See Notes to Condensed Consolidated Financial Statements (Unaudited).
AGL RESOURCES INC. AND SUBSIDIARIES
See Notes to Condensed Consolidated Financial Statements (Unaudited).
AGL RESOURCES INC. AND SUBSIDIARIES
See Notes to Condensed Consolidated Financial Statements (Unaudited).
The December 31, 2012 Condensed Consolidated 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 and regulations of the SEC. In accordance with such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with GAAP. Our unaudited 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. These unaudited Condensed Consolidated Financial Statements should be read in conjunction with our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.
Due to the seasonal nature of our business and other factors, our results of operations and our financial condition for the periods presented are not necessarily indicative of the results of operations and financial condition to be expected for or as of or for any other period.
Except for Nicor Gas, our gas inventories and the inventories we hold for Marketers are accounted for using the WACOG.carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers including SouthStar, sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns on a monthly basis, the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory. Atlanta Gas Light also retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. See Note 9 for information regarding a regulatory filing by Atlanta Gas Light related to gas inventory.
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 our wholesale services segment 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. While the amounts due from or owed to wholesale services’ counterparties are settled net, they are recorded on a gross basis in our unaudited Condensed Consolidated Statements of Financial Position as energy marketing receivables and energy marketing payables.
The fair value of the natural gas derivative instruments that we use to manage exposures arising from changing 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 indices to value substantially all of our derivative instruments. See Note 3 and Note 4 for additional derivative disclosures.
We account for the financial effects of regulation in accordance with authoritative guidance related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs and estimated future expenditures that otherwise would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs or expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for estimated expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulatory commissions. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs consistent with our historical recoveries. In the event that the provisions of authoritative guidance related to regulated operations were no longer applicable, we would recognize a write-off of regulatory assets that would result in a charge to net income and be classified as an extraordinary item.
Our regulatory assets and liabilities are summarized in the following table.
We compute basic earnings per common share attributable to AGL Resources Inc. common shareholders by dividing our net income attributable to AGL Resources Inc. by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. common shareholders reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. common shareholders that could occur when potentially dilutive common shares are added to common shares outstanding.
We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options. The vesting of certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance criteria. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares forunderlying the options exceeds the respective periods.exercise prices of the stock options.
The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. common shareholders for the periods presented, if performance units currently earned under the plan ultimately vest and if stock options currently exercisable at prices below the average market prices are exercised.
On January 31, 2013, our retail operations segment acquired approximately 500,000 service plans and certain other assets from NiSource Inc. for $120 million, plus $2 million of working capital. These service plans provide home warranty protection solutions and energy efficiency leasing solutions for residential and small business utility customers and complementscomplement the retail services business acquired in the Nicor merger. The preliminary allocation of the purchase price is as follows:
Intangible assets related to this acquisition are primarily customer relationships of $47 million and trade names of $17 million. The amortization periods are estimated to be 14 years for customer relationships and 10 years for trade names.
A description of our objectives and strategies for using derivative instruments, related accounting policies and methods used to determine their fair values are described in Note 2. See Note 3 for additional fair value disclosures.
Derivative Instruments in our Unaudited Condensed Consolidated Statements of Financial Position
The following table presents the fair values and unaudited Condensed Consolidated Statements of Financial Position classifications of our derivative instruments as of the periodsdates presented.
| Unaudited Condensed Consolidated Statements of Financial | | March 31, 2013 | | | December 31, 2012 | | | March 31, 2012 | | | | | | June 30, 2013 | | | December 31, 2012 | | | June 30, 2012 | | | December 31, 2011 | |
In millions | Position Location (1) (2) | | Assets | | | Liabilities | | | Assets | | | Liabilities | | | Assets | | | Liabilities | | | Classification (1) (2) | | | Assets | | | Liabilities | | | Assets | | | Liabilities | | | Assets | | | Liabilities | | | Assets | | | Liabilities | |
Designated as cash flow hedges and fair value hedges | Designated as cash flow hedges and fair value hedges | | | | | | | | | | | | | | | | | | | Designated as cash flow hedges and fair value hedges | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas contracts | Current | | $ | 3 | | | $ | (1 | ) | | $ | 1 | | | $ | (2 | ) | | $ | 5 | | | $ | (11 | ) | | Current | | | $ | 2 | | | $ | (1 | ) | | $ | 1 | | | $ | (2 | ) | | $ | 6 | | | $ | (7 | ) | | $ | 9 | | | $ | (12 | ) |
Natural gas contracts | Long-term | | | - | | | | - | | | | 3 | | | | - | | | | - | | | | - | | | Long-term | | | | - | | | | - | | | | 3 | | | | - | | | | - | | | | - | | | | - | | | | - | |
Interest rate swap agreements | Current | | | 5 | | | | - | | | | - | | | | - | | | | - | | | | - | | |
Interest rate swap agreements | Long-term | | | - | | | | - | | | | - | | | | - | | | | 9 | | | | (11 | ) | | Long-term | | | | - | | | | - | | | | - | | | | - | | | | 17 | | | | - | | | | 13 | | | | (13 | ) |
Total | | | | 8 | | | | (1 | ) | | | 4 | | | | (2 | ) | | | 14 | | | | (22 | ) | | | | | | | 2 | | | | (1 | ) | | | 4 | | | | (2 | ) | | | 23 | | | | (7 | ) | | | 22 | | | | (25 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Not designated as cash flow hedges | Not designated as cash flow hedges | | | | | | | | | | | | | | | | | | | | | | | | | Not designated as cash flow hedges | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas contracts | Current | | | 332 | | | | (327 | ) | | | 394 | | | | (355 | ) | | | 683 | | | | (718 | ) | | Current | | | | 456 | | | | (445 | ) | | | 394 | | | | (355 | ) | | | 493 | | | | (489 | ) | | | 706 | | | | (689 | ) |
Natural gas contracts | Long-term | | | 46 | | | | (48 | ) | | | 45 | | | | (50 | ) | | | 82 | | | | (85 | ) | | Long-term | | | | 124 | | | | (139 | ) | | | 45 | | | | (50 | ) | | | 69 | | | | (66 | ) | | | 133 | | | | (116 | ) |
Total | | | | 378 | | | | (375 | ) | | | 439 | | | | (405 | ) | | | 765 | | | | (803 | ) | | | | | | | 580 | | | | (584 | ) | | | 439 | | | | (405 | ) | | | 562 | | | | (555 | ) | | | 839 | | | | (805 | ) |
Gross amount of recognized assets and liabilities | Gross amount of recognized assets and liabilities | | | 386 | | | | (376 | ) | | | 443 | | | | (407 | ) | | | 779 | | | | (825 | ) | Gross amount of recognized assets and liabilities | | | | 582 | | | | (585 | ) | | | 443 | | | | (407 | ) | | | 585 | | | | (562 | ) | | | 861 | | | | (830 | ) |
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position | Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position | | | (275 | ) | | | 352 | | | | (299 | ) | | | 368 | | | | (513 | ) | | | 722 | | Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position | | | | (452 | ) | | | 546 | | | | (299 | ) | | | 368 | | | | (359 | ) | | | 496 | | | | (573 | ) | | | 720 | |
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position | Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position | | $ | 111 | | | $ | (24 | ) | | $ | 144 | | | $ | (39 | ) | | $ | 266 | | | $ | (103 | ) | Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position | | | $ | 130 | | | $ | (39 | ) | | $ | 144 | | | $ | (39 | ) | | $ | 226 | | | $ | (66 | ) | | $ | 288 | | | $ | (110 | ) |
(1) | The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Statements of Financial Position to the extent that we have netting arrangements with the counterparties. |
(2) | As required by the authoritative guidance related to derivatives and hedging, the gross amounts of recognized assets and liabilities above do not include cash collateral held on deposit in broker margin accounts of $77$94 million as of March 31,June 30, 2013, $69 million as of December 31, 2012, and $209$137 million as of MarchJune 30, 2012 and $147 million as of December 31, 2012.2011. Cash collateral is included in the “Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position” line of this table. |
Derivative Instruments Impacts in our Unaudited Condensed Consolidated Statements of Income
The following table presents the amounts of our derivative instruments in our unaudited Condensed Consolidated Statements of Income for the three months ended March 31, 2013 and 2012.periods presented.
| | | Three months ended June 30, | | | Six months ended June 30, | |
In millions | | 2013 | | | 2012 | | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
Designated as cash flow hedges | | | | | | | | | | | | | | | | | | |
Natural gas contracts - loss reclassified from OCI into cost of goods sold for settlement of hedged item | | $ | - | | | $ | (1 | ) | |
Natural gas contracts - gain reclassified from OCI into cost of goods sold | | | $ | 1 | | | $ | 3 | | | $ | 1 | | | $ | 4 | |
Natural gas contracts – gain reclassified from OCI into operation and maintenance expense | | | | - | | | | 1 | | | | - | | | | 1 | |
Natural gas contracts – loss recognized in OCI (effective portion) | | | | - | | | | (1 | ) | | | - | | | | - | |
Interest rate swaps - ineffectiveness recorded as an offset to interest expense | | | (3 | ) | | | 2 | | | | - | | | | (1 | ) | | | (3 | ) | | | (3 | ) |
| | | | | | | | | |
Not designated as hedges | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas contracts - net fair value adjustments recorded in operating revenues (1) | | | (24 | ) | | | 4 | | | | 22 | | | | 15 | | | | (2 | ) | | | 19 | |
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2) | | | - | | | | (2 | ) | | | (1 | ) | | | (1 | ) | | | (1 | ) | | | (3 | ) |
Natural gas contracts - net value adjustments recorded in operation and maintenance expense | | | - | | | | (1 | ) | |
Total (losses) gains on derivative instruments | | $ | (27 | ) | | $ | 2 | | |
Total gains (losses) on derivative instruments | | | $ | 22 | | | $ | 16 | | | $ | (5 | ) | | $ | 18 | |
(1) | Associated with the fair value of existing derivative instruments at March 31,June 30, 2013 and 2012. |
(2) | Excludes losses recorded in operating revenues or cost of goods sold associated with weather derivatives of $2$3 million for the threesix months ended March 31,June 30, 2013 and gains of $14 million for the threesix months ended March 31,June 30, 2012. |
Any amounts recognized in operating income, related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur were immaterial for the threesix months ended March 31,June 30, 2013 and 2012.
Our expected pre-tax net income (loss)loss to be reclassified from OCI and recognized in cost of goods sold, operation and maintenance expenses, operating revenues and interest expense in our unaudited Condensed Consolidated Statements of Income over the next 12 months is $2$1 million. These pre-tax deferred gains and losses are recorded in OCI related to natural gas derivative contracts associated with retail operations and Nicor Gas.Gas and interest rate swaps with AGL Capital. The expected losses are based upon the fair values of these financial instruments at March 31,June 30, 2013.
There have been no other significant changes to our derivative instruments, as described in Note 2 and Note 4 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.
Note 5- Employee Benefit Plans
Pension Benefits
On December 31, 2012, the AGL Resources Inc. Retirement Plan (AGL Plan), the Nicor Companies Pension and Retirement Plan (Nicor Plan) and the Employees’ Retirement Plan of NUI Corporation (NUI Plan) were merged with, and into, the AGL Plan. The eligibility and benefit terms for participants under the Nicor Plan and the NUI Plan were not changed as a result of the plan merger. The AGL Plan is described in Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.
Following are the components of our pension benefit costs for the periods indicated.
| | Three months ended March 31, | | | Three months ended June 30, | | | Six months ended June 30, | |
In millions | | 2013 | | | 2012 | | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
Service cost | | $ | 8 | | | $ | 7 | | | $ | 7 | | | $ | 7 | | | $ | 15 | | | $ | 14 | |
Interest cost | | | 10 | | | | 11 | | | | 11 | | | | 11 | | | | 21 | | | | 22 | |
Expected return on plan assets | | | (16 | ) | | | (16 | ) | | | (15 | ) | | | (16 | ) | | | (31 | ) | | | (32 | ) |
Net amortization of prior service cost | | | - | | | | (1 | ) | | | (1 | ) | | | - | | | | (1 | ) | | | (1 | ) |
Recognized actuarial loss | | | 8 | | | | 9 | | | | 9 | | | | 8 | | | | 17 | | | | 17 | |
Net periodic pension benefit cost | | $ | 10 | | | $ | 10 | | | $ | 11 | | | $ | 10 | | | $ | 21 | | | $ | 20 | |
Retiree Welfare Benefits
On December 31, 2012, the Nicor Gas Welfare Benefit Plan (Nicor Welfare Plan) was terminated and as of January 1, 2013, all participants under that plan became eligible to participate in the Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Welfare Plan). This change in plan participation eligibility did not affect the benefit terms under the predecessor plans. The Nicor Welfare Plan benefits are now being offered to such participants under the AGL Welfare Plan. The benefits of the AGL Welfare Plan are described in Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.
Following are the components of our retiree welfare benefit costs for the periods indicated.
| | Three months ended March 31, | | | Three months ended June 30, | | | Six months ended June 30, | |
In millions | | 2013 | | | 2012 | | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
| | $ | 1 | | | $ | 1 | | | $ | - | | | $ | 1 | | | $ | 1 | | | $ | 2 | |
| | | 3 | | | | 4 | | | | 4 | | | | 4 | | | | 7 | | | | 8 | |
Expected return on plan assets | | | (1 | ) | | | (1 | ) | | | (2 | ) | | | (2 | ) | | | (3 | ) | | | (3 | ) |
Net amortization of prior service cost | | | (1 | ) | | | (1 | ) | | | (1 | ) | | | - | | | | (2 | ) | | | (1 | ) |
Recognized actuarial loss | | | 2 | | | | 3 | | | | 2 | | | | 2 | | | | 4 | | | | 5 | |
Net periodic welfare benefit cost | | $ | 4 | | | $ | 6 | | | $ | 3 | | | $ | 5 | | | $ | 7 | | | $ | 11 | |
Capitalized Costs
A portion of the netNet pension benefit and net periodic welfare benefit costs have beenare included in operation and maintenance expense, except for a portion that is capitalized as a cost of constructing natural gas distribution facilities and the remainder is included in operation and maintenance expenses, net of amounts charged to affiliates.facilities.
Contributions
Our employees generally do not contribute to these pension and retiree welfare plans. We fund the qualified pension plan by contributing at least the minimum amounts required by applicable regulations and as recommended by our actuary. However, we may contribute in excess of the minimum required amounts.amounts.
As a result of merging the pension plans, there were no contributions required during the threesix months ended March 31,June 30, 2013. We contributed a combined $17$24 million to the AGL Plan and the NUI Plan during the same period last year. For more information on our pension plans, see Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.
Note 6 - Debt and Credit Facilities
The following table provides maturity dates, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities that are included in our unaudited Condensed Consolidated Statements of Financial Position. For additional information on our debt, see Note 8 in our Consolidated Financial Statements and related notes in Item 8 of our 2012 Form 10-K.
| | | | | March 31, 2013 | | | | | | March 31, 2012 | | | | | | June 30, 2013 | | | | | | June 30, 2012 | |
Dollars in millions | | Year(s) due | | | Weighted average interest rate (1) | | | Outstanding | | | Outstanding at December 31, 2012 | | | Weighted average interest rate (1) | | | Outstanding | | | Year(s) due | | | Weighted average interest rate (1) | | | Outstanding | | | Outstanding at December 31, 2012 | | | Weighted average interest rate (1) | | | Outstanding | |
Short-term debt | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Commercial paper- AGL Capital (2) | | 2013 | | | | 0.5 | % | | $ | 868 | | | $ | 1,063 | | | | 0.5 | % | | $ | 625 | | |
Commercial paper- Nicor Gas (2) | | 2013 | | | | 0.4 | | | | - | | | | 314 | | | | 0.5 | | | | 105 | | |
Commercial paper - AGL Capital (2) | | | 2013 | | | | 0.5 | % | | $ | 521 | | | $ | 1,063 | | | | 0.5 | % | | $ | 731 | |
Commercial paper - Nicor Gas | | | 2013 | | | | 0.4 | | | | - | | | | 314 | | | | 0.5 | | | | - | |
Total short-term debt | | | | | | 0.5 | % | | $ | 868 | | | $ | 1,377 | | | | 0.5 | % | | $ | 730 | | | | | | | 0.5 | | | | 521 | | | | 1,377 | | | | 0.5 | | | | 731 | |
Current portion of long-term debt and capital leases | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current portion of long-term debt | | 2013 | | | | 4.5 | % | | $ | 225 | | | $ | 225 | | | | 8.3 | % | | $ | 15 | | | 2013 | | | | 4.5 | | | | - | | | | 225 | | | | 4.7 | | | | 230 | |
Current portion of capital leases | | 2013 | | | | 5.0 | | | | 1 | | | | 1 | | | | 4.9 | | | | 2 | | | 2013 | | | | 5.0 | | | | - | | | | 1 | | | | 4.9 | | | | 1 | |
Total current portion of long-term debt and capital leases | | | | | | 4.5 | % | | $ | 226 | | | $ | 226 | | | | 8.0 | % | | $ | 17 | | | | | | | 4.5 | % | | $ | - | | | $ | 226 | | | | 4.7 | % | | $ | 231 | |
Long-term debt - excluding current portion | Long-term debt - excluding current portion | | | | | | | | | | | | | | | | | | | | | | Long-term debt - excluding current portion | | | | | | | | | | | | | | | | | | | | | |
Senior notes | | | 2015-2041 | | | | 5.1 | % | | $ | 2,325 | | | $ | 2,325 | | | | 5.1 | % | | $ | 2,550 | | | | 2015-2043 | | | | 5.1 | % | | $ | 2,825 | | | $ | 2,325 | | | | 5.1 | % | | $ | 2,325 | |
First mortgage bonds | | | 2016-2038 | | | | 5.6 | | | | 500 | | | | 500 | | | | 5.6 | | | | 500 | | | | 2016-2038 | | | | 5.6 | | | | 500 | | | | 500 | | | | 5.6 | | | | 500 | |
Gas facility revenue bonds | | | 2022-2033 | | | | 0.3 | | | | 200 | | | | 200 | | | | 1.1 | | | | 200 | | | | 2022-2033 | | | | 0.5 | | | | 200 | | | | 200 | | | | 1.2 | | | | 200 | |
Medium-term notes | | | 2017-2027 | | | | 7.8 | | | | 181 | | | | 181 | | | | 7.8 | | | | 181 | | | | 2017-2027 | | | | 7.8 | | | | 181 | | | | 181 | | | | 7.8 | | | | 181 | |
Total principal long-term debt | | | | | | | 4.9 | % | | $ | 3,206 | | | $ | 3,206 | | | | 4.9 | % | | $ | 3,431 | | | | | | | | 4.9 | | | | 3,706 | | | | 3,206 | | | | 5.0 | | | | 3,206 | |
Fair value adjustment of long-term debt (3) | | | 2016-2038 | | | | n/a | | | $ | 100 | | | $ | 103 | | | | n/a | | | $ | 109 | | | | 2016-2038 | | | | n/a | | | | 97 | | | | 103 | | | | n/a | | | | 110 | |
Unamortized debt premium, net | | | n/a | | | | n/a | | | | 18 | | | | 18 | | | | n/a | | | | 18 | | | | n/a | | | | n/a | | | | 16 | | | | 18 | | | | n/a | | | | 18 | |
Total non-principal long-term debt | | | | | | | n/a | | | $ | 118 | | | $ | 121 | | | | n/a | | | $ | 127 | | | | | | | | n/a | | | | 113 | | | | 121 | | | | n/a | | | | 128 | |
Total long-term debt | | | | | | | | | | $ | 3,324 | | | $ | 3,327 | | | | | | | $ | 3,558 | | | | | | | | | | | $ | 3,819 | | | $ | 3,327 | | | | | | | $ | 3,334 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total debt | | | | | | | | | | $ | 4,418 | | | $ | 4,930 | | | | | | | $ | 4,305 | | | | | | | | | | | $ | 4,340 | | | $ | 4,930 | | | | | | | $ | 4,296 | |
(1) | Interest rates are calculated based on the daily weighted average balance for the applicable category outstanding for the threesix months ended March 31.June 30. |
(2) | As of March 31,June 30, 2013, the weighted average interest rate on our AGL CapitalCapital’s commercial paper borrowings was 0.5%0.4%. |
(3) | See Note 3 for additional information on our fair value measurements. |
Long-Term Debt
On May 16, 2013, we issued $500 million in 30-year senior notes with a fixed interest rate of 4.4%. The net proceeds were used to repay a portion of AGL Capital’s commercial paper, including $225 million we borrowed to redeem our senior notes that matured on April 15, 2013. We fully and unconditionally guarantee all debt issued by AGL Capital.
During the first quarter of 2013, we refinanced $200 million of our outstanding tax-exempt gas facility revenue bonds, $180 million of which were previously issued by the New Jersey Economic Development Authority and $20 million of which were previously issued by Brevard County, Florida. The refinancing involved a combination of the issuance of $60 million of refunding bonds to, and the purchase of $140 million of existing bonds by, a syndicate of banks. Our relationship with the syndicate of banks regarding the bonds is governed by an agreement that contains representations, warranties, covenants and default provisions consistent with those contained in similar financing documents of ours. All of the bonds remainare floating-rate instruments. AGL Resources had no cash receipts or payments in connection with the refinancing. The letters of credit providing credit support for the refinancedoutstanding revenue bonds along with other related agreements were terminated as a result of the refinancing.
