Use of Accounting Estimates
Our accounting policies are described in Note 2 to our Consolidated Financial Statements and related notes included in Item 8 of our 2010 Form 10-K. There were no significant changes to our accounting policies during the six months ended June 30, 2011.
The preparation of our financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience, where applicable, and various other assumptions that we believe to be reasonable under the circumstances. We evaluate our estimates and assumptions on an ongoing basis and make adjustments in subsequent periods to reflect more current information if we determine that updated assumptions and estimates are warranted. Our estimates may involve complex situations requiring a high degree of judgment either in the application and interpretation of existing financial accounting literature or in the development of estimates that impact our financial statements. The most significant estimates include our regulatory infrastructure program accruals, ERC liability accruals, allowance for uncollectible accounts, contingencies, pension and postretirement obligations, derivative and hedging activities and provision for income taxes. Our actual results could differ from those estimates and such differences could be material.
Fair Value Measurements
The carrying values of cash and cash equivalents, receivables, derivative financial assets and liabilities, accounts payable, other current assets and liabilities and accrued interest approximate fair value. There have been no significant changes to our fair value methodologies, as described in Note 2 to our Consolidated Financial Statements and related notes included in Item 8 of our 2010 Form 10-K.
As defined in the authoritative guidance related to fair value measurements and disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observance of those inputs. See Note 4 for additional fair value disclosure.
Energy Marketing Receivables and Payables
Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements, which enable wholesale services to net receivables and payables by counterparty. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. The amounts due from or owed to wholesale services’ counterparties are netted and recorded on our Condensed Consolidated Statements of Financial Position as energy marketing receivables and energy marketing payables.
Our wholesale services segment has some trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. No collateral has been posted under such provisions since our credit ratings have always exceeded the minimum requirements. As of June 30, 2011, December 31, 2010 and June 30, 2010, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. However, if such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.
Inventories
For our distribution operations segment, we record natural gas stored underground at the WACOG. For Sequent and SouthStar we account for natural gas inventory at the lower of WACOG or market price. SouthStar and Sequent evaluate the weighted-average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other-than-temporary. For any declines considered to be other-than-temporary, we record adjustments to reduce the weighted-average cost of the natural gas inventory to market price. SouthStar and Sequent recorded LOCOM adjustments for the periods presented as follows:
| |
|
Three months ended
June 30,
|
|
|
Six months ended
June 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
4 |
|
Regulatory Assets and Liabilities
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 would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future 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 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. Further, we are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and believe that we will be able to recover these costs, consistent with our historical recoveries.
As of June 30, 2011, there have been no new types of regulatory assets or liabilities from those discussed in Note 2 to our Consolidated Financial Statements and related notes in Item 8 of our 2010 Form 10-K.
Our regulatory assets and liabilities and the associated assets and liabilities are summarized in the following table.
| |
|
Jun. 30,
|
|
|
Dec. 31,
|
|
|
Jun. 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
|
Regulatory assets
|
|
|
|
|
|
|
|
|
|
Recoverable regulatory infrastructure program costs
|
|
$ |
328 |
|
|
$ |
292 |
|
|
$ |
303 |
|
|
|
|
|
222 |
|
|
|
171 |
|
|
|
164 |
|
Recoverable seasonal rates
|
|
|
0 |
|
|
|
11 |
|
|
|
0 |
|
Recoverable postretirement benefit costs
|
|
|
9 |
|
|
|
9 |
|
|
|
10 |
|
|
|
|
|
42 |
|
|
|
42 |
|
|
|
44 |
|
|
|
|
|
601 |
|
|
|
525 |
|
|
|
521 |
|
|
Associated assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
|
12 |
|
|
|
20 |
|
|
|
23 |
|
Total regulatory and associated assets
|
|
$ |
613 |
|
|
$ |
545 |
|
|
$ |
544 |
|
|
Regulatory liabilities
|
|
|
|
|
|
|
|
|
|
Accumulated removal costs
|
|
$ |
253 |
|
|
$ |
182 |
|
|
$ |
186 |
|
Derivative financial instruments
|
|
|
12 |
|
|
|
20 |
|
|
|
23 |
|
|
|
|
|
15 |
|
|
|
15 |
|
|
|
16 |
|
Unamortized investment tax credit
|
|
|
11 |
|
|
|
12 |
|
|
|
12 |
|
Deferred natural gas costs
|
|
|
49 |
|
|
|
23 |
|
|
|
31 |
|
|
|
|
|
8 |
|
|
|
0 |
|
|
|
9 |
|
|
|
|
|
26 |
|
|
|
24 |
|
|
|
20 |
|
Total regulatory liabilities
|
|
|
374 |
|
|
|
276 |
|
|
|
297 |
|
|
Associated liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory infrastructure program costs
|
|
|
258 |
|
|
|
228 |
|
|
|
242 |
|
|
|
|
|
180 |
|
|
|
132 |
|
|
|
128 |
|
Total associated liabilities
|
|
|
438 |
|
|
|
360 |
|
|
|
370 |
|
Total regulatory and associated liabilities
|
|
$ |
812 |
|
|
$ |
636 |
|
|
$ |
667 |
|
The increase in ERC costs is discussed further in Note 9. The increase in regulatory infrastructure program costs primarily relates to updated engineering estimates based on actual path and rights of way for pipeline added to the program in 2010.
