) | | | 8 | | | | 8 | | | | 12 | |
Netting of cash collateral | | | 15 | | | | (8 | ) | | | 8 | | | | 20 | |
Cash collateral and net fair value of derivative financial instruments outstanding at end of period(1) | | $ | 10 | | | $ | - | | | $ | 16 | | | $ | 32 | |
(1) | Net fair value of derivative financial instruments outstanding includes $3 million premium at September 30, 2009 and $1 million at September 30, 2008 associated with weather derivatives. |
| | Six months ended June 30, | | | Nine months ended Sept. 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Net fair value of derivative financial instruments outstanding at beginning of period | | $ | (17 | ) | | $ | 10 | | | $ | (17 | ) | | $ | 10 | |
Derivative financial instruments realized or otherwise settled during period | | | 18 | | | | (10 | ) | | | 22 | | | | (10 | ) |
Change in net fair value of derivative financial instruments | | | (6 | ) | | | 8 | | | | 3 | | | | 12 | |
Net fair value of derivative financial instruments outstanding at end of period(1) | | | (5 | ) | | | 8 | | | | 8 | | | | 12 | |
Netting of cash collateral | | | 15 | | | | (8 | ) | | | 8 | | | | 20 | |
Cash collateral and net fair value of derivative financial instruments outstanding at end of period(1) | | $ | 10 | | | $ | - | | | $ | 16 | | | $ | 32 | |
(1) | Net fair value of derivative financial instruments outstanding includes $3 million premium at September 30, 2009 and $1 million at September 30, 2008 associated with weather derivatives. |
The sources of SouthStar’s net fair value of its natural gas-related derivative financial instruments at JuneSeptember 30, 2009, are as follows:
In millions | | Prices actively quoted (Level 1) (1) | | | Significant other observable inputs (Level 2) | | | Significant unobservable inputs (Level 3) | | | Prices actively quoted (Level 1) (1) | | | Significant other observable inputs (Level 2) (2) | |
Mature through | | | | | | | | | | | | | | | |
2009 | | $ | (12 | ) | | $ | - | | | $ | - | | | $ | (3 | ) | | $ | 1 | |
2010 | | | 7 | | | | - | | | | - | | | | 7 | | | | 3 | |
Total derivative financial instruments (2)(3) | | $ | (5 | ) | | $ | - | | | $ | - | | | $ | 4 | | | $ | 4 | |
(1) Valued using NYMEX futures prices. | | | | | | | | | | | | | |
(2) Excludes cash collateral amounts. | | | | | | | | | | | | | |
(1) | Valued using NYMEX futures prices |
(2) | Values primarily related to weather derivative transactions that are valued on an intrinsic basis in accordance with authoritative guidance related to financial instruments as based on heating degree days. Additionally includes values associated with basis transactions that represent the commodity from NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. |
(3) | Excludes cash collateral amounts. |
The following tables include the fair values and average values of SouthStar’s derivative instruments as of the dates indicated. SouthStar bases the average values on monthly averages for the sixnine months ended JuneSeptember 30, 2009 and 2008.
| | | Derivative financial instruments average fair values (1) at June 30, | | | Derivative financial instruments average fair values (1) at September 30, | |
In millions | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Asset | | | $ | 11 | | | $ | 7 | | | $ | 12 | | | $ | 13 | |
Liability | | | | 28 | | | | 1 | | | | 23 | | | | 5 | |
(1) Excludes cash collateral amounts.
| | Derivative financial instruments fair values netted with cash collateral at | | | Derivative financial instruments fair values netted with cash collateral at | |
In millions | | June 30, 2009 | | | Dec. 31, 2008 | | | June 30, 2008 | | | Sept. 30, 2009 | | | Dec. 31, 2008 | | | Sept. 30, 2008 | |
Asset | | $ | 10 | | | $ | 16 | | | $ | 5 | | | $ | 16 | | | $ | 16 | | | $ | 33 | |
Liability | | | - | | | | 2 | | | | 5 | | | | - | | | | 2 | | | | 1 | |
Value at Risk A 95% confidence interval is used to evaluate VaR exposure. A 95% confidence interval means that over the holding period, an actual loss in portfolio value is not expected to exceed the calculated VaR more than 5% of the time. We calculate VaR based on the variance-covariance technique. This technique requires several assumptions for the basis of the calculation, such as price distribution, 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. SouthStar’s portfolio of positions for the sixnine months ended JuneSeptember 30, 2009 and 2008 had quarterly average 1-day holding period VaRs of less than $100,000 and its high, low and period end 1-day holding period VaR were immaterial.