Interest Rate Swaps
InOn April 4, 2013, we entered into two ten-year, $50 million fixed-rate forward-starting interest rate swaps to hedge any potential interest rate volatility prior to our anticipated issuance of senior notes duringin the second quarter 2013. The average interest rate on these swaps was 1.98%. Including existing forward-starting interest rate swap hedges, which were executed last year, we havehad fixed-rate swaps totaling $300 million in notional value at an average interest rate of 1.85%. We have designated the forward-starting interest rate swaps as cash flow hedges of our anticipated second quarter 2013 debtsenior note issuance. The interest rate swaps were settled on May 16, 2013, the senior note issuance date, at which time we received $6 million in proceeds. The $6 million will be amortized to reduce interest expense over the first 10 years of the 30-year senior notes.
Financial and Non-Financial Covenants
The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month; however, our goal is to maintain these ratios at levels between 50% and 60%.These ratios, as calculated in accordance with the debt covenants, include standby letters of credit and surety bonds and exclude accumulated OCI items related to non-cash OCI pension adjustments, other post-retirement benefits liability adjustments and accounting adjustments for cash flow hedges. Adjusting for these items, the following table contains our debt-to-capitalization ratios for the periodsdates presented, which are within our required and targeted ranges.below the maximum allowed.
| | March 31, 2013 | | | December 31, 2012 | | | March 31, 2012 | | | June 30, 2013 | | | December 31, 2012 | | | June 30, 2012 | |
AGL Credit Facility | | | 54 | % | | | 58 | % | | | 54 | % | | | 54 | % | | | 58 | % | | | 54 | % |
Nicor Gas Credit Facility | | | 43 | % | | | 55 | % | | | 47 | % | | | 43 | | | | 55 | | | | 43 | |
The credit facilities contain certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations and other matters customarily restricted in such agreements.
Default Provisions
Our credit facilities and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. The 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 triggering 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 triggering events. We were in compliance with all existing debt provisions and covenants, both financial and non-financial, for all periods presented.
Our other comprehensive income amounts are aggregated within our accumulated other comprehensive loss. The following table provides changes in the components of our accumulated other comprehensive loss balance, net of the related income tax effects.
| | | 2013 | | | 2012 | |
In millions (1) | | Cash flow hedges | | | Retirement benefit plans | | | Total | | | Cash flow hedges | | | Retirement benefit plans | | | Total | | | Cash flow hedges | | | Retirement benefit plans | | | Total | |
Balance as of December 31, 2012 | | $ | (6 | ) | | $ | (212 | ) | | $ | (218 | ) | |
For the three months ending June 30 | | | | | | | | | | | | | | | | | | | |
Balance as of March 31 | | | $ | (2 | ) | | $ | (209 | ) | | $ | (211 | ) | | $ | (12 | ) | | $ | (206 | ) | | $ | (218 | ) |
Other comprehensive income, before reclassifications | | | | (1 | ) | | | - | | | | (1 | ) | | | 4 | | | | - | | | | 4 | |
Amounts reclassified from accumulated other comprehensive income | | | | (1 | ) | | | 4 | | | | 3 | | | | - | | | | 7 | | | | 7 | |
Net current-period other comprehensive (loss) income | | | | (2 | ) | | | 4 | | | | 2 | | | | 4 | | | | 7 | | | | 11 | |
Balance as of June 30 | | | $ | (4 | ) | | $ | (205 | ) | | $ | (209 | ) | | $ | (8 | ) | | $ | (199 | ) | | $ | (207 | ) |
For the six months ending June 30 | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance as of December 31, prior year | | | $ | (6 | ) | | $ | (212 | ) | | $ | (218 | ) | | $ | (10 | ) | | $ | (207 | ) | | $ | (217 | ) |
Other comprehensive income, before reclassifications | | | 2 | | | | - | | | | 2 | | | | 1 | | | | - | | | | 1 | | | | 2 | | | | - | | | | 2 | |
Amounts reclassified from accumulated other comprehensive income | | | 2 | | | | 3 | | | | 5 | | | | 1 | | | | 7 | | | | 8 | | | | - | | | | 8 | | | | 8 | |
Net current-period other comprehensive income | | | 4 | | | | 3 | | | | 7 | | | | 2 | | | | 7 | | | | 9 | | | | 2 | | | | 8 | | | | 10 | |
Balance as of March 31, 2013 | | $ | (2 | ) | | $ | (209 | ) | | $ | (211 | ) | |
Balance as of June 30 | | | $ | (4 | ) | | $ | (205 | ) | | $ | (209 | ) | | $ | (8 | ) | | $ | (199 | ) | | $ | (207 | ) |
(1) | All amounts are net of income taxes. Amounts in parentheses indicate debits to Accumulated Other Comprehensive Loss.accumulated other comprehensive loss. |
The following table provides details of the reclassifications out of accumulated other comprehensive loss for the period ended March 31, 2013,periods presented, and the ultimate impact on net income.
| | | Amount reclassified from accumulated other comprehensive loss (1) | | Affected line item in the income statement |
| | | Three months ending June 30, | | | Six months ending June 30, | | |
In millions | | Amount reclassified from Accumulated Other Comprehensive Loss (1) | | Affected line item in the Income Statement | | 2013 | | | 2012 | | | 2013 | | | 2012 | | |
Cash flow hedges | | | | | | | | | | | | | | | | | |
Interest rate contracts | | $ | (3 | ) | Interest expense, net | | $ | 1 | | | $ | - | | | $ | (2 | ) | | $ | - | | Interest expense, net |
Income tax benefit | | | 1 | | | | | - | | | | - | | | | 1 | | | | - | | |
Total cash flow hedges | | | (2 | ) | | | | 1 | | | | - | | | | (1 | ) | | | - | | |
Retirement benefit plan amortization of | | | | | | | | | | | | | | | | | | | | | | |
Actuarial losses | | | (6 | ) | See (2), below | | | (7 | ) | | | (10 | ) | | | (13 | ) | | | (12 | ) | See (2), below |
Prior service credits | | | 1 | | See (2), below | | | - | | | | - | | | | 2 | | | | - | | See (2), below |
Total before income tax | | | (5 | ) | | | | (7 | ) | | | (10 | ) | | | (11 | ) | | | (12 | ) | |
Income tax benefit | | | 2 | | | | | 3 | | | | 3 | | | | 4 | | | | 4 | | |
Total retirement benefit plans | | | (3 | ) | | | | (4 | ) | | | (7 | ) | | | (7 | ) | | | (8 | ) | |
Total reclassification for the period | | $ | (5 | ) | | | $ | (3 | ) | | $ | (7 | ) | | $ | (8 | ) | | $ | (8 | ) | |
(1) | Amounts in parentheses indicate debits, or reductions, to profit/loss and credits to Accumulated Other Comprehensive Income.accumulated other comprehensive loss. Except for retirement benefit plan amounts, the profit/loss impacts are immediate. |
(2) | TheseAmortization of these accumulated OCIother comprehensive loss components areis included in the computation of net periodic benefit cost. See Note 5 Employee Benefit Plans, for additional details about net periodic benefit cost.
|
Note 8 - Non-Wholly Owned Entities
Variable Interest Entities
On a quarterly basis, we evaluate all of our ownership interests to determine if they represent a VIE as defined by the authoritative accounting guidance on consolidation, and if so, which party is the primary beneficiary. We have determined that SouthStar, a joint venture owned 85% by us and 15% by Piedmont, is our only VIE for which we are the primary beneficiary, which requires us to consolidate its assets, liabilities and Statementsstatements of Income.income. See Note 10 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K. Earnings from SouthStar in 2013 and 2012 were allocated entirely in accordance with the ownership interests.
SouthStar markets natural gas and related services under the trade name Georgia Natural Gas to retail customers primarily in Georgia, under various other trade names to retail customers in Ohio, Florida and New York, and to commercial and industrial customers in the southeastern United States.
During the three months ended March 31, 2013, thereThere have been no significant changes to the primary risks associated with SouthStar asbeyond those discussed in our risk factors included in Item 1A of our 2012 Form 10-K.
SouthStar’s financial results are seasonal in nature, with business depending to a great extent on the first and fourth quarters of each year. SouthStar’s current assets consist primarily of natural gas inventory, derivative instruments and receivables from its customers. SouthStar also has receivables from us due to its participation in AGL Capital’s commercial paper program. See Note 2 for additional discussions of SouthStar’s inventories. SouthStar’s restricted assets consist of customer deposits and were immaterial as of March 31,June 30, 2013 and 2012. SouthStar’s current liabilities consist primarily of accrued natural gas costs, other accrued expenses, customer deposits, derivative instruments and payables to us from its participation in AGL Capital’s commercial paper program.
SouthStar’s other contractual commitments and obligations, including operating leases and agreements with third party providers, do not contain terms that would trigger material financial obligations in the event that such contracts were terminated. As a result, our maximum exposure to a loss at SouthStardue to SouthStar’s contractual commitments and obligations is considered to be immaterial. SouthStar’s creditors have no recourse to our general credit beyond our corporate guarantees that we have provided to SouthStar’s counterparties and natural gas suppliers. We have provided no financial or other support that was not previously contractually required. With the exception of our corporate guarantees, we have not entered into any arrangements that could require us to provide financial support to SouthStar.
Price and volume fluctuations of SouthStar’s natural gas inventories can cause significant variations in our working capital and cash flow from operations. Changes in our operating cash flows are also attributable to SouthStar’s working capital changes resulting from the impact of weather, the timing of customer collections, payments for natural gas purchases and cash collateral amounts that SouthStar maintains to facilitate its derivative instruments.instruments also impact our operating cash flow.
Cash flows used in our investing activities include capital expenditures for SouthStar of $1 million for the threesix months ended March 31,June 30, 2013 and 2012, and $1 million for the year ended December 31, 2012. Cash flows used in our financing activities include SouthStar’s distribution to Piedmont for its portion of SouthStar’s annual earnings from the previous year. Generally, this distribution occurs in the first quarter of each fiscal year. For the threesix months ended March 31,June 30, 2013, SouthStar distributed $17 million to Piedmont and $14 million during the same period last year. The increase of $3 million was primarily the result of increased earnings year-over-year.
The following table provides additional information on all of SouthStar’s assets and liabilities as of the dates presented, which are consolidated within our unaudited Condensed Consolidated Statements of Financial Position.The SouthStar balances do not include intercompany eliminations or the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.
| | March 31, 2013 | | | December 31, 2012 | | | March 31, 2012 | | | June 30, 2013 | | | December 31, 2012 | | | June 30, 2012 | |
In millions | | Consolidated | | | SouthStar | | | | | | Consolidated | | | SouthStar | | | | | | Consolidated | | | SouthStar | | | | | | Consolidated | | | SouthStar | | | | | | Consolidated | | | SouthStar | | | | | | Consolidated | | | SouthStar | | | | |
| | $ | 2,361 | | | $ | 143 | | | | 6 | % | | $ | 2,668 | | | $ | 201 | | | | 8 | % | | $ | 2,022 | | | $ | 149 | | | | 7 | % | | $ | 2,063 | | | $ | 135 | | | | 7 | % | | $ | 2,668 | | | $ | 201 | | | | 8 | % | | $ | 1,880 | | | $ | 145 | | | | 8 | % |
Long-term assets and other deferred debits | | | 11,579 | | | | 10 | | | | - | | | | 11,473 | | | | 10 | | | | - | | | | 11,217 | | | | 9 | | | | - | | | | 11,732 | | | | 10 | | | | - | | | | 11,473 | | | | 10 | | | | - | | | | 11,349 | | | | 9 | | | | - | |
| | $ | 13,940 | | | $ | 153 | | | | 1 | % | | $ | 14,141 | | | $ | 211 | | | | 1 | % | | $ | 13,239 | | | $ | 158 | | | | 1 | % | | $ | 13,795 | | | $ | 145 | | | | 1 | % | | $ | 14,141 | | | $ | 211 | | | | 1 | % | | $ | 13,229 | | | $ | 154 | | | | 1 | % |
| | $ | 3,060 | | | $ | 51 | | | | 2 | % | | $ | 3,338 | | | $ | 62 | | | | 2 | % | | $ | 2,348 | | | $ | 52 | | | | 2 | % | | $ | 2,349 | | | $ | 40 | | | | 2 | % | | $ | 3,338 | | | $ | 62 | | | | 2 | % | | $ | 2,460 | | | $ | 37 | | | | 2 | % |
Long-term liabilities and other deferred credits | | | 7,339 | | | | - | | | | - | | | | 7,368 | | | | - | | | | - | | | | 7,465 | | | | - | | | | - | | | | 7,891 | | | | - | | | | - | | | | 7,368 | | | | - | | | | - | | | | 7,340 | | | | - | | | | - | |
| | | 10,399 | | | | 51 | | | | 1 | | | | 10,706 | | | | 62 | | | | 1 | | | | 9,813 | | | | 52 | | | | 1 | | | | 10,240 | | | | 40 | | | | - | | | | 10,706 | | | | 62 | | | | 1 | | | | 9,800 | | | | 37 | | | | - | |
| | | 3,541 | | | | 102 | | | | 3 | | | | 3,435 | | | | 149 | | | | 4 | | | | 3,426 | | | | 106 | | | | 3 | | | | 3,555 | | | | 105 | | | | 3 | | | | 3,435 | | | | 149 | | | | 4 | | | | 3,429 | | | | 117 | | | | 3 | |
Total liabilities and equity | | $ | 13,940 | | | $ | 153 | | | | 1 | % | | $ | 14,141 | | | $ | 211 | | | | 1 | % | | $ | 13,239 | | | $ | 158 | | | | 1 | % | | $ | 13,795 | | | $ | 145 | | | | 1 | % | | $ | 14,141 | | | $ | 211 | | | | 1 | % | | $ | 13,229 | | | $ | 154 | | | | 1 | % |
The following table provides additional information on SouthStar’s operating revenues and operating expenses for the three months ended March 31, 2013 and 2012,periods presented, which are consolidated within our unaudited Condensed Consolidated Statements of Income.
| | | Three months ended June 30, | | | Six months ended June 30, | |
In millions | | 2013 | | | 2012 | | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
Operating revenues | | $ | 250 | | | $ | 215 | | | $ | 116 | | | $ | 99 | | | $ | 366 | | | $ | 314 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | |
Cost of goods sold | | | 164 | | | | 133 | | | | 95 | | | | 80 | | | | 259 | | | | 213 | |
Operation and maintenance | | | 18 | | | | 19 | | | | 15 | | | | 12 | | | | 33 | | | | 31 | |
Depreciation and amortization | | | 1 | | | | - | | | | - | | | | 1 | | | | 1 | | | | 1 | |
Taxes other than income taxes | | | - | | | | 1 | | | | 1 | | | | 1 | | | | 1 | | | | 2 | |
Total operating expenses | | | 183 | | | | 153 | | | | 111 | | | | 94 | | | | 294 | | | | 247 | |
Operating income | | $ | 67 | | | $ | 62 | | | $ | 5 | | | $ | 5 | | | $ | 72 | | | $ | 67 | |
Equity Method Investments
Income from our equity method investments is classified as other income in our unaudited Condensed Consolidated Statements of Income. ForThe following table provides the three months ended March 31, 2013, this included investment income from Triton of $2 million and $1 million of investment income from our other equity method investments. For the three months ended March 31, 2012, this included $3 million of investment income from Triton and an immaterial amount of investment income from our other equity method investments.investments. For more information about our equity method investments, see Note 10 to our Consolidated Financial Statements under Item 8 included in our 2012 Form 10-K.
| | Three months ended June 30, | | | Six months ended June 30, | |
In millions | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
Triton | | $ | 2 | | | $ | 3 | | | $ | 4 | | | $ | 6 | |
Other | | | - | | | | 2 | | | | 1 | | | | 2 | |
Note 9 - Commitments, Guarantees and Contingencies
ThereOther than the changes in our debt, see Note 6 herein, there were no significant changes to our contractual obligations beyond those described in Note 11 ofto our Consolidated Financial Statements and related notes as filed in Item 8 of our 2012 Form 10-K.
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.
Contingencies and Guarantees
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. We have certain subsidiaries that enter into various financial and performance guarantees and indemnities providing assurance to third parties. We believe the likelihood of payment under our guarantees and indemnities is remote. No liability has been recorded for such guarantees and indemnifications.indemnifications as the fair value is insignificant.
Regulatory Matters
On December 21, 2012, Atlanta Gas Light filed a petition with the Georgia Commission for approval to resolve an imbalance of approximately 4.8 Bcf of natural gas related to Atlanta Gas Light’s use of retained storage assets to operationally balance the system for the benefit of the natural gas market. We believe that any costs associated with resolving the imbalance are recoverable from Marketers. The resolution of this imbalance will be decided by the Georgia Commission and we are unable to predict the ultimate outcome.
Environmental Matters
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 our current and former operating sites. The following table provides more information on the costs related to remediation of our current and former operating sites as of March 31,June 30, 2013.
In millions | | Probabilistic model cost estimates (1) | | | Engineering estimates (1) | | | Amount recorded | | | Expected costs over next twelve months | |
Illinois | | $ | 193 - $439 | | | $ | 50 | | | $ | 239 | | | $ | 35 | |
New Jersey | | | 116 - 203 | | | | 6 | | | | 121 | | | | 14 | |
Georgia and Florida | | | 49 - 107 | | | | 12 | | | | 54 | | | | 6 | |
North Carolina | | | n/a | | | | 11 | | | | 11 | | | | 8 | |
Total | | $ | 358 - $749 | | | $ | 79 | | | $ | 425 | | | $ | 63 | |
(1) | There were events during first quarter 2013 that resulted in changes to the estimates disclosed in, and the amounts recorded in, our December 31, 2012 Form 10-K. These changes are reflected in the table above. |
In millions | | Probabilistic model cost estimates | | | Engineering estimates | | | Amount recorded | | | Expected costs over next twelve months | |
Illinois | | $ | 208 - $458 | | | $ | 42 | | | $ | 250 | | | $ | 34 | |
New Jersey | | | 146 - 240 | | | | 5 | | | | 151 | | | | 15 | |
Georgia and Florida | | | 42 - 100 | | | | 11 | | | | 56 | | | | 8 | |
North Carolina | | | n/a | | | | 11 | | | | 11 | | | | 5 | |
Total | | $ | 396 - $798 | | | $ | 69 | | | $ | 468 | | | $ | 62 | |
Our environmental remediation cost liabilities are estimates of future remediation costs for our current and former operating sites that are contaminated. Our estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, which is generally the case when remediation has not commenced or during the early years of a remediation effort. For those elements of the program where we cannot perform engineering estimates, there remains considerable variability in future cost estimates. Accordingly, we have established a probabilistic model to determine a range of potential expenditures to remediate and monitor our former operating sites. We cannot, at this time, identify any single number within this range as a better estimate of likely future costs, and we generally have recorded the low end of the range for our probabilistic cost estimates.
As we conduct the actual remediation and enter into cleanup contracts, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering assumptions, which we refine and update on an ongoing basis. With the exception of our North Carolina site, these costs are recoverable from our customers as they are paid and, accordingly, we have recorded a regulatory asset associated with the recorded liabilities. For more information on our environmental remediation costs, see Note 2 herein and Note 11 ofto our Consolidated Financial Statements and related notes as filed in Item 8 of our 2012 Form 10-K.
Litigation
We are involved in litigation arising in the normal course of business. Although in some cases the company is unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require the company to take charges against, or will result in reductions in, future earnings. It is the opinion of managementManagement believes that while the resolution of these contingencies, eitherwhether individually or in aggregate, could be material to earnings in a particular period, butthey will not have a material adverse effect on our consolidated financial position or cash flows. For additional litigation information, see Note 11 in our Consolidated Financial Statements and related notes in Item 8 of our 2012 Form 10-K.
PBR Proceeding From 2000 to 2002 Nicor Gas’Gas operated a PBR plan for natural gas costs went into effect in 2000 and was terminated effective January 1, 2003.costs. Under this plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. The PBR plan is currentlywas under review by the Illinois Commission as there aresince 2002 due to allegations that Nicor Gas acted improperly in connection with the plan. On June 27, 2002, the Citizens Utility Board (CUB) filed a motion to reopen the record in the Illinois Commission’s proceedings to review the PBR plan (the “Illinois Commission Proceedings”). As a result of the motion to reopen, Nicor Gas entered into a stipulation with the staff of the Illinois Commission and CUB providing for additional discovery. The Illinois Attorney General’s Office (IAGO) has also intervened in this matter. In addition, the IAGO issued Civil Investigation Demands (CIDs) to CUB and the Illinois Commission staff. The CIDs ordered that CUB and the Illinois Commission staff produce all documents relating to any claims that Nicor Gas may have presented, or caused to be presented, regarding false information related to its PBR plan. We have committed to cooperate fully in the reviews of the PBR plan.