Earnings per Common Share
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 issued under restricted stock or issuable under restricted stock units and stock options. The vesting of shares of the restricted stock and restricted stock units depends on the satisfaction of certain performance criteria. The future issuance of shares underlying the outstanding stock options depends upon whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. common shareholders for the periods presented, if performance units currently earned under our plans ultimately vest and stock options currently exercisable at prices below the average market prices are exercised:
| |
|
Three months ended
June 30,
|
|
|
Six months ended
June 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
Denominator for basic earnings per share (1)
|
|
|
77.9 |
|
|
|
77.4 |
|
|
|
77.8 |
|
|
|
77.3 |
|
Assumed exercise of restricted stock, restricted stock units and stock options
|
|
|
0.6 |
|
|
|
0.4 |
|
|
|
0.5 |
|
|
|
0.4 |
|
|
Denominator for diluted earnings per share
|
|
|
78.5 |
|
|
|
77.8 |
|
|
|
78.3 |
|
|
|
77.7 |
|
(1) Daily weighted-average shares outstanding.
The following table contains the weighted-average shares attributable to outstanding stock options that were excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. because their effect would have been anti-dilutive, as the exercise prices were greater than the average market price.
| |
|
June 30,
|
|
|
|
|
|
In millions
|
|
2011 (2)
|
|
|
2010
|
|
|
Change (1)
|
|
|
|
|
|
0.0 |
|
|
|
0.8 |
|
|
|
(0.8 |
) |
|
|
|
|
0.0 |
|
|
|
0.8 |
|
|
|
(0.8 |
) |
(1) The decrease was primarily a result of a higher average market value of our common shares compared to the same period during 2010.
(2) 0.0 values represent amounts less than 0.1 million.
On December 6, 2010, we entered into a Merger Agreement with Nicor, a copy of which was filed with the SEC on December 7, 2010. In accordance with the Merger Agreement, each share of Nicor common stock outstanding, other than shares to be cancelled and Dissenting Shares, as defined in the Merger Agreement, will be converted into the right to receive consideration of (i) 0.8382 of a share of our common stock and (ii) $21.20 in cash, subject to adjustments in certain circumstances to ensure that the transaction satisfies the “continuity of interest” requirement for a “reorganization” within Section 368(a) of the Internal Revenue Code. The Merger Agreement contains certain termination rights for both Nicor and us, and provides for the payment of fees and expenses upon the termination of the Merger Agreement under certain circumstances. Upon the closing of the proposed merger, it is anticipated that our shareholders will own approximately 67%, and Nicor shareholders will own approximately 33%, of the combined company.
In April 2011, we received antitrust clearance from the Department of Justice and the Federal Trade Commission under the Hart-Scott-Rodino Antitrust Improvement Act. Additionally, in April 2011, the SEC declared effective our registration statement on Form S-4 which registered our common stock to be issued in connection with the proposed merger. In June 2011, we and Nicor received shareholder approval of the proposed merger at our respective shareholder meetings. Completion of the proposed merger is conditioned upon, among other things, regulatory approval by the Illinois Commerce Commission.