Wholesale Services Sequent routinely utilizes various types of derivative financial instruments to mitigate certain natural gas price risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts and financial swap agreements.
The following tables include the fair values and average values of Sequent’s derivative financial instruments as of the dates indicated. Sequent bases the average values on monthly averages for the sixnine months ended JuneSeptember 30, 2009 and 2008.
| | | Derivative financial instruments average values (1) at June 30, | | | Derivative financial instruments average values (1) at September 30, | |
In millions | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Asset | | | $ | 176 | | | $ | 48 | | | $ | 169 | | | $ | 72 | |
Liability | | | | 84 | | | | 78 | | | | 75 | | | | 48 | |
(1) | Excludes cash collateral amounts. |
| | Derivative financial instruments fair values netted with cash collateral at | | | Derivative financial instruments fair values netted with cash collateral at | |
In millions | | June 30, 2009 | | | Dec. 31, 2008 | | | June 30, 2008 | | | Sept. 30, 2009 | | | Dec. 31, 2008 | | | Sept. 30, 2008 | |
Asset | | $ | 183 | | | $ | 206 | | | $ | 90 | | | $ | 146 | | | $ | 206 | | | $ | 140 | |
Liability | | | 18 | | | | 27 | | | | 85 | | | | 17 | | | | 27 | | | | 24 | |
Sequent experienced a $27 million decrease and a $26 million and $153 million decreasesincrease in the net fair value of its outstanding contracts during the first sixnine months of 2009 and 2008, respectively, due to changes in the fair value of derivative financial instruments utilized in its energy marketing and risk management activities and contract settlements.
The following tables illustrate the change in the net fair value of Sequent’s derivative financial instruments during the three and sixnine months ended JuneSeptember 30, 2009 and 2008, and provide details of the net fair value of contracts outstanding as of JuneSeptember 30, 2009.
| | Three months ended June 30, | |
In millions | | 2009 | | | 2008 | |
Net fair value of derivative financial instruments outstanding at beginning of period | | $ | 7 | | | $ | (18 | ) |
Derivative financial instruments realized or otherwise settled during period | | | 33 | | | | 5 | |
Change in net fair value of derivative financial instruments | | | 16 | | | | (83 | ) |
Net fair value of derivative financial instruments outstanding at end of period | | | 56 | | | | (96 | ) |
Netting of cash collateral | | | 109 | | | | 101 | |
Cash collateral and net fair value of derivative financial instruments outstanding at end of period | | $ | 165 | | | $ | 5 | |
Glossary of Key Terms
| | Six months ended June 30, | | | Three months ended September 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Net fair value of derivative financial instruments outstanding at beginning of period | | $ | 82 | | | $ | 57 | | | $ | 56 | | | $ | (96 | ) |
Derivative financial instruments realized or otherwise settled during period | | | (78 | ) | | | (45 | ) | | | (9 | ) | | | 60 | |
Change in net fair value of derivative financial instruments | | | 52 | | | | (108 | ) | | | 8 | | | | 119 | |
Net fair value of derivative financial instruments outstanding at end of period | | | 56 | | | | (96 | ) | | | 55 | | | | 83 | |
Netting of cash collateral | | | 109 | | | | 101 | | | | 74 | | | | 33 | |
Cash collateral and net fair value of derivative financial instruments outstanding at end of period | | $ | 165 | | | $ | 5 | | | $ | 129 | | | $ | 116 | |
| | Nine months ended September 30, | |
In millions | | 2009 | | | 2008 | |
Net fair value of derivative financial instruments outstanding at beginning of period | | $ | 82 | | | $ | 57 | |