The Nicor Board of Directors directed management to, among other things, make appropriate adjustments to account for, and fully address, the adverse consequences to ratepayers, and conduct a detailed study of the adequacy of internal accounting and regulatory controls. The adjustments were made in prior years’ financial statements resulting in a $25$25 million liability. Included in this $25 million liability is a $4$4 million loss contingency. A $2$2 million adjustment to the previously recorded liability, which is discussed below, was made in 2004 increasing the recorded liability to $27$27 million. By the end of 2003, Nicor Gas completed steps to correct the weaknesses and deficiencies identified in the detailed study of the adequacy of internal controls.
On February 5, 2003, CUB filed a motion for $27$27 million in sanctions against Nicor Gas in the Illinois Commission Proceedings. In that motion, CUB alleged that Nicor Gas’ responses to certain CUB data requests were false. Also on February 5, 2003, CUB stated in a press release that, in addition to $27 million in sanctions, it would seek additional refunds to consumers. On March 5, 2003, the Illinois Commission staff filed a response brief in support of CUB’s motion for sanctions. On May 1, 2003, the Administrative Law Judges assigned to the proceeding issued a ruling denying CUB’s motion for sanctions. CUB has filed an appeal of the motion for sanctions with the Illinois Commission, and the Illinois Commission has indicated that it will not rule on the appeal until the final disposition of the Illinois Commission Proceedings. It is not possible to determine how the Illinois Commission will resolve the claims of CUB or other parties to the Illinois Commission Proceedings.
In 2004, Nicor Gas became aware of additional information relating to the activities of individuals affecting the PBR plan for the period from 1999 through 2002, including information consisting of third party documents and recordings of telephone conversations from Entergy-Koch Trading, LP (EKT), a natural gas, storage and transportation trader and consultant with whom Nicor Gas did business under the PBR plan. Review of additional information completed in 2004 resulted in the $2 million adjustment to the previously recorded liability referenced above.
The evidentiary hearings on this matter were stayed in 2004 in order to permit the parties to undertake additional third party discovery from EKT. In December 2006, the additional third party discovery from EKT was obtained and the Administrative Law Judge issued a scheduling order that provided for Nicor Gas to submit direct testimony by April 13, 2007. Nicor Gas submitted direct testimony in April 2007, rebuttal testimony in April 2011 and surrebuttal testimony in December 2011. In surrebuttal testimony, we sought$6 $6 million, which included interest due to us of $2$2 million, as of December 31, 2011. The staff of the Illinois Commission, IAGO and CUB submitted direct testimony to the Illinois Commission in April 2009 and rebuttal testimony in October 2011. In rebuttal testimony, the staff of the Illinois Commission, IAGO and CUB requested refunds of $85$85 million, $255 million and $305 million, respectively.
In February 2012, we committed to a stipulated resolution of issues, which existed prior to our acquisition of Nicor Gas, with the staff of the Illinois Commission whichthat would include crediting Nicor Gas customers $64 million. This resulted in a $37 million adjustment toThere were no new developments between the previously recorded $27 million liability referenced abovedate of acquisition and is reflected in the purchase price allocation. Thedate of the stipulated resolution does not constitute an admission of fault, and it is not final and is subject to review and approval by the Illinois Commission.resolution. The CUB and IAGO arewere not parties to the stipulated resolution and continue to pursue their claims in this proceeding. Evidentiary hearings before the Administrative Law Judges were held during the first quarter of 2012 and post-trial legal briefs from the parties were submitted during the second quarter of 2012. Following the submission of legal briefs, on November 5, 2012, the Administrative Law Judges issued a proposed order for a refund of $72 million to ratepayers. During the fourth quarter of 2012, we increased our accrual by $8 million for a total of $72 million as a result of these developments and its effect on the estimated liability. liabilityWe do not agree with the additional $8 million .proposed by the Administrative Law Judges and will consider all legal recourse available should
On June 7, 2013, the Illinois Commission authorizeissued an order requiring us to refund $72 million to Nicor Gas’ current customers over a 12-month period and we began issuing these refunds in July 2013. We maintain that the appropriate PBR refund greater than theis $64 million, stipulation amount between Nicor Gas andconsistent with the staff ofstipulated resolution with the Illinois Commission.Commission staff, and have filed an appeal for the amount in excess of that specified in the stipulated resolution. Any appeal must be filed by August 19, 2013.
Nicor Services Warranty Product Actions In the first quarter of 2011, three putative class actions were filed againstNicor Gas, Nicor Services and Nicor Gas, andare defendants in one case against Nicor. In September 2011, the three cases were consolidated into a singleputative class action pendinginitially filed in September 2011, in state court in Cook County, Illinois. The plaintiffs purport to represent a class of customers of Nicor Gas who purchased the Gas Line Comfort Guard product from Nicor Services. In the consolidated action, theThe plaintiffs variously allege that the marketing, sale and billing of the Nicor Services Gas Line Comfort Guard violate the Illinois Consumer Fraud and Deceptive Business Practices Act, constitute common law fraud and result in unjust enrichment of Nicor Services and Nicor Gas. The plaintiffs seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorney fees and injunctive relief. While we are unable to predict the outcome of these matters or to reasonably estimate our potential exposure related thereto, if any, and have not recorded a liability associated with this contingency, the final disposition of this matter is not expected to have a material adverse impact on our liquidity or financial condition.
Other We also are also involved in litigation relating to estimated billing practices and an investigation by the United States Environmental Protection Agency regarding the applicable regulatory requirements for polychlorinated biphenyl in the Nicor Gas distribution system. While we are unable to predict the outcome of these mattersthis matter or to reasonably estimate our potential exposure related thereto, if any, and have not recorded a liability associated with these contingencies. Thethis contingency, the final disposition of these mattersthis matter is not expected to have a material adverse impact on our liquidity or financial condition.
For additional litigation information on these matters, see Note 11 in our Consolidated Financial Statements and related notes in Item 8 of our 2012 Form 10-K.
In addition to the matters set forth above, we are involved in legal or administrative proceedings before various courts and agencies with respect to general claims, taxes, environmental, gas cost prudence reviews and other matters. Although we are unable to determine the ultimate outcomes of these other contingencies, we believe that our financial statements appropriately reflect these amounts, including the recording of liabilities when a loss is probable and reasonably estimable.
Our operating segments comprise revenue-generating components of our company for which we produce separate financial information internally that we regularly use to make operating decisions and assess performance. Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. We manage our businesses through five operating segments - distribution operations, retail operations, wholesale services, midstream operations, cargo shipping and oneother, a non-operating segment, other.segment.
Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities in seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland. These utilities construct, manage and maintain intrastate natural gas pipelines and distribution facilities. Although the operations of our distribution operations segment are geographically dispersed, the operating subsidiaries within the distribution operations segment are regulated utilities, with rates determined by individual state regulatory commissions. These natural gas distribution utilities have similar economic and risk characteristics.
We are also involved in several related and complementary businesses. Our retail operations segment includes retail natural gas marketing to end-use customers primarily in Georgia, as well as various businesses that market retail energy-related products and services to residential and small business customers primarily in Illinois. Additionally, our retail operations segment providesIllinois, such as warranty protection solutions to customers and customer move connection services for other utilities. Our wholesale services segment includes natural gas asset management and related logistics activities for each of our utilities, except Nicor Gas, as well as for nonaffiliated companies, natural gas storage arbitrage and related activities. Our midstream operations segment includes our non-utility storage and pipeline operations, including the development and operation of high-deliverability natural gas storage assets.
Our cargo shipping segment transports containerized freight between Florida, the eastern coast of Canada, the Bahamas and the Caribbean region. Our cargo shipping segment also includes amounts related to cargo insurance coverage sold to our customers and other third parties. Our cargo shipping segment’s vessels are under foreign registry, and its containers are considered instruments of international trade. Although the majority of its long-lived assets are foreign owned and its revenues are derived from foreign operations, the functional currency is generally the United States dollar. Our cargo shipping segment also includes an equity investment in Triton, a cargo container leasing business. Profits and losses are generally allocated to investors’ capital accounts in proportion to their capital contributions. Our investment in Triton is accounted for under the equity method, and our share of earnings is reported within other income in our unaudited Condensed Consolidated Statements of Income.
Our other segment includes intercompany eliminations and aggregated subsidiaries that are individually not significant enough on a stand-alone basis and that do not meet the criteria in one of our other five operating segments.to be reportable.
We evaluate segment performance using the non-GAAP measure of EBIT that includes operating income, other income and expenses, and equity investment income. Items we do not include in EBIT are income taxes and financing costs, including interest and debt expense, each of which we evaluate on a consolidated basis. We believe EBIT is a useful measurement of our performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.
You should not consider EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The reconciliations of EBIT to operating income, earnings before income taxes and net income for the three months ended March 31, 2013 and, 2012periods presented are presented below.as follows:
| | | Three months ended June 30, | | | Six months ended June 30, | |
In millions | | 2013 | | | 2012 | | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
Operating income | | $ | 299 | | | $ | 262 | | | $ | 122 | | | $ | 91 | | | $ | 421 | | | $ | 353 | |
Other income | | | 5 | | | | 4 | | | | 7 | | | | 9 | | | | 12 | | | | 13 | |
EBIT | | | 304 | | | | 266 | | | | 129 | | | | 100 | | | | 433 | | | | 366 | |
Interest expense | | | 46 | | | | 47 | | | | 46 | | | | 45 | | | | 92 | | | | 92 | |
Earnings before income taxes | | | 258 | | | | 219 | | | | 83 | | | | 55 | | | | 341 | | | | 274 | |
Income taxes | | | 94 | | | | 80 | | | | 33 | | | | 20 | | | | 127 | | | | 100 | |
Net income | | $ | 164 | | | $ | 139 | | | $ | 50 | | | $ | 35 | | | $ | 214 | | | $ | 174 | |
Information by segment on our Statements of Financial Position as of December 31, 2012, is as follows:
In millions | | Identifiable and total assets (1) | | | Goodwill | |
Distribution operations | | $ | 11,320 | | | $ | 1,640 | |
Retail operations | | | 511 | | | | 122 | |
Wholesale services | | | 1,218 | | | | - | |
Midstream operations | | | 720 | | | | 14 | |
Cargo shipping | | | 464 | | | | 61 | |
Other (2) | | | (92 | ) | | | - | |
Consolidated | | $ | 14,141 | | | $ | 1,837 | |
(1) | Identifiable assets are those assets used in each segment’s operations. |
(2) | OurThe assets of our other segment’s assetssegment consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations.
|
Summarized Statements of Income, Statements of Financial Position and capital expenditure information by segment as of and for the periods presented are shown in the following tables.
Three months ended March 31,June 30, 2013
In millions | | Distribution operations | | | Retail operations | | | Wholesale services | | | Midstream operations | | | Cargo shipping | | | Other and intercompany eliminations (4) | | | Consolidated | | | Distribution operations | | | Retail operations | | | Wholesale services | | | Midstream operations | | | Cargo shipping | | | Other and intercompany eliminations (4) | | | Consolidated | |
Operating revenues from external parties | | $ | 1,264 | | | $ | 302 | | | $ | 39 | | | $ | 24 | | | $ | 87 | | | $ | (7 | ) | | $ | 1,709 | | | $ | 615 | | | $ | 165 | | | $ | 21 | | | $ | 15 | | | $ | 88 | | | $ | - | | | $ | 904 | |
Intercompany revenues (1) | | | 55 | | | | - | | | | - | | | | - | | | | - | | | | (55 | ) | | | - | | | | 43 | | | | - | | | | - | | | | - | | | | - | | | | (43 | ) | | | - | |
Total operating revenues | | | 1,319 | | | | 302 | | | | 39 | | | | 24 | | | | 87 | | | | (62 | ) | | | 1,709 | | | | 658 | | | | 165 | | | | 21 | | | | 15 | | | | 88 | | | | (43 | ) | | | 904 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost of goods sold | | | 765 | | | | 195 | | | | 10 | | | | 12 | | | | 53 | | | | (62 | ) | | | 973 | | | | 266 | | | | 115 | | | | 10 | | | | 4 | | | | 54 | | | | (42 | ) | | | 407 | |
Operation and maintenance | | | 185 | | | | 31 | | | | 13 | | | | 6 | | | | 28 | | | | (4 | ) | | | 259 | | | | 159 | | | | 32 | | | | 10 | | | | 6 | | | | 30 | | | | (4 | ) | | | 233 | |
Depreciation and amortization | | | 90 | | | | 5 | | | | - | | | | 4 | | | | 5 | | | | 3 | | | | 107 | | | | 90 | | | | 5 | | | | 1 | | | | 4 | | | | 5 | | | | 4 | | | | 109 | |
Taxes other than income taxes | | | 64 | | | | 1 | | | | 1 | | | | 1 | | | | 1 | | | | 3 | | | | 71 | | | | 38 | | | | 1 | | | | - | | | | 2 | | | | 2 | | | | 1 | | | | 44 | |
Total operating expenses | | | 1,104 | | | | 232 | | | | 24 | | | | 23 | | | | 87 | | | | (60 | ) | | | 1,410 | | | | 553 | | | | 153 | | | | 21 | | | | 16 | | | | 91 | | | | (41 | ) | | | 793 | |
Gain on sale of Compass Energy | | | | - | | | | - | | | | 11 | | | | - | | | | - | | | | - | | | | 11 | |
Operating income (loss) | | | 215 | | | | 70 | | | | 15 | | | | 1 | | | | - | | | | (2 | ) | | | 299 | | | | 105 | | | | 12 | | | | 11 | | | | (1 | ) | | | (3 | ) | | | (2 | ) | | | 122 | |
Other income | | | 3 | | | | - | | | | - | | | | 1 | | | | 2 | | | | (1 | ) | | | 5 | | | | 4 | | | | - | | | | - | | | | 1 | | | | 2 | | | | - | | | | 7 | |
EBIT | | $ | 218 | | | $ | 70 | | | $ | 15 | | | $ | 2 | | | $ | 2 | | | $ | (3 | ) | | $ | 304 | | | $ | 109 | | | $ | 12 | | | $ | 11 | | | $ | - | | | $ | (1 | ) | | $ | (2 | ) | | $ | 129 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Identifiable and total assets (3) | | $ | 11,258 | | | $ | 668 | | | $ | 1,005 | | | $ | 714 | | | $ | 459 | | | $ | (164 | ) | | $ | 13,940 | | |
Goodwill | | $ | 1,640 | | | $ | 168 | | | $ | - | | | $ | 14 | | | $ | 61 | | | $ | - | | | $ | 1,883 | | |
Capital expenditures | | $ | 137 | | | $ | 1 | | | $ | - | | | $ | 4 | | | $ | 1 | | | $ | 5 | | | $ | 148 | | | $ | 158 | | | $ | 3 | | | $ | - | | | $ | 4 | | | $ | 2 | | | $ | 3 | | | $ | 170 | |
Three months ended March 31,June 30, 2012
In millions | | Distribution operations | | | Retail operations | | | Wholesale services | | | Midstream operations | | | Cargo shipping | | | Other and intercompany eliminations (4) | | | Consolidated | | | Distribution operations | | | Retail operations | | | Wholesale services | | | Midstream operations | | | Cargo shipping | | | Other and intercompany eliminations (4) | | | Consolidated | |
Operating revenues from external parties | | $ | 994 | | | $ | 263 | | | $ | 64 | | | $ | 16 | | | $ | 84 | | | $ | (17 | ) | | $ | 1,404 | | | $ | 449 | | | $ | 136 | | | $ | 7 | | | $ | 18 | | | $ | 80 | | | $ | (4 | ) | | $ | 686 | |
Intercompany revenues (1) | | | 46 | | | | - | | | | - | | | | - | | | | - | | | | (46 | ) | | | - | | | | 41 | | | | - | | | | - | | | | - | | | | - | | | | (41 | ) | | | - | |
Total operating revenues | | | 1,040 | | | | 263 | | | | 64 | | | | 16 | | | | 84 | | | | (63 | ) | | | 1,404 | | | | 490 | | | | 136 | | | | 7 | | | | 18 | | | | 80 | | | | (45 | ) | | | 686 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost of goods sold | | | 529 | | | | 166 | | | | 30 | | | | 5 | | | | 50 | | | | (61 | ) | | | 719 | | | | 131 | | | | 93 | | | | 4 | | | | 7 | | | | 51 | | | | (46 | ) | | | 240 | |
Operation and maintenance | | | 173 | | | | 32 | | | | 13 | | | | 5 | | | | 28 | | | | (6 | ) | | | 245 | | | | 152 | | | | 25 | | | | 11 | | | | 4 | | | | 26 | | | | - | | | | 218 | |
Depreciation and amortization | | | 88 | | | | 4 | | | | 1 | | | | 2 | | | | 6 | | | | 3 | | | | 104 | | | | 86 | | | | 3 | | | | - | | | | 4 | | | | 6 | | | | 3 | | | | 102 | |
Taxes other than income taxes | | | 57 | | | | 1 | | | | 1 | | | | 1 | | | | 2 | | | | 2 | | | | 64 | | | | 25 | | | | 1 | | | | 1 | | | | 2 | | | | 1 | | | | 2 | | | | 32 | |
Nicor merger expenses (2) | | | - | | | | - | | | | - | | | | - | | | | - | | | | 10 | | | | 10 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 3 | | | | 3 | |
Total operating expenses | | | 847 | | | | 203 | | | | 45 | | | | 13 | | | | 86 | | | | (52 | ) | | | 1,142 | | | | 394 | | | | 122 | | | | 16 | | | | 17 | | | | 84 | | | | (38 | ) | | | 595 | |
Operating income (loss) | | | 193 | | | | 60 | | | | 19 | | | | 3 | | | | (2 | ) | | | (11 | ) | | | 262 | | | | 96 | | | | 14 | | | | (9 | ) | | | 1 | | | | (4 | ) | | | (7 | ) | | | 91 | |
Other income | | | 1 | | | | - | | | | - | | | | - | | | | 3 | | | | - | | | | 4 | | | | 4 | | | | - | | | | - | | | | 1 | | | | 3 | | | | 1 | | | | 9 | |
EBIT | | $ | 194 | | | $ | 60 | | | $ | 19 | | | $ | 3 | | | $ | 1 | | | $ | (11 | ) | | $ | 266 | | | $ | 100 | | | $ | 14 | | | $ | (9 | ) | | $ | 2 | | | $ | (1 | ) | | $ | (6 | ) | | $ | 100 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Identifiable and total assets (3) | | $ | 10,785 | | | $ | 471 | | | $ | 917 | | | $ | 665 | | | $ | 477 | | | $ | (76 | ) | | $ | 13,239 | | |
Goodwill | | $ | 1,586 | | | $ | 124 | | | $ | 2 | | | $ | 16 | | | $ | 77 | | | $ | 8 | | | $ | 1,813 | | |
Capital expenditures | | $ | 122 | | | $ | 2 | | | $ | - | | | $ | 42 | | | $ | - | | | $ | 5 | | | $ | 171 | | | $ | 146 | | | $ | 2 | | | $ | - | | | $ | 17 | | | $ | 1 | | | $ | 13 | | | $ | 179 | |
Six months ended June 30, 2013
In millions | | Distribution operations | | | Retail operations | | | Wholesale services | | | Midstream operations | | | Cargo shipping | | | Other and intercompany eliminations (4) | | | Consolidated | |
Operating revenues from external parties | | $ | 1,879 | | | $ | 467 | | | $ | 60 | | | $ | 39 | | | $ | 175 | | | $ | (7 | ) | | $ | 2,613 | |
Intercompany revenues (1) | | | 98 | | | | - | | | | - | | | | - | | | | - | | | | (98 | ) | | | - | |
Total operating revenues | | | 1,977 | | | | 467 | | | | 60 | | | | 39 | | | | 175 | | | | (105 | ) | | | 2,613 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost of goods sold | | | 1,031 | | | | 310 | | | | 20 | | | | 16 | | | | 107 | | | | (104 | ) | | | 1,380 | |
Operation and maintenance | | | 344 | | | | 63 | | | | 23 | | | | 12 | | | | 58 | | | | (8 | ) | | | 492 | |
Depreciation and amortization | | | 180 | | | | 10 | | | | 1 | | | | 8 | | | | 10 | | | | 7 | | | | 216 | |
Taxes other than income taxes | | | 102 | | | | 2 | | | | 1 | | | | 3 | | | | 3 | | | | 4 | | | | 115 | |
Total operating expenses | | | 1,657 | | | | 385 | | | | 45 | | | | 39 | | | | 178 | | | | (101 | ) | | | 2,203 | |
Gain on sale of Compass Energy | | | - | | | | - | | | | 11 | | | | - | | | | - | | | | - | | | | 11 | |
Operating income (loss) | | | 320 | | | | 82 | | | | 26 | | | | - | | | | (3 | ) | | | (4 | ) | | | 421 | |
Other income | | | 7 | | | | - | | | | - | | | | 2 | | | | 4 | | | | (1 | ) | | | 12 | |
EBIT | | $ | 327 | | | $ | 82 | | | $ | 26 | | | $ | 2 | | | $ | 1 | | | $ | (5 | ) | | $ | 433 | |
Identifiable and total assets (3) | | $ | 11,166 | | | $ | 641 | | | $ | 1,008 | | | $ | 715 | | | $ | 462 | | | $ | (197 | ) | | $ | 13,795 | |
Goodwill | | $ | 1,640 | | | $ | 168 | | | $ | - | | | $ | 14 | | | $ | 61 | | | $ | - | | | $ | 1,883 | |
Capital expenditures | | $ | 295 | | | $ | 4 | | | $ | - | | | $ | 8 | | | $ | 3 | | | $ | 8 | | | $ | 318 | |
Six months ended June 30,2012
In millions | | Distribution operations | | | Retail operations | | | Wholesale services | | | Midstream operations | | | Cargo shipping | | | Other and intercompany eliminations (4) | | | Consolidated | |
Operating revenues from external parties | | $ | 1,443 | | | $ | 399 | | | $ | 71 | | | $ | 34 | | | $ | 164 | | | $ | (21 | ) | | $ | 2,090 | |
Intercompany revenues (1) | | | 87 | | | | - | | | | - | | | | - | | | | - | | | | (87 | ) | | | - | |
Total operating revenues | | | 1,530 | | | | 399 | | | | 71 | | | | 34 | | | | 164 | | | | (108 | ) | | | 2,090 | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost of goods sold | | | 660 | | | | 259 | | | | 34 | | | | 12 | | | | 101 | | | | (107 | ) | | | 959 | |
Operation and maintenance | | | 325 | | | | 57 | | | | 24 | | | | 9 | | | | 54 | | | | (6 | ) | | | 463 | |
Depreciation and amortization | | | 174 | | | | 7 | | | | 1 | | | | 6 | | | | 12 | | | | 6 | | | | 206 | |
Taxes other than income taxes | | | 82 | | | | 2 | | | | 2 | | | | 3 | | | | 3 | | | | 4 | | | | 96 | |
Nicor merger expenses (2) | | | - | | | | - | | | | - | | | | - | | | | - | | | | 13 | | | | 13 | |
Total operating expenses | | | 1,241 | | | | 325 | | | | 61 | | | | 30 | | | | 170 | | | | (90 | ) | | | 1,737 | |
Operating income (loss) | | | 289 | | | | 74 | | | | 10 | | | | 4 | | | | (6 | ) | | | (18 | ) | | | 353 | |
Other income | | | 5 | | | | - | | | | - | | | | 1 | | | | 6 | | | | 1 | | | | 13 | |
EBIT | | $ | 294 | | | $ | 74 | | | $ | 10 | | | $ | 5 | | | $ | - | | | $ | (17 | ) | | $ | 366 | |
Identifiable and total assets (3) | | $ | 10,784 | | | $ | 452 | | | $ | 895 | | | $ | 685 | | | $ | 471 | | | $ | (58 | ) | | $ | 13,229 | |
Goodwill | | $ | 1,586 | | | $ | 124 | | | $ | 2 | | | $ | 16 | | | $ | 77 | | | $ | 8 | | | $ | 1,813 | |
Capital expenditures | | $ | 268 | | | $ | 4 | | | $ | - | | | $ | 59 | | | $ | 1 | | | $ | 18 | | | $ | 350 | |
(1) | Intercompany revenues - wholesale services records its energy marketing and risk management revenues on a net basis and its total operating revenues include intercompany revenues of $140$103 million and $243 million for the three and six months ended March 31,June 30, 2013 and $88$49 million and $137 million for the three and six months ended March 31,June 30, 2012. |
(2) | Transaction expenses associated with the Nicor merger are shown separately to better compare year-over-year results. |
(3) | Identifiable assets are those used in each segment’s operations. |
(4) | OurThe assets of our other segment’s assetssegment consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations. |
ITEM 2.2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and the notes to our unaudited Condensed Consolidated Financial Statements in this quarterly filing, as well as our 2012 Form 10-K. Results for the interim periods presented are not necessarily indicative of the results to be expected for the full fiscal period due to seasonal and other factors.
Certain expectations and projections regarding our future performance referenced in this 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 within the meaning of the United States federal securities laws and are subject to uncertainties and risks. 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,” “proposed,” "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 currentlythe available information that we currently have, our expectations are subject to future events, risks and uncertainties, and there are numerous factors - many beyond our control - that could cause our actual results to vary 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; limits on pipeline capacity; the impact of acquisitions and divestitures; our ability to successfully fully integrate operations that we have or may acquire or develop in the future; direct or indirect effects on our business, financial condition or liquidity resulting from any change in our credit ratings, or any change in the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions, including disruptions in the capital markets and lending environment; general economic conditions; uncertainties about environmental issues and the related impact of such issues, including our environmental remediation plans; the impact of our depreciation study for Nicor Gas and related legislation; 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 and on our cargo shipping business; acts of war or terrorism; the outcome of litigation; and other factors discussed elsewhere herein and in our other filings with the SEC.
We caution readers that the important factors described elsewhere in this report, among others, could cause our business, results of operations or financial condition to differ significantly from those expressed in any forward-looking statements. There also may be other factors that we cannotdo not anticipate or that we do not recognize as material that are not described in this report that could cause our actual results to differ significantlymaterially from our expectations.
Forward-looking statements arespeak only as of the date they are made. We undertake noexpressly disclaim any obligation to publicly update or revise any forward-looking statement, whether as a result of future events, new information or otherwise, except as required under United States federal securities law.
We are an energy services holding company whose principal business is the distribution of natural gas in seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland - through our seven natural gas distribution utilities. We are also involved in several other businesses that are primarily related and complementary to the distribution of natural gas. Our operating segments consist of the following five operating and reporting segments – distribution operations, retail operations, wholesale services, midstream operations and cargo shipping and one non-operating segment –- other. These segments are consistent with how management views and operates our business. For additional information on our operating segments, see Note 10.10 to our unaudited Condensed Consolidated Financial Statements herein and Item 1, “Business” of our 2012 Form 10-K. Following are summarized recent developments for our operating segments.
Overview In the first half of 2013, we benefited from the return to more normal weather as compared to the historically warm weather in 2012. Excluding weather, we achieved growth in our operating margins during the first half of 2013 primarily as a result of our regulatory infrastructure programs in our distribution operations, targeted acquisition growth in retail operations, and higher contributions from commercial activity in our wholesale operations.
We continue to effectively manage costs and leverage our shared services model across our businesses to largely overcome inflationary effects. As expected, our operation and maintenance expenses in the first half of 2013 increased as a result of returning to targeted levels of incentive compensation. In addition, bad debt expense has increased modestly for some of our businesses as a result of colder weather and higher natural gas prices compared to 2012, which resulted in higher average customer bills. Our operation and maintenance expenses, excluding rider pass through expenses and incremental expenses related to the service plans acquired in January 2013, have otherwise
decreased slightly and we continue to maintain significant focus on costs.
Distribution Operations At March 31,June 30, 2013, our seven utilities within distribution operations served approximately 4.5 million end-use customers with itstheir primary focus being the safe and reliable delivery of natural gas.
Nicor Gas On June 7, 2013, the Illinois Commission issued an order requiring us to refund $72 million to Nicor Gas’ current customers over a 12-month period in connection with Nicor Gas’ operation of a PBR plan from 2000 to 2002. We continue to maintain that the appropriate PBR refund is $64 million, consistent with our stipulated resolution agreed to by Nicor Gas and the staff of the Illinois Commission, and have appealed the amount in excess of that specified in the stipulated resolution. On July 1, 2013, Nicor Gas began refunding the $72 million, with approximately 40% to be refunded in 2013 and 60% to be refunded in 2014. Nicor Gas previously accrued $72 million for this contingent liability, which is in line with the order issued by the Illinois Commission. Any appeal must be filed by August 19, 2013. See Note 9 to our unaudited Condensed Consolidated Financial Statements for additional information.
In June 2013, we entered into an OTC weather derivative to reduce the risk of lower operating margins as a result of significantly warmer-than-normal weather in Illinois during the fourth quarter of 2013. The weather derivative is based on fourth quarter 2013 Heating Degree Days at Chicago Midway International Airport. This is a cash-settled option and we will retain substantially all upside potential should the fourth quarter be colder-than-normal, but our operating margin will be largely protected in the event of significantly warmer-than-normal weather.
In July 2013, Illinois enacted legislation that will allow Nicor Gas to provide more widespread safety and reliability enhancements to its system in a timelier manner than under traditional utility regulation, and pass along lower program costs to our customers. We expect to submit a plan for approval by the Illinois Commission in mid-2014 and begin work in 2015.
In May 2013, the Illinois legislature passed legislation that, if signed by the Governor of Illinois, would provide a streamlined process for natural gas utilities serving more than 1.6 million customers as of January 1, 2013 to revise their depreciation rates. Accordingly, this legislation is applicable to Nicor Gas which has 2.2 million customers. If approved, the Illinois Commission has 120 days after our depreciation study is filed to review and rule on the proposed depreciation rate. Any change in the depreciation rate would become effective as of the date the depreciation study was filed and a retroactive adjustment to depreciation expense would be recognized.
We are currently performingin the final stages of completing a depreciation study for Nicor Gas that weand expect the final study will result in a decrease to complete later this year. Theour current composite, straight-line rate for Nicor Gas is currentlyof 4.1% and a. A 10 basis point shiftdecrease in this rate in either direction, is estimated to changelower our annual depreciation expense by $4 million to $6 million. Any changeWe expect to file our depreciation study with the Illinois Commission during the third quarter of 2013 and do not anticipate that our current customer rates will be affected by a decrease to our depreciation rates would be subject to regulatory approval.rate.
Atlanta Gas Light OnIn December 21, 2012, Atlanta Gas Light filed a petition with the Georgia Commission for approval to resolve an imbalance of approximately 4.8 Bcf of natural gas related to Atlanta Gas Light’s use of retained storage assets to operationally balance the system for the benefit of the natural gas market. We believe that any costs associated with resolving the imbalance are recoverable from Marketers. The resolution of this imbalance will be decided by the Georgia Commission and we are unable to predict the ultimate outcome.
Virginia Natural Gas In AprilMay 2013, the hearing examiner in charge ofVirginia Commission approved Virginia Natural Gas’ Conservation and Ratemaking Efficiency (CARE) plan. The plan issued a report recommending approval of a stipulation between Virginia Natural Gas and the staff of the Virginia Commission. The stipulation proposedprovides for a modified CARE plan that includedincludes a more limited set of conservation programs and measures at a reduced cost of $2 million over a three-year period. A decision by the Virginia Commission is expected by June 1, 2013.period.
Chattanooga Gas In April 2013, legislation was passedsigned into law that gives the Tennessee Authority the ability to approve alternative regulatory mechanisms. The law allows the Tennessee Authority to implement: (1)to: (i) implement separate rate adjustment mechanisms that track specific costs; (2)costs, (ii) implement annual rate reviews in lieu of traditional rate cases and (3)(iii) adopt other policies or procedures that permit a more timely review and revision of rates, streamline the regulatory process, and reduce the cost and time associated with the traditional ratemaking processes.
In April 2013, Chattanooga Gas filed a proposal with the Tennessee Authority a proposal to extend its energy conservation programs and associated rate adjustment mechanism that adjusts rates to recover revenue lostreduced operating revenues as a result of customers usage changes fromreduced customer usage. In August 2013, a status conference will be held by the level used to set base rates.Tennessee Authority, at which time a procedural schedule will be established.
Retail Operations Our retail operations businesses serve approximately 600 thousand0.6 million energy customers and approximately 1.2 million customer service contracts in Florida, Georgia, Illinois, Indiana, Kentucky, Ohio, Maryland, Massachusetts, New York, Pennsylvania and West Virginia. SouthStar, Nicor Advanced Energy and Nicor Solutions generate earnings through the sale of natural gas to residential, commercial and industrial customers, primarily in Georgia and
Illinois where we capture spreads between wholesale and retail natural gas prices. Additionally, these businesses offer our customers energy-related products that provide for natural gas price stability and utility bill management. These products mitigate and/or eliminate the risks to customers of colder-than-normal weather and/or changes in natural gas prices. We charge a fee or premium for these services. Our retail operations businesses also provide warranty protection and home solutions that include gas and electric line repair, equipment repair, insurance and maintenance through Nicor Services Pivotal Home Solutions and represent customers who are on monthly service contracts or warranty products billed at a fixed monthly amount.
On January 31,As described in Note 2 to our unaudited Condensed Consolidated Financial Statements, during June 2013, our retail operations segment acquired approximately 33,000 residential and commercial relationships in Illinois for $32 million. The transaction significantly increases the size of our retail energy customer portfolio in Illinois with minimal incremental operating expenses. We expect this transaction to result in approximately $4 million of EBIT during 2013.
In January 2013, our retail operations segment acquired approximately 500 thousand,000 service plans and certain other assets from NiSource Inc. for $120 million, plus $2 million of working capital. We believe this acquisition will provide an enhanced platform for growth and continued expansion of this business into a number of key markets.
Wholesale Services Our wholesale services segment consists of our wholly owned subsidiariessubsidiary Sequent and Compass Energy Services Inc. (Compass) and engages in asset management and optimization, storage, transportation, producer and peaking services and wholesale marketing of natural gas across the United States and in Canada. Additionally, itIt also provides natural gas asset management and/or related logistics services for most of our utilities, as well as for non-affiliated companies. In April 2013, the Tennessee Authority authorized an extension of the asset management agreement between Chattanooga Gas and Sequent. The terms of the agreement remain unchanged, except the expiration date is now March 2015.
Additionally, Sequent manages Nicor Solutions’ and Nicor Advanced Energy’s product risks, including the purchase ofIn May 2013, we sold Compass Energy, a non-regulated retail natural gas supplies.business supplying commercial and industrial customers. Upon completion of the sale, we received an initial cash payment of $12 million, which resulted in an $11 million pre-tax gain. Additionally, we are eligible to receive contingent cash consideration up to $8 million with a guaranteed minimum receipt of $3 million. The amount of the contingent cash consideration will be paid over a five-year earn out period based upon the financial performance of Compass provides natural gas supply and servicesEnergy. See Note 2 to commercial, industrial and governmental customers primarily in Kentucky, Ohio, Pennsylvania, Virginia and West Virginia.our unaudited Condensed Consolidated Financial Statements for additional information.
Midstream Operations Our midstream operations segment includes a number of businesses that are related and complementary to our primary business. The most significant of these businesses is our natural gas storage business, which develops, acquires and operates high-deliverability underground natural gas storage assets primarily in the Gulf Coast region of the United States and in northern California. While this business can generate additional revenue during times of peak market demand for natural gas storage services, a portionmany of our natural gas storage facilities are covered under a portfolio of short, medium and long-term contracts at fixed market rates.
Golden Triangle Storage’s Cavern 1 began commercial operations in September 2010, and Cavern 2 began commercial operations in September 2012. Cavern 1 is currently going through a process to assess the cavern’smonitor its working gas and restore capacity that is expectedwas lost to slightly increasenormal capacity shrinkage in the size of the facility. Thiscavern. The process began in early 2013 and willis expected to continue throughwith limited commercial operations resuming in the third quarter of 2013. We expect Cavern 1 to return to full commercial service in the first quarter of 2014. Cavern 2 will continue to cover the obligations of Cavern 1 during this process. Central Valley, located in northern California, began commercial operations and providing services tofor firm customers during the second quarter of 2012.
Through our wholly owned subsidiary Cypress Creek Gas Storage, LLC and as a result of our merger with Nicor, we own a 50% interest in Sawgrass Storage, LLC (Sawgrass Storage), a joint venture between us and a privately held energy exploration and production company. Sawgrass Storage was granted certification from the Federal Energy Regulatory Commission (FERC) in March 2012 for the development of an underground natural gas storage facility in Louisiana with 30 Bcf of working gas capacity (expandable to 40 Bcf). The FERC certificate is set to expire in March 2014 if not extended. Given the current weakness in the natural gas storage market and the FERC certificate set to expire, we along with our joint venture partner continue to evaluate our on-going strategy for the Sawgrass Storage facility. Currently, our investment in Sawgrass Storage is $9 million, which could potentially be written-off or impaired in the event of a continued decline in natural gas market fundamentals and the rates for contracting availability capacity, the FERC certificate not being extended or other strategic decisions made by us, our joint venture partner or the joint venture.
Cargo Shipping Our cargo shipping segment consists of Tropical Shipping,Shipping; multiple wholly owned foreign subsidiaries of Tropical Shipping that are treated as disregarded entities for United States income tax purposes,purposes; Seven Seas, a wholly owned domestic cargo insurance company,company; and an equity investment in Triton, a cargo container leasing business. For additional information on our operating segments, see Item 1, “Business” of our 2012 Form 10-Kbusiness.
Natural gas market fundamentals Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the country. The volatility of natural gas commodity prices has a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of our retail operations and wholesale services segments to capture value from location and seasonal spreads. Additionally, these changes in commodity prices subject a significant portion of our operations to earnings variability. Since 2011, the volatility of the daily Henry Hub spot market prices for natural gas – a benchmark measure for natural gas generally - in the United States has been significantly lower than it had been in previous years. This is the result of a robust natural gas supply, the weak economy and ample natural gas storage.storage.
Our utility natural gas acquisition strategy is designed to secure sufficient supplies of natural gas and the rights to physically flow natural gas between delivery points in order to meet the needs of our utility customers and to hedge gas prices and location spreads to effectively manage costs, reduce price volatility for our utility customers and maintain a competitive advantage.
Our non-utility businesses principally use physical and financial arrangements to reduce the risks associated with both weather-related seasonal fluctuations in market conditions and changing commodity prices. Additionally, our hedging strategies and physical natural gas supplies in storage enable us to reduce earnings risk exposure due to higher gas costs.
These economic hedges may not qualify, or aremay not be designated, for hedge accounting treatment. As a result, our reported earnings for the wholesale services, retail operations and midstream operations segments reflect changes in the fair values of certain derivatives. Accordingly, a decline in natural gas prices or decreases in transportation spreads generally results in hedge gains and correspondingly increases in EBIT, while an increase in natural gas prices or a widening of transportation spreads generally results in hedge losses and correspondingly decreases in EBIT. These values may change significantly from period to period and are reflected as gains or losses within our operating revenues or our OCI for those derivative instruments that qualify and are designated as accounting hedges.
It is possible that natural gas prices will remain low for an extended period based on current levels of excess supply relative to market demand for natural gas, in part due to abundant sources of new shale natural gas reserves and the lack of demand by commercial and industrial enterprises. However, as economic conditions continue to improve, the demand for natural gas may increase, natural gas prices could rise and higher volatility could return to the natural gas markets. Consequently, we are working to reposition our wholesale services business model with respect to fixed costs, and the types of contracts pursued and executed.
The market fundamentals of midstream operations storage business are cyclical, and as discussed above, the abundant supply of natural gas in recent years and the resulting lack of market and price volatility have negatively impacted the profitability of our storage facilities. In 2013, expiring storage capacity contracts were re-subscribed at lower prices and we anticipate these lower natural gas prices to continue inthroughout 2013 as compared to historical averages. Due to the current market storage rates, we did not re-contract 2.0 Bcf at Golden Triangle Storage and intend to provide other services until market conditions improve to support term contracts. As of April 1,June 30, 2013, the overall average firm subscription rate per facility is as follows:
| | Average Monthly Rate per Dekatherm | | | Average Monthly Rate per Dekatherm | |
Jefferson Island (1) | | $ | 0.122 | | | $ | 0.111 | |
Golden Triangle (1) | | $ | 0.240 | | | | 0.182 | |
Central Valley | | $ | 0.130 | | | | 0.130 | |
(1) | ExcludesIncludes firm capacity contracted by Sequent.Sequent at April 1, 2013 of 1.5 Bcf at an average monthly rate of $0.07 per dekatherm at Jefferson Island and 2 Bcf at an average monthly rate of $0.125 per dekatherm at Golden Triangle. |
While the average monthly rates were lower than prior years and we did not re-contract all of the available capacity during the first quarterhalf of 2013, our current projections remain consistent with those from our most recent annual impairment assessment given the revenues that are expected to be earned from other storage services. We will continue to monitor all of our reporting units for impairment indicators throughout the year, but as of March 31,June 30, 2013, we believe there are no indications of potential impairment.
We generate the majority of our operating revenues through the sale, distribution and storage of natural gas. We include in our consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed to residential, commercial and industrial customers from the date of the last bill to the end of the reporting period. No individual customer or industry accounts for a significant portion of our revenues.
The operating revenues and EBIT of our distribution operations and retail operations segments are seasonal. During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather. Our base operating expenses, excluding cost of gas, revenue taxes, interest expense and certain incentive compensation costs, are generally incurred relatively equally over any given year. Additionally, the revenues of our cargo shipping business are generally higher in the fourth quarter, as our customers require moredue to increased tourist-related shipments as the hotels, resorts, and cruise ships typically have increased occupancy rates commencing in the fourth quarter and increasing further into the first quarter and consumer spending increases during traditional holiday periods. Revenues are also impacted during the fourth quarter by Peak Season Surcharges. Thus, our operating results vary significantly from quarter to quarter as a result of seasonality.