Derivative financial instruments realized or otherwise settled during period | | | (77 | ) | | | (48 | ) |
Change in net fair value of derivative financial instruments | | | 50 | | | | 74 | |
Net fair value of derivative financial instruments outstanding at end of period | | | 55 | | | | 83 | |
Netting of cash collateral | | | 74 | | | | 33 | |
Cash collateral and net fair value of derivative financial instruments outstanding at end of period | | $ | 129 | | | $ | 116 | |
The sources of Sequent’s net fair value of its natural gas-related derivative financial instruments at JuneSeptember 30, 2009, are as follows:
In millions | In millions | | | Prices actively quoted (Level 1) (1) | | | Significant other observable inputs (Level 2) (2) | | | Significant unobservable inputs (Level 3) | | | | Prices actively quoted (Level 1) (1) | | | Significant other observable inputs (Level 2) (2) | |
Mature through | Mature through | | | | | | | | | | | | | | | | | |
2009 | 2009 | | | $ | (65 | ) | | $ | 89 | | | $ | - | | | | $ | (21 | ) | | $ | 29 | |
| 2010 - 2011 | | | | (2 | ) | | | 27 | | | | - | | |
| 2012 - 2014 | | | | 1 | | | | 6 | | | | - | | |
2010 - 2011 | | 2010 - 2011 | | | (21 | ) | | | 66 | |
2012 - 2014 | | | | | 1 | | | | 1 | |
Total derivative financial instruments (3) | Total derivative financial instruments (3) | | | $ | (66 | ) | | $ | 122 | | | $ | - | | | | $ | (41 | ) | | $ | 96 | |
(1) | Valued using NYMEX futures prices and other quoted sources. |
(2) | Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. |
(3) | Excludes cash collateral amounts. |
Value at Risk 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 Sequent generally manages physical gas assets and economically protects its positions by hedging in the futures markets, its open exposure is generally immaterial, permitting Sequent to operate within relatively low VaR limits. Sequent employs daily risk testing, using both VaR and stress testing, to evaluate the risks of its open positions.
Sequent’s management actively monitors open natural gas positions and the resulting VaR. Sequent continues to maintain a relatively matched book, where its total buy volume is close to sell volume with minimal open natural gas price risk. Based on a 95% confidence interval and employing a 1-day holding period for all positions, Sequent’s portfolio of positions for the three and sixnine months ended JuneSeptember 30, 2009 and 2008 had the following VaRs.
| | Three months ended June 30, | | | Six months ended June 30, | | | Three months ended September 30, | | | Nine months ended September 30, | |
In millions | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Period end | | $ | 2.6 | | | $ | 2.3 | | | $ | 2.6 | | | $ | 2.3 | | | $ | 1.9 | | | $ | 1.9 | | | $ | 1.9 | | | $ | 1.9 | |
Average | | | 2.2 | | | | 1.8 | | | | 2.1 | | | | 1.6 | | | | 1.6 | | | | 1.8 | | | | 1.9 | | | | 1.7 | |
High | | | 3.1 | | | | 2.5 | | | | 3.3 | | | | 2.9 | | | | 2.5 | | | | 2.4 | | | | 3.3 | | | | 2.9 | |
Low | | | 1.7 | | | | 1.2 | | | | 1.3 | | | | 0.8 | | | | 1.2 | | | | 1.0 | | | | 1.2 | | | | 0.8 | |
Energy Investments In 2009, Golden Triangle Storage began using derivative financial instruments to reduce its exposure during the construction of the storage caverns to the risk of changes with the price of natural gas that will be purchased in future periods for pad gas, which includes volumes of non-working natural gas used to maintain the operational integrity of the caverns. As of September 30, 2009, Golden Triangle Storage had locked-in the price of approximately 67% of the required pad gas for the first storage cavern or 2 Bcf with a fair value of approximately $1 million.