We evaluate segment performance using the measures of operating margin and EBIT, which include the effects of corporate expense allocations. Operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of goods sold and revenue tax expense in distribution operations. Operating margin excludes operation and maintenance expense, depreciation and amortization, certain taxes other than income taxes, and the gain or loss on the sale of our assets, if any. These items are included in our calculation of operating income as reflected in our unaudited Condensed Consolidated Statements of Income. EBIT is also a non-GAAP measure that includes operating income and 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 basis.
We believe operating margin is a better indicator than operating revenues of the contribution resulting from customer growth in our distribution operations segment, since the cost of goods sold and revenue tax expenses can vary significantly and are generally billed directly to our customers. We also consider operating margin to be a better indicator in our retail operations, wholesale services, midstream operations and cargo shipping segments, since it is a direct measure of operating margin generated 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 and EBIT measures may not be comparable to similarly titled measures of other companies.
We believe presenting the non-GAAP measurements of basic and diluted earnings per share - as adjusted, which excludes Nicor merger-related expenses, provides investors with an additional measure of our performance. Adjusted basic and diluted earnings per share should not be considered an alternative to, or a more meaningful indicator of, our operating performance than our GAAP basic and diluted earnings per share. The following table reconciles operating revenue and operating margin to operating income, and EBIT to earnings before income taxes and net income, and our GAAP basic and diluted earnings per common share to our non-GAAP basic and diluted earnings per share – as adjusted, together with other consolidated financial information for the periods presented.
| | Three months ended March 31, | | | Three months ended June 30, | | | Six months ended June 30, | |
In millions, except per share amounts | | 2013 | | | 2012 | | | Change | | | 2013 | | | 2012 | | | Change | | | 2013 | | | 2012 | | | Change | |
Operating revenues | | $ | 1,709 | | | $ | 1,404 | | | $ | 305 | | | $ | 904 | | | $ | 686 | | | $ | 218 | | | $ | 2,613 | | | $ | 2,090 | | | $ | 523 | |
Cost of goods sold | | | (973 | ) | | | (719 | ) | | | (254 | ) | | | (407 | ) | | | (240 | ) | | | (167 | ) | | | (1,380 | ) | | | (959 | ) | | | (421 | ) |
Revenue tax expense (1) | | | (49 | ) | | | (41 | ) | | | (8 | ) | | | (24 | ) | | | (13 | ) | | | (11 | ) | | | (73 | ) | | | (54 | ) | | | (19 | ) |
Operating margin | | | 687 | | | | 644 | | | | 43 | | | | 473 | | | | 433 | | | | 40 | | | | 1,160 | | | | 1,077 | | | | 83 | |
Operating expenses (2) | | | (437 | ) | | | (413 | ) | | | (24 | ) | | | (386 | ) | | | (352 | ) | | | (34 | ) | | | (823 | ) | | | (765 | ) | | | (58 | ) |
Revenue tax expense (1) | | | 49 | | | | 41 | | | | 8 | | | | 24 | | | | 13 | | | | 11 | | | | 73 | | | | 54 | | | | 19 | |
Nicor merger expenses (3) | | | - | | | | (10 | ) | | | 10 | | |
Sale of Compass Energy | | | | 11 | | | | - | | | | 11 | | | | 11 | | | | - | | | | 11 | |
Nicor merger expenses (2) | | | | - | | | | (3 | ) | | | 3 | | | | - | | | | (13 | ) | | | 13 | |
Operating income | | | 299 | | | | 262 | | | | 37 | | | | 122 | | | | 91 | | | | 31 | | | | 421 | | | | 353 | | | | 68 | |
Other income | | | 5 | | | | 4 | | | | 1 | | | | 7 | | | | 9 | | | | (2 | ) | | | 12 | | | | 13 | | | | (1 | ) |
EBIT | | | 304 | | | | 266 | | | | 38 | | | | 129 | | | | 100 | | | | 29 | | | | 433 | | | | 366 | | | | 67 | |
Interest expenses | | | 46 | | | | 47 | | | | (1 | ) | | | (46 | ) | | | (45 | ) | | | (1 | ) | | | (92 | ) | | | (92 | ) | | | - | |
Earnings before income taxes | | | 258 | | | | 219 | | | | 39 | | | | 83 | | | | 55 | | | | 28 | | | | 341 | | | | 274 | | | | 67 | |
Income tax expenses | | | 94 | | | | 80 | | | | 14 | | | | (33 | ) | | | (20 | ) | | | (13 | ) | | | (127 | ) | | | (100 | ) | | | (27 | ) |
Net income | | | 164 | | | | 139 | | | | 25 | | | | 50 | | | | 35 | | | | 15 | | | | 214 | | | | 174 | | | | 40 | |
Less net income attributable to the noncontrolling interest | | | 10 | | | | 9 | | | | 1 | | | | 1 | | | | 1 | | | | - | | | | 11 | | | | 10 | | | | 1 | |
Net income attributable to AGL Resources Inc. | | $ | 154 | | | $ | 130 | | | $ | 24 | | | $ | 49 | | | $ | 34 | | | $ | 15 | | | $ | 203 | | | $ | 164 | | | $ | 39 | |
Per common share data | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic earnings per common share attributable to AGL Resources Inc. common shareholders | | $ | 1.31 | | | $ | 1.12 | | | $ | 0.19 | | |
Basic earnings per common share attributable to AGL Resources Inc. common shareholders (3) | | | $ | 0.41 | | | $ | 0.28 | | | $ | 0.13 | | | $ | 1.72 | | | $ | 1.40 | | | $ | 0.32 | |
Transaction costs of Nicor merger | | | - | | | | 0.05 | | | | (0.05 | ) | | | - | | | | 0.02 | | | | (0.02 | ) | | | - | | | | 0.07 | | | | (0.07 | ) |
Basic earnings per share – as adjusted | | $ | 1.31 | | | $ | 1.17 | | | $ | 0.14 | | |
Basic earnings per share - as adjusted | | | $ | 0.41 | | | $ | 0.30 | | | $ | 0.11 | | | $ | 1.72 | | | $ | 1.47 | | | $ | 0.25 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders | | $ | 1.31 | | | $ | 1.11 | | | $ | 0.20 | | |
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders (3) | | | $ | 0.41 | | | $ | 0.28 | | | $ | 0.13 | | | $ | 1.72 | | | $ | 1.40 | | | $ | 0.32 | |
Transaction costs of Nicor merger | | | - | | | | 0.05 | | | | (0.05 | ) | | | - | | | | 0.02 | | | | (0.02 | ) | | | - | | | | 0.07 | | | | (0.07 | ) |
Diluted earnings per share – as adjusted | | $ | 1.31 | | | $ | 1.16 | | | $ | 0.15 | | |
Diluted earnings per share - as adjusted | | | $ | 0.41 | | | $ | 0.30 | | | $ | 0.11 | | | $ | 1.72 | | | $ | 1.47 | | | $ | 0.25 | |
(1) | Adjusted for Nicor Gas’ revenue tax expenses, for Nicor Gas, which are passed directly through to customers. |
(2) | Excludes expenses associated with the merger with Nicor of $10 million ($6 million net of tax) for the three months ended March 31, 2012.
|
(3) | Expenses associated with the Nicor merger are part of operating expenses, but are shown separately to better compare year-over-year results. |
(3) | Sale of Compass Energy generated basic and diluted EPS of $0.04 for the three and six months ending June 30, 2013. |
For the firstsecond quarter of 2013, our net income attributable to AGL Resources Inc. increased by $24$15 million or 18%44% compared to last year. The increase was primarily the result of increased operating margin at distribution operations and retail operations due to colder weather and increased average customer usage compared to prior year, and increased regulatory infrastructure program revenues at Atlanta Gas Light. The increases were slightly offset by lower margins at wholesale services resulting from mark-to-market accounting hedge losses. Additionally, during the three months ended March 31, 2012, we recorded $10 million ($6
· | The increase was primarily the result of increased operating margin at distribution operations and retail operations due to colder weather and increased average customer usage compared to the same period in the prior year, and increased regulatory infrastructure program revenues at Atlanta Gas Light. The operating margin of our wholesale services segment for the quarter increased by $8 million as a result of higher commercial activity. The increase in our net income attributable to AGL Resources Inc. was also favorably impacted by the $11 million pre-tax gain on the sale of Compass Energy in our wholesale services segment. |
· | The increases were partially offset by increased operating expenses at distribution operations as our incentive compensation expense increased to targeted levels. In addition, our bad debt expense increased at retail operations as a result of colder weather combined with natural gas prices that were higher than in the same period of the prior year. |
· | During the three months ended June 30, 2012, we recorded $3 million ($2 million net of tax) of Nicor merger related expenses. |
For the six months ended June 30, 2013, our net income attributable to AGL Resources Inc. increased by $39 million or 24% compared to last year.
· | The primary drivers of this increase are consistent with those described above for the second quarter of 2013 compared to 2012. |
· | During the six months ended June 30, 2012, we recorded $13 million ($8 million net of tax) of Nicor merger related expenses. |
OurFor the second quarter of 2013, our income tax expense increased by $14$13 million or 18% compared to the firstsecond quarter of 2012 and by $27 million for the six months ended June 30, 2013 compared to the same period of 2012. The increase wasincreases were primarily due to higher consolidated earnings, as previously discussed.discussed. Our income tax expense is determined from earnings before income taxes less net income attributable to noncontrolling interest.
Operating Metrics
Weather We measure the effects of weather on our business through Heating Degree Days. Generally, increased Heating Degree Days result in greaterhigher demand for gas on our distribution systems. With the exception of Nicor Gas and Florida City Gas, we have various regulatory mechanisms, such as weather normalization mechanisms, at all of our utilities, which limit our exposure to weather changes within typical ranges in alleach of our utilities’ respective service areas. However, our customers in Illinois and retail operations’ customers in Georgia can be impacted by warmer or colder than normal weather. We have presented the Heating Degree Day information for those locations in the following table.
| | | Three months ended June 30, | | | | | | | | | Six months ended June 30, | | | | | | | |
Weather (Heating Degree Days) | Weather (Heating Degree Days) | | | | | | | | | Normal | | | 2013 | | | 2012 | | | colder | | | colder | | | Normal | | | 2013 | | | 2012 | | | colder | | | colder | |
| | Three months ended March 31, | | | 2013 vs. 2012 | | | 2013 vs. normal | | |
| | Normal | | | 2013 | | | 2012 | | | colder | | | colder | | |
Illinois (1) (2) | | | 2,991 | | | | 3,153 | | | | 2,358 | | | | 34 | % | | | 5 | % | | | 623 | | | | 715 | | | | 542 | | | | 32 | % | | | 15 | % | | | 3,614 | | | | 3,868 | | | | 2,900 | | | | 33 | % | | | 7 | % |
Georgia (1) | | | 1,452 | | | | 1,461 | | | | 983 | | | | 49 | % | | | 1 | % | | | 136 | | | | 178 | | | | 72 | | | | 147 | % | | | 31 | % | | | 1,588 | | | | 1,639 | | | | 1,055 | | | | 55 | % | | | 3 | % |
(1) | Normal represents the ten-year average from JanJanuary 1, 2003 through March 31,June 30, 2012, for Illinois at Chicago Midway International Airport, and for Georgia at Atlanta Hartsfield-Jackson International Airport as obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center. |
(2) | The 10-year average Heating Degree Days for the period, as established by the Illinois Commission in our last rate case, is 2,902617 for the second quarter and 3,519 for the first six months from 1998 through 2007. |
(2) | The 10-year average for the period, as established by the Illinois Commission in our last rate case, is 2,902 from 1998 through 2007. |
During the three months ended March 31,June 30, 2013, weather in Illinois was 15% colder-than-normal and 32% colder than last year. Georgia also experienced 31% colder-than-normal weather, and 147% colder than the same period in the prior year. During the six months ended June 30, 2013, we experienced weather in Illinois that was 5%7% colder-than-normal and 34%33% colder than lastthe same period in the prior year. Georgia also experienced 1%3% colder-than-normal weather, and 49%55% colder than the same period last year. This colder weather positively impacted our operating margin by $24 million compared to last year. However, the 2011/2012 Heating Season was one of the warmest on record and was 18% - 40% warmer-than-normal across our service territory, which negatively impacted our operating margin by $21 million in the first quarter of 2012.
Customers Our customer metrics highlight the average number of customers for which we provide services and are provided in the following table. ThisThe number of customers at distribution operations and energy customers at retail operations can be impacted by natural gas prices, economic conditions and competition from alternative fuels. Our year-over-year consolidated utility customer growth rate was 0.3%0.5% and 0.4% for the three and six months ended March 31,June 30, 2013, respectively, and we anticipate overall competition and utility customer growth trends for 2013 to be similarimprove compared to that experienced in 2012.prior year.
Our energy customers at retail operations are principallyprimarily located in Georgia and Illinois. The number of customers within these locations remained consistent for the three months ended March 31, 2013 and 2012; however, the market in Georgia remains very competitive.competitive, which we expect will continue for the foreseeable future. In 2013, our retail operations segment intends on continuing its efforts of enteringto enter and expandingexpand within targeted markets to increase its energy customers and expandingexpand our service contracts to include our service territories in Georgia, Virginia and Tennessee.
Customers and service contracts (average end-use - in thousands) | | Three months ended March 31, | | | 2013 vs. 2012 | |
| | 2013 | | | 2012 | | | % change | |
Distribution Operations customers | | | 4,501 | | | | 4,487 | | | | 0.3 | % |
Retail Operations | | | | | | | | | | | | |
Energy Customers (1) | | | 613 | | | | 675 | | | | (9 | )% |
Service Contracts (2) | | | 1,183 | | | | 711 | | | | 66 | % |
Market share in Georgia | | | 32 | % | | | 32 | % | | | - | % |
| | Three months ended June 30, | | | 2013 vs. 2012 | | | Six months ended June 30, | | | 2013 vs. 2012 | |
Customers and service contracts (average end-use, in thousands) | | 2013 | | | 2012 | | | % change | | | 2013 | | | 2012 | | | % change | |
Distribution operations customers | | | 4,492 | | | | 4,468 | | | | 1 | % | | | 4,496 | | | | 4,478 | | | | - | % |
Retail operations | | | | | | | | | | | | | | | | | | | | | | | | |
Energy customers (1) | | | 618 | | | | 615 | | | | - | % | | | 616 | | | | 645 | | | | (4 | )% |
Service contracts (2) | | | 1,176 | | | | 689 | | | | 71 | % | | | 1,095 | | | | 701 | | | | 56 | % |
Market share in Georgia | | | 32 | % | | | 32 | % | | | - | % | | | 32 | % | | | 32 | % | | | - | % |
(1) | A portion of the customers represents customer equivalents in Ohio, which are computed by the actual delivered volumes divided by the expected average customer usage. Decrease primarily due to our contract to serve approximately 50,000 customer equivalents that ended on April 1, 2012.2012. |
(2) | Increase primarily due to acquisition of approximately 500,000 service contracts on January 31, 2013. These contracts are as of March 31, 2013 and 2012. |
Volumes Our natural gas volume metrics for distribution operations and retail operations, as shown in the following table, present the effects of weather and our customers’ demand for natural gas compared to prior year. Wholesale services’ daily physical sales volumes represent the daily average natural gas volumes sold to its customers. Within our midstream operations segment, our natural gas storage businesses seek to have a significant percentage of their working natural gas capacity under firm subscription, but also take into account current and expected market conditions. This allows our natural gas storage business to generate additional revenue during times of peak market demand for natural gas storage services, but retain some consistency with their earnings and maximize the value of the investments.
Additionally, our cargo shipping segment measures the volume of shipments during the period in TEUs and is presented in the following table.TEUs. We continue to seek opportunities to profitably increase our number of TEUs and maximize the utilization of our containers and vessels. Our volume metrics are presented in the following table:
Volumes | | Three months ended March 31, | | | 2013 vs. 2012 | | |
| | 2013 | | | 2012 | | | % change | | | Three months ended June 30, | | | 2013 vs. 2012 | | | Six months ended June 30, | | | 2013 vs. 2012 | |
Distribution Operations (In Bcf) | | | | | | | | | | |
Volumes | | | 2013 | | | 2012 | | | % change | | | 2013 | | | 2012 | | | % change | |
Distribution operations (In Bcf) | | | | | | | | | | | | | | | | | | | |
Firm | | | 309 | | | | 240 | | | | 29 | % | | | 107 | | | | 93 | | | | 15 | % | | | 416 | | | | 333 | | | | 25 | % |
Interruptible | | | 30 | | | | 27 | | | | 11 | % | | | 26 | | | | 26 | | | | - | % | | | 56 | | | | 53 | | | | 6 | % |
Total | | | 339 | | | | 267 | | | | 27 | % | | | 133 | | | | 119 | | | | 12 | % | | | 472 | | | | 386 | | | | 22 | % |
Retail Operations (In Bcf) | | | | | | | | | | | | | |
Retail operations (In Bcf) | | | | | | | | | | | | | | | | | | | | | | | | | |
Georgia firm | | | 18 | | | | 14 | | | | 29 | % | | | 5 | | | | 3 | | | | 67 | % | | | 23 | | | | 17 | | | | 35 | % |
Illinois | | | 4 | | | | 4 | | | | - | % | | | 1 | | | | 1 | | | | - | % | | | 5 | | | | 5 | | | | - | % |
Expanded markets (1) | | | 3 | | | | 4 | | | | (25 | )% | |
Wholesale Services | | | | | | | | | | | | | |
Other (1) | | | | 1 | | | | 1 | | | | - | % | | | 4 | | | | 5 | | | | (20 | )% |
Wholesale services | | | | | | | | | | | | | | | | | | | | | | | | | |
Daily physical sales (Bcf / day) | | | 6.3 | | | | 6.0 | | | | 5 | % | | | 5.3 | | | | 4.9 | | | | 8 | % | | | 5.8 | | | | 5.4 | | | | 7 | % |
Cargo Shipping (TEU’s - in thousands) | | | | | | | | | | | | | |
Cargo shipping (TEU’s - in thousands) | | | | | | | | | | | | | | | | | | | | | | | | | |
Shipments | | | 45 | | | | 41 | | | | 10 | % | | | 45 | | | | 40 | | | | 13 | % | | | 90 | | | | 81 | | | | 11 | % |
| | As of March 31, | | | | | | | As of June 30, | | | | | | | | | | | | | | | | | |
| | | 2013 | | | | 2012 | | | | | | | | 2013 | | | | 2012 | | | | | | | | | | | | | | | | | |
Midstream Operations | | | | | | | | | | | | | |
Midstream operations | | | | | | | | | | | | | | | | | | | | | | | | | |
Working natural gas capacity (in Bcf) (2) | | | 31.8 | | | | 13.3 | | | | | | | 31.8 | | | | 24.3 | | | | | | | | | | | | | |
% of firm capacity under subscription by third parties (3) | | | 46 | % | | | 68 | % | | | | | | | 33 | % | | | 58 | % | | | | | | | | | | | | | | | | |
(1) | Includes Florida, Maryland, New York and Ohio. |
(2) | Includes Central Valley Storage that was acquired in connection with the Nicor merger, whichand began commercial operations in the second quarter of 2012. Additionally, Golden Triangle Storage’s Cavern 1 is currently going through a process to assess the cavern’smonitor its working gas capacity and to slightly increase the size of the facility. The process began in Januaryearly 2013 and is expected to continue throughwith limited commercial operations resuming in the third quarter of 2013. We expect Cavern 1 to return to full commercial service in the first quarter of 2014. Cavern 2 will cover the obligations of Cavern 1 during this process. |
(3) | The percentage of capacity under subscription does not include 3.5 Bcf of capacity under contract with Sequent at June 30, 2013, and 3 Bcf of capacity under contract with Sequent at March 31, 2013, and 4 Bcf of capacity under contract with Sequent at March 31,June 30, 2012. |
First quarterThree and six months ended June 30, 2013 compared to first quarterthree and six months ended June 30, 2012
Operating margin, operating expenses and EBIT information for each of our segments are contained in the following tables for the three months ended March 31, 2013 and 2012.tables:
| | 2013 | | | 2012 | | | Three months ended June 30, 2013 | | | Three months ended June 30, 2012 | |
In millions | | Operating margin (1) (2) | | | Operating expenses (2) | | | EBIT (1) | | | Operating margin (1) (2) | | | Operating expenses (2) (3) | | | EBIT (1) | | | Operating margin (1) (2) | | | Operating expenses (2) | | | EBIT (1) (4) | | | Operating margin (1) (2) | | | Operating expenses (2) (3) | | | EBIT (1) | |
Distribution operations | | $ | 505 | | | $ | 290 | | | $ | 218 | | | $ | 470 | | | $ | 277 | | | $ | 194 | | | $ | 368 | | | $ | 263 | | | $ | 109 | | | $ | 346 | | | $ | 250 | | | $ | 100 | |
Retail operations | | | 107 | | | | 37 | | | | 70 | | | | 97 | | | | 37 | | | | 60 | | | | 50 | | | | 38 | | | | 12 | | | | 43 | | | | 29 | | | | 14 | |
Wholesale services(4) | | | 29 | | | | 14 | | | | 15 | | | | 34 | | | | 15 | | | | 19 | | | | 11 | | | | 11 | | | | 11 | | | | 3 | | | | 12 | | | | (9 | ) |
Midstream operations | | | 12 | | | | 11 | | | | 2 | | | | 11 | | | | 8 | | | | 3 | | | | 11 | | | | 12 | | | | - | | | | 11 | | | | 10 | | | | 2 | |
Cargo shipping | | | 34 | | | | 34 | | | | 2 | | | | 34 | | | | 36 | | | | 1 | | | | 34 | | | | 37 | | | | (1 | ) | | | 29 | | | | 33 | | | | (1 | ) |
Other | | | - | | | | 2 | | | | (3 | ) | | | (2 | ) | | | 9 | | | | (11 | ) | | | (1 | ) | | | 1 | | | | (2 | ) | | | 1 | | | | 8 | | | | (6 | ) |
Consolidated | | $ | 687 | | | $ | 388 | | | $ | 304 | | | $ | 644 | | | $ | 382 | | | $ | 266 | | | $ | 473 | | | $ | 362 | | | $ | 129 | | | $ | 433 | | | $ | 342 | | | $ | 100 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six months ended June 30, 2013 | | | Six months ended June 30, 2012 | |
In millions | | Operating margin (1) (2) | | | Operating expenses (2) | | | EBIT (1) (4) | | | Operating margin (1) (2) | | | Operating expenses (2) (3) | | | EBIT (1) | |
Distribution operations | | $ | 873 | | | $ | 553 | | | $ | 327 | | | $ | 816 | | | $ | 527 | | | $ | 294 | |
Retail operations | | | 157 | | | | 75 | | | | 82 | | | | 140 | | | | 66 | | | | 74 | |
Wholesale services (4) | | | 40 | | | | 25 | | | | 26 | | | | 37 | | | | 27 | | | | 10 | |
Midstream operations | | | 23 | | | | 23 | | | | 2 | | | | 22 | | | | 18 | | | | 5 | |
Cargo shipping | | | 68 | | | | 71 | | | | 1 | | | | 63 | | | | 69 | | | | - | |
Other | | | (1 | ) | | | 3 | | | | (5 | ) | | | (1 | ) | | | 17 | | | | (17 | ) |
Consolidated | | $ | 1,160 | | | $ | 750 | | | $ | 433 | | | $ | 1,077 | | | $ | 724 | | | $ | 366 | |
(1) | These are non-GAAP measures. A reconciliation of operating margin to operating income and EBIT to earnings before income taxes and net income is contained in “Results of Operations” herein. See Note 10 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein for additional segment information. |
(2) | Operating margin and expense are adjusted for revenue tax expense for Nicor Gas, which is passed directly through to customers. |
(3) | Includes $10$3 million and $13 million in Nicor merger transaction expenses associated with the merger with Nicor for the first quarterthree and six months ended June 30, 2012. |
(4) | EBIT includes $11 million gain on sale of 2012.Compass Energy. |
Distribution Operations
Our distribution operations segment is the largest component of our business and is subject to regulation and oversight by agencies in each of the seven states we serve. These agencies approve natural gas rates designed to provide us the opportunity to generate revenues to recover the cost of natural gas delivered to our customers and our fixed and variable costs, such as depreciation, interest, maintenance and overhead costs, and to earn a reasonable return for our shareholders.
With the exception of Atlanta Gas Light, our second largestsecond-largest utility, the earnings of our regulated utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas and general economic conditions that may impact our customers’ ability to pay for gas consumed. DistributionFor the three and six months ended June 30, 2013, distribution operations’ EBIT increased by $24$9 million or 12%9% and $33 million or 11%, respectively, compared to lastprior year, as shown in the following table.
In millions | | | |
EBIT - for first quarter of 2012 | | $ | 194 | |
| | | | |
Operating margin | | | | |
Increased operating margin mainly driven by higher customer usage at Nicor Gas due to colder weather compared to prior year | | | 14 | |
Increased operating margin as a result of energy efficiency programs at Nicor Gas | | | 10 | |
Increased revenues from regulatory infrastructure programs at Atlanta Gas Light | | | 8 | |
Increased operating margin from higher usage at Florida City Gas due to colder weather compared to prior year | | | 2 | |
Increased operating margin from higher usage at Elizabethtown Gas compared to prior year | | | 1 | |
Increase in operating margin | | | 35 | |
| | | | |
Operating expenses | | | | |
Increased expenses as a result of energy efficiency program expenses at Nicor Gas | | | 10 | |
Increased incentive compensation costs due to amounts returning to targeted levels | | | 5 | |
Increased depreciation expense as a result of increased PP&E from infrastructure additions and improvements | | | 2 | |
Decreased retirement benefits expenses primarily as a result of change in actuarial assumptions | | | (3 | ) |
Other | | | (1 | ) |
Increase in operating expenses | | | 13 | |
Increased AFUDC equity primarily from STRIDE projects at Atlanta Gas Light | | | 2 | |
EBIT - for first quarter of 2013 | | $ | 218 | |
In millions | | Three months ended | | | Six months ended | |
EBIT - for June 30, 2012 | | $ | 100 | | | $ | 294 | |
` | | | | | | | | |
Operating margin | | | | | | | | |
Increased operating margin mainly driven by colder weather and higher customer usage at Nicor Gas, Florida City Gas, Elizabethtown Gas and Virginia Natural Gas compared to prior year | | | 10 | | | | 27 | |
Increased rider revenues primarily as a result of energy efficiency program recoveries at Nicor Gas | | | 2 | | | | 12 | |
Increased revenues from regulatory infrastructure programs, primarily at Atlanta Gas Light | | | 10 | | | | 18 | |
Increase in operating margin | | | 22 | | | | 57 | |
| | | | | | | | |
Operating expenses | | | | | | | | |
Increased rider expenses primarily as a result of energy efficiency program expenses at Nicor Gas | | | 2 | | | | 12 | |
Increased incentive compensation costs due to amounts returning to targeted levels | | | 4 | | | | 9 | |
Increased depreciation expense as a result of increased PP&E from infrastructure additions and improvements | | | 4 | | | | 6 | |
Decreased benefits expenses primarily related to medical claims and retiree healthcare costs | | | (3 | ) | | | (6 | ) |
Increased outside service costs and other | | | 6 | | | | 5 | |
Increase in operating expenses | | | 13 | | | | 26 | |
Increased AFUDC equity primarily from STRIDE projects at Atlanta Gas Light | | | - | | | | 2 | |
EBIT - for June 30, 2013 | | $ | 109 | | | $ | 327 | |
Retail Operations
Our retail operations segment, which consists of SouthStar and several businesses that provide energy-related products and services to retail markets, also is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to mitigate potential weather impacts. RetailFor the second quarter of 2013, retail operations’ EBIT decreased by $2 million or 14% compared to the second quarter of 2012 and increased by $10$8 million or 17%11% for the six months ended June 30, 2013, compared to lastprior year, as shown in the following table.
In millions | | | | | Three months ended | | | Six months ended | |
EBIT - for first quarter of 2012 | | $ | 60 | | |
EBIT - for June 30, 2012 | | | $ | 14 | | | $ | 74 | |
| | | | | | | | | | | | |
Operating margin | | | | | | | | | | | | |
Increased average customer usage in Georgia due to colder weather relative to prior year, net of weather derivatives | | | 10 | | | | 4 | | | | 14 | |
Increased margin at retail services primarily due to acquired NiSource Inc. retail service contracts | | | 4 | | |
Increased margin primarily due to January 2013 acquisition of retail service contracts | | | | 8 | | | | 12 | |
Inventory write-down (LOCOM) in 2012 | | | 3 | | | | - | | | | 3 | |
Increased margin in Illinois mainly due to timing of revenue recognition associated with fixed bill products and favorable weather | | | 2 | | |
Decreased margin in Illinois mainly due to timing of revenue recognition associated with fixed bill products | | | | (4 | ) | | | (2 | ) |
Decrease related to increase in transportation and gas costs and lower retail price spreads, partially offset by favorable customer portfolio | | | (10 | ) | | | - | | | | (10 | ) |
Other | | | 1 | | | | (1 | ) | | | - | |
Increase in operating margin | | | 10 | | | | 7 | | | | 17 | |
| | | | | | | | | | | | |
Operating expenses | | | | | | | | | | | | |
Increased expenses at retail services primarily due to acquisition of NiSource Inc’s retail service contracts | | | 3 | | |
Decreased payroll, benefits, outside services and other | | | (3 | ) | |
Increased expenses primarily due to January 2013 acquisition of retail service contracts | | | | 6 | | | | 9 | |
Increased bad debt expense primarily related to colder weather and higher natural gas prices | | | | 2 | | | | 2 | |
Increased (decreased) payroll, benefits, marketing and other expenses | | | | 1 | | | | (2 | ) |
Increase in operating expenses | | | - | | | | 9 | | | | 9 | |
EBIT - for first quarter of 2013 | | $ | 70 | | |
EBIT - for June 30,2013 | | | $ | 12 | | | $ | 82 | |
Wholesale Services
Our wholesale services segment is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services and wholesale marketing. EBIT for our wholesale services segment is impacted by volatility in the natural gas market arising from a number of factors, including weather fluctuations and changes in supply or demand for natural gas in different regions of the country. WholesaleFor the three and six months ended June 30, 2013, wholesale services’ EBIT decreasedincreased by $4$20 million and $16 million, respectively, compared to lastprior year, as shown in the following table.
In millions | | | |
EBIT - for first quarter of 2012 | | $ | 19 | |
| | | | |
Operating margin | | | | |
Change in commercial activity largely driven by the withdrawal of a portion of the storage inventory hedged at the end of 2012 and colder weather | | | 26 | |
Storage inventory write-down (LOCOM) in 2012 | | | 18 | |
Change in value on storage hedges as a result of increase in NYMEX natural gas prices | | | (36 | ) |
Change in value on transportation and forward commodity hedges from price movements related to natural gas transportation positions | | | (13 | ) |
Decrease in operating margin | | | (5 | ) |
| | | | |
Operating expenses | | | | |
Decreased incentive compensation, outside services costs and other | | | (1 | ) |
Decrease in operating expenses | | | (1 | ) |
EBIT - for first quarter of 2013 | | $ | 15 | |
In millions | | Three months ended | | | Six months ended | |
EBIT - for June 30, 2012 | | $ | (9 | ) | | $ | 10 | |
| | | | | | | | |
Operating margin | | | | | | | | |
Change in commercial activity largely driven by colder weather, increased cash optimization opportunities in the supply constrained northeast corridor and the withdrawal of a portion of the storage inventory economically hedged at the end of 2012 | | | 13 | | | | 32 | |
Storage inventory write-down (LOCOM) | | | (8 | ) | | | 4 | |
Change in value on storage hedges as a result of decrease in NYMEX natural gas prices | | | 38 | | | | 12 | |
Change in value on transportation and forward commodity hedges from price movements related to natural gas transportation positions | | | (35 | ) | | | (45 | ) |
Increase in operating margin | | | 8 | | | | 3 | |
| | | | | | | | |
Operating expenses | | | | | | | | |
Decreased compensation expense, outside services and other costs | | | (1 | ) | | | (2 | ) |
Decrease in operating expenses | | | (1 | ) | | | (2 | ) |
Gain on sale of Compass Energy | | | 11 | | | | 11 | |
EBIT - for June 30, 2013 | | $ | 11 | | | $ | 26 | |
The following table indicates the components of wholesale services’ operating margin for the periods presented.
| | March 31, | | | Three months ended June 30, | | | Six months ended June 30, | |
In millions | | 2013 | | | 2012 | | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
Commercial activity recognized | | $ | 50 | | | $ | 24 | | | $ | 6 | | | $ | (7 | ) | | $ | 48 | | | $ | 16 | |
(Loss) gain on storage hedges | | | (17 | ) | | | 19 | | |
Gain (loss) on storage hedges | | | | 29 | | | | (9 | ) | | | 18 | | | | 6 | |
(Loss) gain on transportation and forward commodity hedges | | | (4 | ) | | | 9 | | | | (16 | ) | | | 19 | | | | (18 | ) | | | 27 | |
Inventory LOCOM adjustment, net of estimated recoveries | | | - | | | | (18 | ) | | | (8 | ) | | | - | | | | (8 | ) | | | (12 | ) |
Operating margin | | $ | 29 | | | $ | 34 | | | $ | 11 | | | $ | 3 | | | $ | 40 | | | $ | 37 | |
Change in commercial activity The commercial activity at wholesale services includes recognized storage and transportation values which were generated in prior periods, and the impact of prior period hedge gains and losses. Additionally, the commercial activity includes operating margin generated and recognized in the current period. The increase in commercial activity reflects the recognition of operating margin resulting from the withdrawal of storage inventory hedged at the end of 2012 that was included in the storage withdrawal schedule with a value of $27 million as of December 31, 2012 as well as the effecteffects of colder weather onand increased cash optimization opportunities related to certain of our transportation portfolio positions, particularly in the Northeastern United States. As previously discussed, our operating margin opportunities are expected to be lower in 2013 due to continued lower volatility and lower seasonal price spreads associated with our storage portfolio.
Change in storage and transportation hedges Seasonal (storage) and geographical location (transportation) spreads and overall natural gas price volatility continued to remain low relative to historical periods. However, during the current yearsecond quarter of 2013, a decline in natural gas prices moved higher resultingresulted in storage hedge lossesgains as compared to storage hedge gainsthe same period last year resulting from a downward movement in natural gas prices. Gains from our transportation position in 2012 were primarily due to large transportation spreads atyear. For the time our transportation positions were executed and the subsequent narrowingfirst six months of regional transportation spreads. However, similar to the fourth quarter of 2012,2013, significant volatility continued during the current quarter at natural gas delivery points throughout the northeast corridor relative to natural gas delivery constraints in the region resulting, resulted in losses on our transportation positions.
Withdrawal schedule Sequent’s expected natural gas withdrawals from storage are presented in the following table along with the operating revenues expected at the time of withdrawal. Sequent’s expected operating revenues exclude storage demand charges but are net of the estimated impact of profit sharing under our asset management agreements and reflect the amounts that are realizable in future periods based on the inventory withdrawal schedule and forward natural gas prices at March 31,June 30, 2013 and 2012. A portion of Sequent’s storage inventory is economically hedged with futures contracts, which results in realization of substantially fixed operating revenues, timing notwithstanding. For more information on Sequent’s energy marketing and risk management activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk” of our 2012 Form 10-K.
Withdrawal schedule | | Total storage (in Bcf) (WACOG $2.85) | | | Expected operating revenues (1) (in millions) | | | Total storage (in Bcf) (WACOG $3.26) | | | Expected operating revenues (1) (in millions) | |
2013 | | | | | | | | | | | | |
Second quarter | | | 15 | | | $ | 16 | | |
Third quarter | | | 12 | | | | 13 | | | | 28 | | | $ | 5 | |
Fourth quarter | | | 4 | | | | 4 | | | | 20 | | | | 8 | |
2014 | | | 1 | | | | 1 | | | | | | | | | |
Total at March 31, 2013 | | | 32 | | | $ | 34 | | |
First quarter | | | | 2 | | | | 1 | |
Total at June 30, 2013 | | | | 50 | | | $ | 14 | |
Total at December 31, 2012 | | | 51 | | | $ | 27 | | | | 51 | | | $ | 27 | |
Total at March 31, 2012 | | | 47 | | | $ | 19 | | |
Total at June 30, 2012 | | | | 55 | | | $ | 47 | |
(1) | Represents expected operating revenues from planned storage withdrawals associated with existing inventory positions and could change as Sequent adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations. |
Midstream Operations
Our midstream operations segment’s primary activity is operating non-utility storage and pipeline facilities including the development, acquisition and operation of high-deliverability underground natural gas storage assets. While this business can also generate additional revenue during times of peak market demand for natural gas storage services, the majoritycertain of our storage services are covered under medium to long-term contracts at fixed market rates. MidstreamFor the three and six months ended June 30, 2013, midstream operations’ EBIT decreased by $1$2 million and $3 million, respectively, compared to lastprior year, as shown in the following table.
In millions | | | | | Three months ended | | | Six months ended | |
EBIT - for first quarter of 2012 | | $ | 3 | | |
EBIT - for June 30, 2012 | | | $ | 2 | | | $ | 5 | |
| | | | | | | | | | | | |
Operating margin | | | | | | | | | | | | |
Increased revenues at Golden Triangle as a result of Cavern 2 beginning commercial service in third quarter 2012 | | | 2 | | |
Decreased margin at Jefferson Island as a result of lower subscription rates | | | (1 | ) | |
Increased revenues at Golden Triangle as a result of Cavern 2 beginning commercial service in third quarter 2012, partially offset by lower revenues at Jefferson Island as a result of lower subscription rates | | | | - | | | | 1 | |
Increase in operating margin | | | 1 | | | | - | | | | 1 | |
| | | | | | | | | | | | |
Operating expenses | | | | | | | | | | | | |
Increased depreciation, property taxes, storage expenses and outside services largely due to Central Valley and Cavern 2 at Golden Triangle beginning commercial service in 2012 | | | 3 | | |
Increased depreciation, property taxes, storage expenses, payroll and outside services largely due to Central Valley and Cavern 2 at Golden Triangle beginning commercial service in 2012 | | | | 2 | | | | 5 | |
Increase in operating expenses | | | 3 | | | | 2 | | | | 5 | |
Increase from equity investment in Horizon Pipeline | | | 1 | | | | - | | | | 1 | |
EBIT - for first quarter of 2013 | | $ | 2 | | |
EBIT - for June 30, 2013 | | | $ | - | | | $ | 2 | |
Cargo Shipping
Our cargo shipping segment’s primary activity is transporting containerized freight in the Bahamas and the Caribbean, a region that has historically been characterized by modest market growth and intense competition. Such shipments consist primarily of southbound cargo such as building materials, food and other necessities for developers, distributors and residents in the region, as well as tourist-related shipments intended for use in hotels and resorts and on cruise ships. The balance of the cargo consists primarily of interisland shipments of consumer staples and northbound shipments of apparel, rum and agricultural products. Other related services, such as inland transportation and cargo insurance, are also provided within the cargo shipping segment. Our cargo shipping segment also includes an equity investment in Triton, a cargo container leasing business. For more information about our investment in Triton, see Note 10 to our Consolidated Financial Statements under Item 8 included in our 2012 Form 10-K.
For the second quarter of 2013, cargo shipping’s EBIT was flat compared to the second quarter of 2012 and increased by $1 million for the six months ended June 30, 2013, compared to lastprior year, as shown in the following table.
In millions | | | | | Three months ended | | | Six months ended | |
EBIT - for first quarter of 2012 | | $ | 1 | | |
EBIT - for June 30, 2012 | | | $ | (1 | ) | | $ | - | |
| | | | | | | | | | | | |
Operating margin | | | | | | | | | | | | |
TEU volume increased due to market share expansion and modest improvement in economic conditions in our service regions | | | 5 | | |
TEU volume increased due to market share expansion and modest improvement in economic conditions in our service regions; leverage effect of volume increases on fuel expense | | | | 8 | | | | 13 | |
Decreased TEU rates due to ongoing overcapacity, changes in cargo mix and competitive pressures | | | (4 | ) | | | (4 | ) | | | (8 | ) |
Other | | | (1 | ) | | | 1 | | | | - | |
Increase in operating margin | | | - | | | | 5 | | | | 5 | |
| | | | | | | | | | | | |
Operating expenses | | | | | | | | | | | | |
Decreased depreciation expense | | | (1 | ) | | | (1 | ) | | | (2 | ) |
Decreased payroll, benefits, outside services and other | | | (1 | ) | |
Decrease in operating expenses | | | (2 | ) | |
Increased payroll, benefits, outside services and other | | | | 5 | | | | 4 | |
Increase in operating expenses | | | | 4 | | | | 2 | |
Decrease from equity investment income in Triton | | | (1 | ) | | | (1 | ) | | | (2 | ) |
EBIT - for first quarter of 2013 | | $ | 2 | | |
EBIT - for June 30, 2013 | | | $ | (1 | ) | | $ | 1 | |
Overview The acquisition of natural gas and pipeline capacity, payment of dividends and funding of working capital needs are our most significant short-term financing requirements. The need for long-term capital is driven primarily by capital expenditures and maturities of long-term debt. The liquidity required to fund our working capital, capital expenditures and other cash needs is primarily provided by our operating activities. Our short-term cash requirements not met with cash from operations are primarily satisfied with short-term borrowings under our commercial paper programs, which are supported by the AGL Credit Facility and the Nicor Gas Credit Facility. Periodically, we raise funds supporting our long-term cash needs from the issuance of long-term debt or equity securities. We regularly evaluate our funding strategy and profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner. Consistent with this, in May 2013, we anticipate issuing approximatelyissued $500 million ofin 30-year senior notes in the second quarter of 2013. We have hedged the underlyingwith an interest rate associated with $300 million in principal amount of the anticipated proceeds, with the remaining un-hedged principal amount subject to fluctuations in interest rates until the financing is completed.4.4%.
Our capital market strategy is focused on maintaining strong Consolidated Statements of Financial Position, ensuring ample cash resources and daily liquidity, accessing capital markets at favorable times as necessary, managing critical business risks and maintaining a balanced capital structure through the appropriate issuance of equity or long-term debt securities.