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. Based on $578$470 million of variable-rate debt, which includes $417$309 million of our variable-rate short-term debt and $161 million of variable-rate gas facility revenue bonds outstanding at JuneSeptember 30, 2009, a 100 basis point change in average market interest rates from 0.5% to 1.5% would have resulted in an increase in pretax interest expense of $6$5 million on an annualized basis.
Credit Risk
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 Sequent is engaged in more than one outstanding derivative transaction with the same counterparty and it has 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 Sequent’s credit risk. Sequent also uses other netting agreements with certain counterparties with whom it 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. Sequent conducts credit evaluations and obtains appropriate internal approvals for its counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, Sequent requires credit enhancements by way of guaranty, cash deposit or letter of credit for counterparties that do not meet the minimum long-term debt rating threshold.have investment grade ratings.
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 JuneSeptember 30, 2009, Sequent’s top 20 counterparties represented approximately 65%64% of the total counterparty exposure of $286$223 million, derived by adding together the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures.
As of JuneSeptember 30, 2009 and June 30, 2008 Sequent’s counterparties, or the counterparties’ guarantors, had a weighted-average S&P equivalent credit rating of A,A-, which is slightly improved fromconsistent with the credit rating of A-ratings at September 30, 2008 and December 31, 2008. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P and Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being the 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 for that counterparty. To arrive at the weighted average credit rating, each counterparty is assigned an internal ratio, which is multiplied by their credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties’ exposures, and this numeric value is then converted to an S&P equivalent. There were no credit defaults with Sequent’s counterparties.
The following table shows Sequent’s third-party natural gas contracts receivable and payable positions as of JuneSeptember 30, 2009 and 2008 and December 31, 2008.
| | Gross receivables | | | Gross payables | | | Gross receivables | | | Gross payables | |
| | June 30, | | | Dec. 31, | | | June 30, | | | June 30, | | | Dec. 31, | | | June 30, | | | Sept. 30, | | | Dec. 31, | | | Sept. 30, | | | Sept. 30, | | | Dec. 31, | | | Sept. 30, | |
In millions | | 2009 | | | 2008 | | | 2008 | | | 2009 | | | 2008 | | | 2008 | | | 2009 | | | 2008 | | | 2008 | | | 2009 | | | 2008 | | | 2008 | |
Netting agreements in place: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Counterparty is investment grade | | $ | 207 | | | $ | 398 | | | $ | 590 | | | $ | 170 | | | $ | 266 | | | $ | 551 | | | $ | 163 | | | $ | 398 | | | $ | 446 | | | $ | 113 | | | $ | 266 | | | $ | 338 | |
Counterparty is non-investment grade | | | 12 | | | | 15 | | | | 37 | | | | 39 | | | | 41 | | | | 40 | | | | 3 | | | | 15 | | | | 10 | | | | 12 | | | | 41 | | | | 16 | |
Counterparty has no external rating | | | 50 | | | | 129 | | | | 177 | | | | 104 | | | | 228 | | | | 334 | | | | 45 | | | | 129 | | | | 76 | | | | 119 | | | | 228 | | | | 212 | |
No netting agreements in place: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Counterparty is investment grade | | | 5 | | | | 7 | | | | 3 | | | | 4 | | | | 4 | | | | 2 | | | | 5 | | | | 7 | | | | 3 | | | | 1 | | | | 4 | | | | 2 | |
Counterparty is non-investment grade | | | 2 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Amount recorded on statements of financial position | | $ | 276 | | | $ | 549 | | | $ | 807 | | | $ | 317 | | | $ | 539 | | | $ | 927 | | | $ | 216 | | | $ | 549 | | | $ | 535 | | | $ | 245 | | | $ | 539 | | | $ | 568 | |
Sequent has certain trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements 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. If such collateral were not posted, Sequent’s ability to continue transacting business with these counterparties would be impaired. If 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 $9$6 million at JuneSeptember 30, 2009, which would not have a material impact to our condensed consolidated results of operations, cash flows or financial condition.
There have been no other significant changes to our credit risk related to our other segments, as described in Item 7A ”Quantitative and Qualitative Disclosures about Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2008.
(a) Evaluation 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 in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of JuneSeptember 30, 2009, the end of the period covered by this report. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of JuneSeptember 30, 2009, 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.
(b) Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II - OTHER INFORMATION
The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities and litigation incidental to the business. For information regarding pending federal and state regulatory matters, see “Note 7 - Commitments and Contingencies” contained in Item 1 of Part I under the caption “Notes to Condensed Consolidated Financial Statements (Unaudited).”
In March 2009, Piedmont filed a lawsuit in the Court of Chancery of the State of Delaware against us asking the court to enter a judgment declaring that our right to purchase Piedmont’s ownership interest in SouthStar expires on November 1, 2009. We have reached a settlement agreement with Piedmont that will dismiss the lawsuit and will result in a restructuring of the ownership interests in the SouthStar joint venture. Under the terms of the agreement, which has been approved by the boards of directors of both companies, we will purchase an additional 15% ownership share in the joint venture from Piedmont for $58 million. As a result, we will own 85% of the SouthStar joint venture, and will be entitled to 85% of the annual earnings from the business, while Piedmont will retain the remaining 15% share. As part of the agreement, our interest will remain a noncontrolling interest and we will not have any further option rights to Piedmont’s remaining 15% ownership interest. The agreement was approved by the Georgia Commission in October 2009 and the effective date of the transaction will be January 1, 2010, and the agreement is subject to approval by the Georgia Commission.
2010.
With regard to other legal proceedings, we are a party, as both plaintiff and defendant, to a number of other suits, claims and counterclaims on an ongoing basis. Management believes that the outcome of all such other litigation in which it is involved will not have a material adverse effect on our consolidated financial statements.
There were noThe following table sets forth information about purchases of our common stock by us and any affiliated purchasers during the three months ended JuneSeptember 30, 2009.
Item 4. Submission of Matters to a Vote of Security Holders
The annual meeting of shareholders was held in Atlanta, Georgia on April 29, 2009. Holders of an aggregate of 77,086,652additional shares of our commonthat may be repurchased, and we may terminate or limit the stock repurchase program at any time. We currently anticipate holding the close of business on February 20, 2009, were entitled to vote at the meeting, of which 67,422,393 or 87.46% of the eligible votingrepurchased shares were represented in person or by proxy. At the annual meeting, our shareholders were presented with three proposals, as set forth in our proxy statement. Our shareholders voted as follows:treasury shares.
Proposal 1 – Election of Directors
| | For | | | Withheld | |
Charles R. Crisp | | | 66,657,056 | | | | 765,337 | |
Wyck A. Knox, Jr. | | | 66,480,924 | | | | 941,469 | |
Dennis M. Love | | | 66,344,672 | | | | 1,077,721 | |
Charles H. McTier | | | 66,595,675 | | | | 826,718 | |
Henry C. Wolf | | | 66,683,058 | | | | 739,335 | |
The term of office of each of the following directors continued after the meeting: Sandra N. Bane, Thomas D. Bell, Jr., Arthur E. Johnson, Dean R. O’Hare, D. Raymond Riddle, James A. Rubright, John W. Somerhalder II, Felker W. Ward, Jr. and Bettina M. Whyte.
Proposal 2 – Amend our articles of incorporation to eliminate the classification of the board of directors.