Our financing activities, including long-term and short-term debt and equity, are subject to customary approval or review by state and federal regulatory bodies, including the various commissions of the states in which we conduct business. Certain financing activities we undertake may also be subject to approval by state regulatory agencies. A substantial portion of our consolidated assets, earnings and cash flows 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. Nicor Gas is restricted by regulation in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Dividends to AGL Resources are allowed only to the extent of Nicor Gas’ retained earnings balance, which was $502$480 million at March 31,June 30, 2013.
We believe the amounts available to us under our senior notes, AGL Credit Facility and Nicor Gas Credit Facility, through the issuance of debt and equity securities, combined with cash provided by operating activities, will continue to allow us to meet our needs for working capital, pension contributions,and retiree welfare benefits, capital expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years. Our ability to satisfy our working capital requirements and our debt service obligations, or fund planned capital expenditures, will substantially depend upon our future operating performance (which will be affected by prevailing economic conditions), and financial, business and other factors, some of which we are unable to control. These factors include, among others, regulatory changes, the price of and demand for natural gas and operational risks.
As of March 31,June 30, 2013 and 2012, and December 31, 2012, we had $76$79 million, $74$76 million and $80 million, respectively, of cash and short and long-termshort-term investments in our unaudited Condensed Consolidated Statements of Financial Position that were generated fromheld by Tropical Shipping. This cash and the investments are not available for use by our other operations unless we repatriate a portion of Tropical Shipping’s earnings in the form of a dividend, that would be subject toand pay a significant amount of United States income tax. See Note 12 to our Consolidated Financial Statements under Item 8 included in our 2012 Form 10-K for additional information on our income taxes.
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,” in our 2012 Form 10-K for additional information on items that could impact our liquidity and capital resource requirements.
Capital Projects We continue to focus on capital discipline and cost control, while moving ahead with projects and initiatives that we expect will have current and future benefits to us and our customers, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure. The following table and discussions provide updates on some of our larger capital projects at our distribution operations segment. These programs update or expand our distribution systems to improve system reliability and meet operational flexibility and growth. Our anticipated expenditures for these programs in 2013 are discussed in “Liquidity and Capital Resources” under the caption ‘Cash Flows from Financing Activities’ in our 2012 Form 10-K.
Dollars in millions | Utility | | Expenditures in 2013 | | | Expenditures since project inception | | | Miles of pipe replaced | | | Year project began | | | Anticipated year of completion | | Utility | | Expenditures in 2013 | | | Expenditures since project inception | | | Miles of pipe replaced | | | Year project began | | | Anticipated year of completion | |
STRIDE program | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Pipeline replacement program | Atlanta Gas Light | | $ | 35 | | | $ | 717 | | | | 2,632 | | | | 1998 | | | | 2013 | | Atlanta Gas Light | | $ | 76 | | | $ | 758 | | | | 2,663 | | | | 1998 | | | | 2013 | |
Integrated System Reinforcement Program | Atlanta Gas Light | | | 2 | | | | 226 | | | | n/a | | | | 2009 | | | | 2013 | | Atlanta Gas Light | | | 10 | | | | 234 | | | | n/a | | | | 2009 | | | | 2013 | |
Integrated Customer Growth Program | Atlanta Gas Light | | | 10 | | | | 39 | | | | n/a | | | | 2010 | | | | 2013 | | Atlanta Gas Light | | | 10 | | | | 39 | | | | n/a | | | | 2010 | | | | 2013 | |
Enhanced infrastructure program | Elizabethtown Gas | | | 1 | | | | 109 | | | | 96 | | | | 2009 | | | | (1 | ) | Elizabethtown Gas | | | 1 | | | | 109 | | | | 96 | | | | 2009 | | | | (1) | |
Accelerated infrastructure program | Virginia Natural Gas | | | 4 | | | | 20 | | | | 52 | | | | 2012 | | | | 2017 | | Virginia Natural Gas | | | 11 | | | | 27 | | | | 61 | | | | 2012 | | | | 2017 | |
Total | | | $ | 52 | | | $ | 1,111 | | | | 2,780 | | | | | | | | | | | | $ | 108 | | | $ | 1,167 | | | | 2,820 | | | | | | | | | |
(1) | In July 2012, we filed a request to extend this program for five years and we are currently waiting to hear from the New Jersey BPU Rate Counsel.BPU. If approved, the program is expected to be completed in 2017. A ruling is expected in the second half of 2013. |
Nicor Gas In July 2013, Illinois enacted legislation that provides for infrastructure investment by natural gas utilities serving more than 700,000 customers, Nicor Gas meets these criteria. This bill will allow Nicor Gas to provide more widespread safety and reliability enhancements to its pipelines in a timelier manner than under traditional utility regulation, and pass along lower program costs to our customers. We expect to submit a plan for approval by the Illinois Commission in mid-2014 and begin work in 2015.
Atlanta Gas Light Our STRIDE program is comprised of the ongoing pipeline replacement program, the Integrated System Reinforcement Program (i-SRP), and the Integrated Customer Growth Program (i-CGP). The purpose of the i-SRP is to upgrade our distribution system and liquefied natural gas facilities in Georgia, improve our peak day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Our i-CGP authorizes Atlanta Gas Light to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. The STRIDE program requires us to file an updated ten-year forecast of infrastructure requirements under i-SRP along with a new construction plan every three years for review and approval by the Georgia Commission. These programs remain on track for completion in 2013. The deadline for filing our next STRIDE construction plan was extended by the Georgia Commission to August 2013 to allow additional time to complete the installation of the initial i-SRP construction program. These programs remain on track for completion in 2013.
We expect to file a new $259 million STRIDE program in August 2013, $214 million of which will be for i-SRP related projects and $45 million of which will be for i-CGP related projects. Atlanta Gas Light expects hearings and a decision on the new STRIDE program in the fourth quarter of 2013.
OnIn November 21, 2012, we filed the Integrated Vintage Plastic Replacement Program (i-VPR) with the Georgia Commission, as a new component of STRIDE. If approved, this program would replace aging plastic pipe that was installed primarily in the mid-1960’s to the early 1980’s. We have identified approximately 3,300 miles of vintage plastic mains in our system that potentially should be considered for expedited replacement over the next 15 - 20 years as it reaches the end of its useful life. However, the initial request to the Georgia Commission is to replace approximately 756 miles over the next three to four years. The estimated cost of the first tranche of pipe to be replaced under construction activity under i-VPR is $275 million. In July 2013, Atlanta Gas Light and the staff of the Georgia Commission filed a joint stipulation adopting the replacement of the 756 miles over four years at an estimated cost of $275 million. Additional reporting requirements and monitoring by the Georgia Commission Staff were also included in the stipulation. Based on the procedural schedule issued by the Georgia Commission, hearings were held in July2013, and a decision on the program is expected to be made on June 18,during the third quarter of 2013.
Elizabethtown Gas The New Jersey BPU approved the accelerated enhanced infrastructure program in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. OnIn May 16, 2011, the New Jersey BPU approved Elizabethtown Gas’ request to spend an additional $40 million under this program before the end of 2012. Costs associated with the investment in this program are recovered through periodic adjustments to base rates. In July 2012, we filed for an extension of the program for up to $135 million in additional spend over five years.years. A ruling is expected from the New Jersey BPU in the second half of 2013.
Virginia Natural Gas OnIn January 31, 2012, Virginia Natural Gas filed SAVE, an accelerated infrastructure replacement program, with the Virginia Commission, which involves replacing aging infrastructure as prioritized through Virginia Natural Gas’ distribution integrity management program. SAVE was filed in accordance with a Virginia statute providing a regulatory cost recovery mechanism to recover the costs associated with certain infrastructure replacement programs. The Virginia Commission approved SAVE onin June 25, 2012, for a five-year period, which includes a maximum allowance for capital expenditure of $25 million per year, not to exceed $105 million in total. SAVE is subject to annual review by the Virginia Commission. We began recovering costs based on this program through a rate rider that became effective August 1, 2012. In May 2013, we filed our annual SAVE rate update detailing the first year performance and our expected future budget, which is subject to review and approval by the Virginia Commission. Approval of the rate update by the Virginia Commission is expected in August 2013.
Credit Ratings Our borrowing costs and our ability to obtain adequate and cost effective financing are directly impacted by our credit ratings, as well as the availability of financial markets. Credit ratings are important to our counterparties when we engage in certain transactions, including OTC derivatives. It is our long-term objective to maintain or improve our credit ratings in order to manage our existing financing costs and enhance our ability to raise additional capital on favorable terms.
Credit ratings and outlooks are opinions subject to ongoing review by the rating agencies and may periodically change. The rating agencies regularly review our performance, prospects and financial condition and reevaluate their ratings of our long-term debt and short-term borrowings, our corporate ratings and our ratings outlook. There is no guarantee 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. A credit rating is not a recommendation to buy, sell or hold securities and each rating should be evaluated independently of other ratings.
Factors we consider important to assessing our credit ratings include our Consolidated Statements of Financial Position leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any triggering 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 March 31,June 30, 2013, and reflects no change from December 31, 2012.
| | AGL Resources | | | Nicor Gas | |
| | S&P | | | Moody’s | | | Fitch | | | S&P | | | Moody’s | | | Fitch | |
Corporate rating | | BBB+ | | | | n/a | | | BBB+ | | | BBB+ | | | | n/a | | | | A | |
Commercial paper | | | A-2 | | | | P-2 | | | | F2 | | | | A-2 | | | | P-2 | | | | F1 | |
Senior unsecured | | BBB+ | | | Baa1 | | | BBB+ | | | BBB+ | | | | A3 | | | | A+ | |
Senior secured | | | n/a | | | | n/a | | | | n/a | | | | A | | | | A1 | | | AA- | |
Ratings outlook | | Stable | | | Stable | | | Stable | | | Stable | | | Stable | | | Stable | |
Our credit ratings depend largely on our financial performance, and a downgrade in our current ratings, particularly below investment grade, would increase our borrowing costs and could limit our access to the commercial paper market. 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 could decrease.
Default Provisions Our debt instruments and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. Our credit facilities contain customary events of default, including, but not limited to, the failure to pay any interest or principal when due, the failure to furnish financial statements within the timeframe established by each debt facility, the failure to comply with certain affirmative and negative covenants, cross-defaults to certain other material indebtedness in excess of specified amounts, incorrect or misleading representations or warranties, insolvency or bankruptcy, fundamentaland a change of control, the occurrence of certain Employee Retirement Income Security Act events, judgments in excess of specified amounts and certain impairments to the guarantee.control.
Our credit facilities contain certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations, and other matters customarily restricted in such agreements.
Our credit facilities each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month. This ratio,However, our goal, subject to extraordinary events such as acquisitions, is to maintain these ratios at levels between 50% and 60%. These ratios, as defined within our debt agreements, includesinclude standby letters of credit, performance/surety bonds and excludesexclude accumulated OCI items related to non-cash pension adjustments, other post-retirement benefits liability adjustments and accounting adjustments for cash flow hedges. Adjusting for these items, the following table contains our debt-to-capitalization ratios for the periodsdates presented,. which are below the maximum allowed.
| | AGL Resources | | | Nicor Gas | |
| | March 31, | | | March 31, | |
| | 2013 | | | 2012 | | | 2013 | | | 2012 | |
Debt-to-capitalization ratio | | | 54 | % | | | 54 | % | | | 43 | % | | | 47 | % |
| | June 30, 2013 | | | December 31, 2012 | | | June 30, 2012 | |
AGL Credit Facility | | | 54 | % | | | 58 | % | | | 54 | % |
Nicor Gas Credit Facility | | | 43 | | | | 55 | | | | 43 | |
We were in compliance with all of our debt provisions and covenants, both financial and non-financial, for all periods presented.
Our ratio of total debt to total capitalization, on a consolidated basis, is typically greater at the beginning of the Heating Season, as we make additional short-term borrowings to fund our natural gas purchases and meet our working capital requirements. We intendattempt to maintain our ratio of total debt to total capitalization in a target range of 50% to 60%. Accomplishing this capital structure objective and maintaining sufficient cash flow are necessary to maintain attractive credit ratings. For more information on our default provisions, see Note 6 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein. The components of our capital structure, as calculated from our unaudited Condensed Consolidated Statements of Financial Position, as of the dates indicated are provided in the following table.
| | March 31, 2013 | | | December 31, 2012 | | | March 31, 2012 | | | June 30, 2013 | | | December 31, 2012 | | | June 30, 2012 | |
Short-term debt | | | 11 | % | | | 16 | % | | | 10 | % | | | 7 | % | | | 16 | % | | | 10 | % |
Long-term debt | | | 45 | | | | 43 | | | | 46 | | | | 48 | | | | 43 | | | | 46 | |
Total debt | | | 56 | | | | 59 | | | | 56 | | | | 55 | | | | 59 | | | | 56 | |
Equity | | | 44 | | | | 41 | | | | 44 | | | | 45 | | | | 41 | | | | 44 | |
Total capitalization | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % |
Cash Flows The following table provides a summary of our operating, investing and financing cash flows for the periods presented.
| | Three months ended March 31, | | | Six months ended June 30, | |
In millions | | 2013 | | | 2012 | | | Variance | | | 2013 | | | 2012 | | | Variance | |
Net cash provided by (used in): | Net cash provided by (used in): | | | | | Net cash provided by (used in): | | | | |
Operating activities | | $ | 850 | | | $ | 835 | | | $ | 15 | | | $ | 1,161 | | | $ | 1,090 | | | $ | 71 | |
Investing activities | | | (256 | ) | | | (175 | ) | | | (81 | ) | | | (413 | ) | | | (358 | ) | | | (55 | ) |
Financing activities | | | (576 | ) | | | (658 | ) | | | 82 | | | | (695 | ) | | | (714 | ) | | | 19 | |
Net increase in cash and cash equivalents | | | 18 | | | | 2 | | | | 16 | | | | 53 | | | | 18 | | | | 35 | |
Cash and cash equivalent at beginning of period | | | 131 | | | | 69 | | | | 62 | | |
Cash and cash equivalent at end of period | | $ | 149 | | | $ | 71 | | | $ | 78 | | |
Cash and cash equivalents at beginning of period | | | | 131 | | | | 69 | | | | 62 | |
Cash and cash equivalents at end of period | | | $ | 184 | | | $ | 87 | | | $ | 97 | |
Cash Flow from Operating Activities The $15$71 million increase in cash from operating activities isfor the six months ended June 30, 2013 compared to the same period in 2012 was primarily related to increased cash provided by (i) inventories, net of LIFO liquidation, due to increased LIFO liquidation at Nicor gas and increased withdrawals at Sequent, (ii) trade payables, other than energy marketing due to increased gas purchase volumes at Nicor Gas resulting from colder weather in March and (iii) energy marketing receivables and payables, net, due to higher cash received in the current period related to higher sales volumes at higher prices in December 2012 versus the same period last year.in 2011, (ii) prepaid taxes, due to decreased prepaid positions for federal and state income taxes, and (iii) inventories, net of LIFO liquidation, due to increased LIFO liquidation at Nicor Gas and increased withdrawals at Sequent. This increase in cash provided by operating activities was partially offset by decreased cash provided by receivables, other than energy marketing, due to colder weather in March 2013, which resulted in higher volumes primarily at distribution operations and retail operations whichthat will be collected in future periods.
Cash Flow from Investing Activities The $81$55 million or 46%, increase in cash flow used in investing activities was a result of $122 million spent to acquire approximately 500,000 service plans during the first quarter of 2013. This increase was partially offset by decreased spending for property, plant and equipment expenditures of $23$32 million, and a net increase in short term investments of $19 million.$15 million and $12 million from the sale of Compass Energy.
Cash Flow from Financing Activities The decreased use of cash for our financing activities for the threesix months ended March 31,June 30, 2013 compared to the same period in 2012 was primarily athe result of lowerour May 2013 issuance of senior notes, partially offset by higher short-term debt payments of $82$267 million due to funding requirements in Januaryand our April 2013 related to the NiSource acquisition.payment of senior notes.
As of March 31,June 30, 2013, our variable-rate debt was 25%17% of our total debt, compared to 32%, as of December 31, 2012 and 26%27% as of March 31,June 30, 2012. The decrease from December 31, 2012 was primarily due to decreased commercial paper borrowings. As of March 31,June 30, 2013, our commercial paper borrowings of $868$521 million were 37%62% lower than as of December 31, 2012, primarily a result of lower working capital requirementsour repayment of a portion of AGL Capital’s commercial paper borrowings and no commercial paper borrowings under the Nicor Gas Credit Facility. For more information on our debt, see Note 6 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein.
OnIn April 15, 2013, our $225 million 4.45% senior notes were redeemed. This redemptionmatured. Repayment of these senior notes was funded through our commercial paper program and will be refinanced as partprogram. In May 2013, we issued $500 million in 30-year senior notes. The net proceeds of $494 million were used to repay a portion of AGL Capital’s commercial paper, including $225 million we borrowed to repay our anticipated issuance of senior notes during the second quarterthat matured in April 2013.
Short-term Debt Our short-term debt is comprised ofcomprises borrowings under our commercial paper programs and current portions of our senior notes and capital leases. The following table provides additional information on our short-term debt.
In millions | | Period end balance outstanding (1) | | | Daily average balance outstanding (2) | | | Minimum balance outstanding (2) | | | Largest balance outstanding (2) | | | Period end balance outstanding (1) | | | Daily average balance outstanding (2) | | | Minimum balance outstanding (2) | | | Largest balance outstanding (2) | |
Commercial paper - AGL Capital | | $ | 868 | | | $ | 980 | | | $ | 846 | | | $ | 1,064 | | | $ | 521 | | | $ | 838 | | | $ | 380 | | | $ | 1,064 | |
Commercial paper - Nicor Gas | | | - | | | | 148 | | | | - | | | | 314 | | | | - | | | | 74 | | | | - | | | | 314 | |
Senior notes | | | 225 | | | | 225 | | | | 225 | | | | 225 | | | | - | | | | 129 | | | | - | | | | 225 | |
Capital leases | | | 1 | | | | 1 | | | | 1 | | | | 1 | | | | - | | | | 1 | | | | - | | | | 1 | |
Total short-term debt and current portion of long-term debt and capital leases | | $ | 1,094 | | | $ | 1,354 | | | $ | 1,072 | | | $ | 1,604 | | |
Total short-term debt and current portions of long-term debt and capital leases | | | $ | 521 | | | $ | 1,042 | | | $ | 380 | | | $ | 1,604 | |
(1) | As of March 31,June 30, 2013. |
(2) | For the threesix months ended March 31,June 30, 2013. The minimum and largest balances outstanding for each short-term debt instrument occurred at different times during the period and, thus,period. Consequently, the total balances are not indicative of actual borrowings on any one day during the quarterperiod. |
The largest, minimum and daily average balances borrowed under our commercial paper programs are important when assessing the intra-period fluctuations of our short-term borrowings and potential liquidity risk. The fluctuations are due to our seasonal cash requirements.requirements to fund working capital needs, in particular the purchase of natural gas inventory.
Increasing natural gas commodity prices can have a significant impact on our commercial paper borrowings. Based on current natural gas prices and our expected injection plan, a $1 increase NYMEX price change could result in a $145$104 million change of working capital requirements during the injection season. This range is sensitive to the timing of storage injections and withdrawals, collateral requirements and our portfolio position. Based on current natural gas prices and our expected purchases during the upcoming injection season, we believe that we have sufficient liquidity to cover our working capital needs for the upcoming Heating Season.
The lenders under our credit facilities and lines of credit are major financial institutions with $2.2 billion of committed balances and all havehad investment grade credit ratings as of March 31,June 30, 2013. 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.
Long-term Debt Our long-term debt matures more than one year from March 31,June 30, 2013, and consists of medium-term notes: Series A, Series B, and Series C, which we issued under an indenture during December 1989,1989; senior notes,notes; first mortgage bondsbonds; and gas facility revenue bonds.
During the first quarter of 2013, we refinanced $200 million of our outstanding tax-exempt gas facility revenue bonds, $180 million of which were previously issued by the New Jersey Economic Development Authority and $20 million of which were previously issued by Brevard County, Florida. The refinancing involved a combination of the issuance of $60 million of refunding bonds to and the purchase of $140 million of existing bonds by a syndicate of banks. Our relationship with the syndicate of banks regarding the bonds is governed by an agreement that contains representations, warranties, covenants and default provisions consistent with those contained in similar financing documents of ours. All of the bonds remain floating-rate instruments and we anticipate annual interest expense savings of approximately $2 million annually over the 5.5 year term of the agreement. AGL Resources had no cash receipts or payments in connection with the refinancing. The letters of credit providing credit support for the retired bonds along with other related agreements were terminated as a result of the refinancing. Costs associated with these refinancings will be amortized over the remaining life of the bonds.
Noncontrolling Interest We recorded cash distributions for SouthStar’s dividend distributions to Piedmont of $17 million for the threesix months ended March 31,June 30, 2013 and $14 million for the same period in 2012. The primary reason for the increase in the distribution to Piedmont during the current year is due towas increased earnings for 2012 compared to 2011.
Dividends on Common Stock Our common stock dividend payments were $55$111 million for the threesix months ended March 31,June 30, 2013 and $42$96 million for the same period in 2012. The increase is primarily due to the $0.10 stub period dividend paid in December 2011, which reduced the dividend paid in the first quarter of 2012 by the same amount and the annual dividend increase of $0.04 per share.
Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of business that are reasonably likely to have a material effect on liquidity or the availability of requirements for 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. 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.
Other than the changes in our debt, see Note 6 to our unaudited Condensed Consolidated Financial Statements under Part I, Item 1 herein, there were no significant changes to our contractual obligations described in Note 11 ofto our Consolidated Financial Statements and related notes as filed in Item 8 of our 2012 Form 10-K.
Pension and retiree welfare plan obligations AsPrimarily as a result of merging theour pension plans there werein December 2012, no contributions were required during the six months ended June 30, 2013. During the first quarterhalf of 2013. In 2012, we contributed $17$24 million to thesecertain of our qualified pension plans and an additional $7$8 million in AprilJuly 2012 for a total of $24$32 million through April ofJuly 2012. Based on the current funding status of these plans,our merged pension plan, we do not believe that weadditional contributions to the pension plan will be required to make a minimum contribution to the plans during 2013. We may make additional contributions in 2013 in order to preserve the current level of benefits under these plans and in accordance with the funding requirements of the Pension Protection Act.
During the threesix months ended March 31,June 30, 2013, we recorded net periodic benefit costs of $14$28 million related to our defined benefit plans compared to $16$31 million during the same period last year. During the firstsecond quarter of 2013, we received an updated estimatea final computation of the 2013 expense that indicated a rangereflects January 1, 2013 census data. The final annual expense is expected to be $57 million, before capitalization, for 2013 compared to actual expense of $55$61 million to $60 million. As such, wefor 2012. We estimate that during the remainder of 2013 we will record net periodic benefit costs in the range of $41 million to $46 million, as compared to actual 2012 expense of $61$29 million. We expect a revised estimate by the end of the second quarter of 2013, which we do not anticipate will be materially different than our current estimate.
The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts in our unaudited Condensed Consolidated Financial Statements and accompanying notes. Those judgments and estimates have a significant effect on our financial statements primarily due to the need to make estimates about the effects of matters that are inherently uncertain. Actual results could differ from those estimates. We frequently reevaluate our judgments and estimates that are based upon historical experience and various other assumptions that we believe to be reasonable under the circumstances.
Each of our critical accounting 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 estimates from those disclosed in our Management’s Discussion and Analysis of Financial Condition and Results of Operations as filed on our 2012 Form 10-K. Our critical accounting estimates used in the preparation of our unaudited Condensed Consolidated Financial Statements include the following:
· Regulatory Infrastructure Program Liabilities
·Environmental Remediation Liabilities
· Derivatives and Hedging Activities
· Goodwill and Intangible Assets
· Contingencies
· Pension and Retiree Welfare Plans
· Income Taxes
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are exposed to risks associated with natural gas prices, interest rates, credit and fuel prices. 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 fuel price risk is primarily in cargo shipping, which is partially reduced through fuel surcharges. Our use of derivative instruments is governed by a risk management policy, approved and monitored by our Risk Management Committee (RMC).
Our 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 treatment for our derivative instruments are described in further detail in Note 4 of our unaudited Condensed Consolidated Financial Statements.
Natural Gas Price Risk
The following tables include the fair values and average values of our consolidated derivative instruments as of the dates indicated. We base the average values on monthly averages for the threesix months ended March 31,June 30, 2013 and 2012.
| | Derivative instruments average values (1) at March 31, | | | Derivative instruments average values at June 30, (1) | |
In millions | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
Asset | | $ | 114 | | | $ | 279 | | | $ | 107 | | | $ | 257 | |
Liability | | | 29 | | | | 117 | | | | 36 | | | | 116 | |
(1) Excludes cash collateral amounts.
| | Derivative instruments fair values netted with cash collateral at | | | Derivative instruments fair values netted with cash collateral at | |
In millions | | March 31, 2013 | | | December 31, 2012 | | | March 31, 2012 | | | June 30, 2013 | | | December 31, 2012 | | | June 30, 2012 | |
Asset | | $ | 111 | | | $ | 144 | | | $ | 266 | | | $ | 130 | | | $ | 144 | | | $ | 226 | |
Liability | | | 24 | | | | 39 | | | | 103 | | | | 39 | | | | 39 | | | | 66 | |
The following table illustrates the change in the net fair value of our derivative instruments during the periods presented, and provides details of the net fair value of contracts outstanding as of the dates presented.
| | Three months ended | | |
| | March 31, | | | Three months ended June 30, | | | Six months ended June 30, | |
In millions | | 2013 | | | 2012 | | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
Net fair value of derivative instruments outstanding at beginning of period | | $ | 36 | | | $ | 31 | | | $ | 10 | | | $ | (46 | ) | | $ | 36 | | | $ | 30 | |
Derivative instruments realized or otherwise settled during period | | | (43 | ) | | | (82 | ) | | | (15 | ) | | | 46 | | | | (46 | ) | | | (18 | ) |
Net fair value of derivative instruments acquired during period | | | | - | | | | - | | | | - | | | | 3 | |
Change in net fair value of derivative instruments | | | 17 | | | | 5 | | | | 2 | | | | 23 | | | | 7 | | | | 8 | |
Net fair value of derivative instruments outstanding at end of period | | | 10 | | | | (46 | ) | | | (3 | ) | | | 23 | | | | (3 | ) | | | 23 | |
Netting of cash collateral | | | 77 | | | | 209 | | | | 94 | | | | 137 | | | | 94 | | | | 137 | |
Cash collateral and net fair value of derivative instruments outstanding at end of period | | $ | 87 | | | $ | 163 | | | $ | 91 | | | $ | 160 | | | $ | 91 | | | $ | 160 | |
The sources of our net fair value at March 31,June 30, 2013, are as follows.
In millions | | Prices actively quoted (Level 1) (1) | | | Significant other observable inputs (Level 2) (2) | | | Prices actively quoted (Level 1) (1) | | | Significant other observable inputs (Level 2) (2) | |
Mature through 2013 | | $ | (15 | ) | | $ | 29 | | | $ | 3 | | | $ | 17 | |
Mature 2014 - 2015 | | | (5 | ) | | | 1 | | | | (46 | ) | | | 24 | |
Mature 2016 - 2017 | | | (2 | ) | | | 2 | | | | (3 | ) | | | 2 | |
Total derivative instruments (3) | | $ | (22 | ) | | $ | 32 | | | $ | (46 | ) | | $ | 43 | |
(1) Valued using NYMEX futures prices.
(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-riskValue at risk Value at risk is 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. Our 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 we generally manage physical gas assets and economically protect our positions by hedging in the futures markets, our open exposure is generally immaterial, permitting us to operate within relatively low VaR limits. We employ daily risk testing, using both VaR and stress testing, to evaluate the risks of our open positions. Our VaR is determined on a 95% confidence interval and a 1-day holding period. In simple terms, this means that 95% of the time, the risk of loss from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated.
We actively monitor open commodity positions and the resulting VaR. We also continue to maintain a relatively matched book, where our total buy volume is close to our 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, our portfolio positions for the periods presented had the following VaRs.
| | Three months ended March 31, | | | Three months ended June 30, | | | Six months ended June 30, | |
In millions | | 2013 | | | 2012 | | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
Period end | | $ | 1.7 | | | $ | 2.2 | | | $ | 1.7 | | | $ | 1.9 | | | $ | 1.7 | | | $ | 1.9 | |
Average | | | 1.9 | | | | 2.5 | | | | 1.8 | | | | 2.4 | | | | 1.8 | | | | 2.5 | |
High | | | 2.6 | | | | 4.8 | | | | 2.2 | | | | 3.6 | | | | 2.6 | | | | 4.8 | |
Low | | | 1.6 | | | | 1.9 | | | | 1.2 | | | | 1.7 | | | | 1.2 | | | | 1.7 | |
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 $1.1$0.7 billion of variable-rate debt outstanding at March 31,June 30, 2013, a 100 basis point change in market interest rates would have resulted in an increase in pre-tax interest expense of $11$7 million on an annualized basis.
We have $300 million of 6.4% senior notes due in July 2016. In May 2011, we entered into interest rate swaps related to these senior notes to effectively convert $250 million from a fixed-rate to a variable-rate obligation. On September 6, 2012, we settled this $250 million interest rate swap, which resulted in our receipt of a $17 million cash payment.
We use interest rate swaps to help us achieve our desired mix of variable to fixed-rate debt. Our variable-rate debt target generally ranges from 20% to 45% of total debt. We also may use forward-starting interest rate swaps and interest rate lock agreements to lock in fixed interest rates on our forecasted issuances of debt. The objective of these hedges is to offset the variability of future payments associated with the interest rate on debt instruments we expect to issue.
We anticipate issuing approximatelyhave $300 million of 6.4% senior notes due in July 2016. In May 2011, we entered into interest rate swaps related to these senior notes to effectively convert $250 million from a fixed-rate to a variable-rate obligation. On September 6, 2012, we settled this $250 million interest rate swap, which resulted in our receipt of a $17 million cash payment.
On May 16, 2013, we issued $500 million of 30-year senior notes in the second quarterwith an interest rate of 2013. As of April 30, 2013, we4.4%. We had entered into $300 million, in notional amount, of fixed-rate forward-starting interest rate swaps to hedge anythe first ten years of potential interest rate volatility prior to this anticipated issuance. The weighted average interest rate of these swaps iswas a 10-year United States Treasury rate of 1.85%. The remaining un-hedged principal amountOn May 16, 2013, we settled these swaps, which resulted in our receipt of the planned debt issuance currently remains subject to the risk of increases in near-term interest rates. We have designated the forward-starting interest rate swaps asa $6 million cash flow hedges, which will mature on the debt issuance date.payment.
The gain or loss on the interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which point it is amortized to interest expense over the lifeperiod of the related debt.hedged interest payments. For additional information, see Note 4 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein.
Credit Risk
Wholesale Services We have established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. We also utilize master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When we are engaged in more than one outstanding derivative transaction with the same counterparty and we also have 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 our credit risk. We also use other netting agreements with certain counterparties with whom we conduct significant transactions. Master netting agreements enable us to net certain assets and liabilities by counterparty. We also net across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions.
Additionally, we may require counterparties to pledge additional collateral when deemed necessary. We conduct credit evaluations and obtain appropriate internal approvals for each 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, we require credit enhancements by way of guaranty, cash deposit or letter of credit for transaction counterparties that do not have investment grade ratings.
We have a concentration of credit risk as measured by our 30-day receivable exposure plus forward exposure. As of March 31,June 30, 2013, our top 20 counterparties represented approximately 49%55% of the total counterparty exposure of $370$377 million, derived by adding together the top 20 counterparties’ exposures, exclusive of customer deposits, and dividing by the total of our counterparties’ exposures.
As of March 31,June 30, 2013, our counterparties, or the counterparties’ guarantors, had a weighted average S&P equivalent credit rating of A-, which is an improvement from the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody’s and 1 being D or Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios of that counterparty. To arrive at the weighted average credit rating, each counterparty is assigned an internal ratio, which ismultiplied 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. The following table shows our third-party natural gas contracts receivable and payable positions.
| | Gross receivables | | | Gross payables | |
| | March 31, | | | December 31, | | | March 31, | | | March 31, | | | December 31, | | | March 31, | |
In millions | | 2013 | | | 2012 | | | 2012 | | | 2013 | | | 2012 | | | 2012 | |
Netting agreements in place: | | | | | | | | | | | | | | | | | | |
Counterparty is investment grade | | $ | 286 | | | $ | 485 | | | $ | 252 | | | $ | 198 | | | $ | 282 | | | $ | 192 | |
Counterparty is non-investment grade | | | 4 | | | | 9 | | | | 11 | | | | 13 | | | | 13 | | | | 20 | |
Counterparty has no external rating | | | 319 | | | | 175 | | | | 121 | | | | 431 | | | | 315 | | | | 212 | |
No netting agreements in place: | | | | | | | | | | | | | | | | | | | | | | | | |
Counterparty is investment grade | | | 12 | | | | 7 | | | | 2 | | | | 10 | | | | 1 | | | | 1 | |
Counterparty has no external rating | | | 6 | | | | 1 | | | | - | | | | 1 | | | | - | | | | - | |
Amount recorded on unaudited Condensed Consolidated Statements of Financial Position | | $ | 627 | | | $ | 677 | | | $ | 386 | | | $ | 653 | | | $ | 611 | | | $ | 425 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
46
| | Gross receivables | | | Gross payables | |
In millions | | | | | | | | | | | | | | | | | | |
Netting agreements in place: | | | | | | | | | | | | | | | | | | |
Counterparty is investment grade | | $ | 206 | | | $ | 485 | | | $ | 266 | | | $ | 107 | | | $ | 282 | | | $ | 186 | |
Counterparty is non-investment grade | | | 1 | | | | 9 | | | | 9 | | | | 7 | | | | 13 | | | | 11 | |
Counterparty has no external rating | | | 396 | | | | 175 | | | | 70 | | | | 514 | | | | 315 | | | | 185 | |
No netting agreements in place: | | | | | | | | | | | | | | | | | | | | | | | | |
Counterparty is investment grade | | | 5 | | | | 7 | | | | 2 | | | | - | | | | 1 | | | | 1 | |
Counterparty has no external rating | | | - | | | | 1 | | | | - | | | | - | | | | - | | | | - | |
Amount recorded on unaudited Condensed Consolidated Statements of Financial Position | | $ | 608 | | | $ | 677 | | | $ | 347 | | | $ | 628 | | | $ | 611 | | | $ | 383 | |
We have 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, we would need to post collateral to continue transacting business with some of our counterparties. If such collateral were not posted, our 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 with our counterparties would have totaled $13$16 million at March 31,June 30, 2013, which would not have a material impact toon our consolidated results of operations, cash flows or financial condition.
There have been no other significant changes to our credit risk related to any of our segments other segments,than wholesale services, as described in Item 7A ”Quantitative and Qualitative Disclosures about Market Risk” of our 2012 Form 10-K.
Cargo Shipping Tropical Shipping’s objective is to reduce its exposure to higher fuel costs through fuel surcharges. However, these fuel surcharges do not entirely remove our entire risk in periods of increasing fuel prices and volatility, or increased competition.competition, and any relief may not be realized in the same period as the cost incurred. An increase of 10% in Tropical Shipping’s average cost per gallon for vessel fuel results in approximately $6 million in additional annual fuel expense. The aforementioned fuelFuel surcharges would be implemented to reduce the impact of the increased fuel expense.
(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 under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of March 31,June 30, 2013, 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 March 31,June 30, 2013, 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 that occurred during the firstsecond quarter ended March 31,June 30, 2013, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities. In addition, we are party, as both plaintiff and defendant, to a number of lawsuits related to our business on an ongoing basis. Management believes that the outcome of all regulatory proceedings and litigation in which we are currently involved will not have a material adverse effect on our consolidated financial condition. For moreinformation regarding some of these proceedings, see Note 9 to our unaudited Condensed Consolidated Financial Statements under the caption “Litigation.”
For information regarding our risk factors, see the factors discussed in Part I, "Item 1A. Risk Factors" in our 2012 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2012 Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterialdo not recognize as material also may materially adversely affect our business, financial condition or future results. The following risk factor has changed since filing our 2012 Form 10-K.
We may be exposed to certain regulatory and financial risks related to climate change and associated legislation and regulation.
Climate change is expected to receive increasing attention from the current federal administration, non-governmental organizations, and legislators. Debate continues as to the extent to which our climate is changing, the potential causes of any change, and its potential impacts. Some attribute global warming to increased levels of greenhouse gases, including carbon dioxide, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.
Presently, there are no federally mandated greenhouse gas reduction requirements that directly affect our operations. However, the United States Environmental Protection Agency (EPA) has begun using provisions of the Clean Air Act to regulate greenhouse gas emissions, including carbon dioxide. Thus far, EPA has imposed greenhouse gas regulations on automobiles and implemented new permitting requirements for the construction or modification of major stationary sources of greenhouse gas emissions, including natural gas-fired power plants.
In addition, President Obama issued a Presidential Memorandum on June 25, 2013, directing EPA to adopt performance standards to regulate greenhouse gas emissions from power plants. Specifically, the Presidential Memorandum directs EPA to propose standards for future power plants by September 20, 2013 (to replace a proposal EPA published in April 2012), and propose emission guidelines for modified, reconstructed, and existing power plants by June 1, 2014. The Presidential Memorandum directs EPA to finalize those regulations by June 1, 2015. It also includes a wide variety of other initiatives designed to reduce greenhouse gas emissions, prepare for the impacts of climate change, and lead international efforts to address climate change.
The outcome of federal and state actions to address climate change could potentially result in new regulations, additional charges to fund energy efficiency activities, or other regulatory actions, which in turn could:
· | result in increased costs associated with our operations, |
· | increase other costs to our business, |
· | affect the demand for natural gas (positively or negatively), and |
· | impact the prices we charge our customers. |
Because natural gas is a fossil fuel with low carbon content, it is likely that future carbon constraints will create additional demand for natural gas, both for production of electricity and direct use in homes and businesses. The impact is already being seen in the power production sector due to both environmental regulations and low natural gas costs.
Any adoption by federal or state governments mandating a substantial reduction in greenhouse gas emissions could have far-reaching and significant impacts on the energy industry. We cannot predict the potential impact of such laws or regulations on our future consolidated financial condition, results of operations, or cash flows.
There were no purchases of our common stock by us or any affiliated purchasers during the firstsecond quarter of 2013 and no unregistered sales of equity securities were made during this period.
10.1 | Bank Rate Mode Covenants Agreement, dated as | |
| 4.1a | | Form of February 26, 2013, among AGL Resources Inc., Pivotal Utility Holdings, Inc., the several purchasers from time to time parties thereto and SunTrust Bank, as administrative agentCapital Corporation 4.40% Senior Notes due 2043 (Exhibit 10.1,4.2, AGL Resources Inc. Form 8-K filed March 1,May 16, 2013). |
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10.2 | Loan Agreement,4.1b
| | Guarantee of AGL Resources Inc. dated as of February 1,May 16, 2013 between Brevard County, Florida and Pivotal Utility Holdings, Inc. (Exhibit 10.2,regarding the AGL Capital Corporation 4.40% Senior Notes due 2043 (Exhibit 4.3, AGL Resources Inc. Form 8-K filed March 1, 2013). |
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10.3 | Loan Agreement, dated as of March 1, 2013, between New Jersey Economic Development Board and Pivotal Utility Holdings, Inc., relating to $40 million New Jersey Economic Development Authority Gas Facilities Refunding Revenue Bonds (Pivotal Utilities Holdings, Inc. Project), Series 2013 (Exhibit 10.1, AGL Resources Inc. Form 8-K filed March 27,May 16, 2013). |
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10.4 | Amended and Restated Loan Agreement, dated as of March 1, 2013, between Brevard County, Florida and Pivotal Utility Holdings, Inc., relating to $39 million New Jersey Economic Development Authority Gas Facilities Refunding Revenue Bonds (NUI Corporation Project), 1996 Series A (Exhibit 10.2, AGL Resources Inc. Form 8-K filed March 27, 2013). |
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10.5 | Amended and Restated Loan Agreement, dated as of March 1, 2013, between Brevard County, Florida and Pivotal Utility Holdings, Inc., relating to $46.5 million New Jersey Economic Development Authority Gas Facilities Refunding Revenue Bonds (Pivotal Utility Holdings, Inc. Project), Series 2005 (Exhibit 10.3, AGL Resources Inc. Form 8-K filed March 27, 2013). |
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10.6 | Amended and Restated Loan Agreement, dated as of March 1, 2013, between Brevard County, Florida and Pivotal Utility Holdings, Inc., relating to $54.6 million New Jersey Economic Development Authority Gas Facilities Refunding revenue Bonds (Pivotal Utility Holdings, Inc. Project), Series 2007 (Exhibit 10.4, AGL Resources Inc. Form 8-K filed March 27, 2013). |
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12 | Statement of Computation of Ratio of Earnings to Fixed Charges. |
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| 31.1 | | Certification of John W. Somerhalder II pursuant to Rule 13a - 14(a). |
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| 31.2 | | Certification of Andrew W. Evans pursuant to Rule 13a - 14(a). |
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| 32.1 | | Certification of John W. Somerhalder II pursuant to 18 U.S.C. Section 1350. |
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| 32.2 | | Certification of Andrew W. Evans pursuant to 18 U.S.C. Section 1350. |
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101.INS | | XBRL Instance Document. |
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101.SCH | | XBRL Taxonomy Extension Schema. |
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101.CAL | | XBRL Taxonomy Extension Calculation Linkbase. |
101.DEF | |
101.DEF | XBRL Taxonomy Definition Linkbase. |
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101.LAB | | XBRL Taxonomy Extension Labels Linkbase. |
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101.PRE | | XBRL Taxonomy Extension Presentation Linkbase. |
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: April 30,July 31, 2013 /s/ Andrew W. Evans
Executive Vice President and Chief Financial Officer