Period | | Total number of shares purchased (1) (2) | | | 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 publicly announced plans or programs (2) | |
July 2009 | | | - | | | $ | - | | | | - | | | | 4,950,951 | |
August 2009 | | | 2,443 | | | | 33.64 | | | | - | | | | 4,950,951 | |
September 2009 | | | - | | | | - | | | | - | | | | 4,950,951 | |
Total third quarter | | | 2,443 | | | $ | 33.64 | | | | - | | | | | |
For(1) | On March 20, 2001, our Board of Directors approved the purchase of up to 600,000 shares of our common stock in the open market to be used for issuances under the Officer Incentive Plan (Officer Plan). We purchased 2,443 shares for such purposes in the third quarter of 2009. As of September 30, 2009, we had purchased a total of 324,860 of the 600,000 shares authorized for purchase, leaving 275,140 shares available for purchase under this program. |
(2) | | 65,838,999 | |
Against | | | 970,551 | |
Abstain | | | 612,843 | |
Broker Non-Votes | | | - | On February 3, 2006, we announced that our Board of Directors had authorized a plan to repurchase up to a total of 8 million shares of our common stock, excluding the shares remaining available for purchase in connection with the Officer Plan as described in note (1) above, over a five-year period. |
In connection with the settlement reached with Piedmont previously described under “Item 1 – RatificationLegal Proceedings,” on July 29, 2009, GNG entered into a Third Amendment to the Amended and Restated Limited Liability Company Agreement by and between GNG and Piedmont. The material terms of the appointment of PricewaterhouseCoopers LLPthird Amendment, which is filed herewith as our independent registered public accounting firm for 2009.
For | | | 66,987,874 | |
Against | | | 158,500 | |
Abstain | | | 276,019 | |
Broker Non-Votes | | | - | |
Exhibit 10.1, are summarized in the second paragraph under “Item 1 – Legal Proceedings” above, which summary is incorporated by reference under this Item 5.
3.1(a)1.1 | AmendedUnderwriting Agreement, dated August 5, 2009, by and Restated Articles of Incorporation filed November 2, 2005, with the Secretary of Stateamong AGL Capital Corporation, as issuer, AGL Resources Inc., as guarantor, and Wells Fargo Securities, LLC, for itself and on behalf of the state of Georgiaseveral underwriters listed on Schedule A thereto (Exhibit 3.1,1.1, AGL Resources, Inc. Form 8-K dated November, 2005)August 5, 2009). |
3.1(b)4.1 | Articles of Amendment to the Amended and Restated Articles of Incorporation filed May 4, 2009, with the Secretary of State of the state of Georgia.Specimen AGL Capital Corporation, 5.25% Senior Notes due 2019 (Exhibit 4.1, AGL Resources, Inc. Form 8-K dated August 5, 2009). |
4.2 | Form of Guarantee of AGL Resources Inc. dated as of August 10, 2009 regarding the AGL Capital Corporation 5.25% Senior Notes due 2019 (Exhibit 4.2, AGL Resources, Inc. Form 8-K dated August 5, 2009). |
10.1 | Third Amendment to Amended and Restated Limited Liability Company Agreement, dated July 29, 2009, by and between Georgia Natural Gas Company and Piedmont Energy Company.Company (Exhibit 10, AGL Resources, Inc. Form 10-Q for the quarter ended June 30, 2009). |
10.2 | Environmental Services Agreement, dated July 16, 2009, by and between Atlanta Gas Light Company and MACTEC Engineering and Consulting, Inc. |
12 | Statement of Computation of Ratio of Earnings to Fixed Charges. |
31.1 | Certification of John W. Somerhalder II pursuant to Rule 13a - 14(a). |
31.2 | Certification of Andrew W. Evans pursuant to Rule 13a - 14(a). |
32.1 | Certification of John W. Somerhalder II pursuant to 18 U.S.C. Section 1350. |
32.2 | Certification of Andrew W. Evans pursuant to 18 U.S.C. Section 1350. |
101.INS | XBRL Instance Document. (1) |
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101.SCH | XBRL Taxonomy Extension Schema. (1) |
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101.CAL | XBRL Taxonomy Extension Calculation Linkbase. (1) |
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101.DEF | XBRL Taxonomy Definition Linkbase. (1) |
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101.LAB | XBRL Taxonomy Extension Labels Linkbase. (1) |
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101.PRE | XBRL Taxonomy Extension Presentation Linkbase. (1) |
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
AGL RESOURCES INC.
(Registrant)
Date: July 30,October 29, 2009 /s/ Andrew W. Evans
Executive Vice President, Chief Financial Officer and Treasurer