In January 2011, we filed a joint application with Nicor to the Illinois Commerce Commission for approval of the proposed merger. The application did not request a rate increase, but included a commitment to maintain the number of full-time equivalent employees at Nicor’s natural gas utility for a period of three years following merger completion. The Illinois Commerce Commission has eleven months to act upon the application, with their deadline for action being December 16, 2011. During May 2011, we and Nicor submitted joint testimony to the Illinois Commerce Commission rebutting the initial testimony of the Staff of the Illinois Commerce Commission and several intervenors who recommended that the Illinois Commerce Commission deny the joint application or that it impose various requirements on the joint applicants as conditions of approval. Hearings on the matter were held in July 2011.
The proposed merger may also be subject to review by the governmental authorities of various other federal, state or local jurisdictions under the antitrust and utility regulation or other applicable laws of those jurisdictions. We have provided a voluntary notice of the merger to the New Jersey BPU and the Maryland Public Service Commission (Maryland Commission), which included a description of the transaction, described the benefits of the transaction and explained why we do not believe that the approval of the New Jersey BPU or Maryland Commission is required to complete the merger. It is possible that one or more state commissions will open proceedings to determine whether they have jurisdiction over the merger. In the event that any reviewing authorities are determined to have jurisdiction over the merger transaction, there can be no assurance that the reviewing authorities will approve the merger without restrictions or conditions (which are difficult to predict or quantify) that would have a material adverse effect on the combined company if the merger were completed.
We and Nicor currently anticipate receiving the required authorizations, approvals and consents to complete the proposed merger in the second half of 2011. However, there can be no assurance as to the timing of these authorizations, approvals and consents or as to our ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to us and Nicor. The Merger Agreement with Nicor contains termination rights for both us and Nicor and provides that, if we terminate the agreement under specified circumstances, we may be required to pay a termination fee of $67 million. In addition, if we terminate the agreement due to a failure to obtain the necessary financing for the transaction, we may also be required to pay Nicor $115 million.
During the three months ended June 30, 2011, we recorded approximately $13 million ($8 million net of tax) of transaction expenses associated with the proposed merger, while we recorded approximately $18 million ($11 million net of tax) of such expenses during the six months ended June 30, 2011. These costs are expensed as incurred. For additional information concerning the proposed merger please see our Form 8-K filed with the SEC on December 7, 2010 and Form S-4/A filed with the SEC on April 28, 2011.
The following table summarizes, by level within the fair value hierarchy, our derivative financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods presented.
| |
|
Recurring fair values
Derivative financial instruments
|
|
| |
|
June 30, 2011
|
|
|
December 31, 2010
|
|
|
June 30, 2010
|
|
|
In millions
|
|
Assets
|
|
|
Liabilities
|
|
|
Assets (1)
|
|
|
Liabilities
|
|
|
Assets
|
|
|
Liabilities
|
|
Quoted prices in active markets (Level 1)
|
|
$ |
13 |
|
|
$ |
(52 |
) |
|
$ |
22 |
|
|
$ |
(71 |
) |
|
$ |
34 |
|
|
$ |
(55 |
) |
Significant other observable inputs (Level 2)
|
|
|
102 |
|
|
|
(17 |
) |
|
|
153 |
|
|
|
(29 |
) |
|
|
148 |
|
|
|
(50 |
) |
Netting of cash collateral
|
|
|
37 |
|
|
|
40 |
|
|
|
53 |
|
|
|
52 |
|
|
|
27 |
|
|
|
30 |
|
Total carrying value (2) (3)
|
|
$ |
152 |
|
|
$ |
(29 |
) |
|
$ |
228 |
|
|
$ |
(48 |
) |
|
$ |
209 |
|
|
$ |
(75 |
) |
|
(1)
|
Less than $1 million premium at December 31, 2010 associated with weather derivatives has been excluded as they are based on intrinsic value, not fair value.
|
|
(2)
|
There were no material unobservable inputs (Level 3) for any of the periods presented.
|
|
(3)
|
There were no material transfers between Level 1, Level 2, or Level 3 for any of the periods presented.
|
In addition, we have several financial and nonfinancial assets and liabilities subject to fair value measures. These financial assets and liabilities include cash and cash equivalents, accounts receivable, accounts payable and debt. For cash and cash equivalents, accounts receivable and accounts payable we consider carrying value to materially approximate fair value due to their short-term nature. The nonfinancial assets and liabilities include pension and post-retirement benefits, which are presented in Note 3 to our Consolidated Financial Statements and related notes included in Item 8 of our 2010 Form 10-K.
Our debt is recorded at carrying value. We estimate the fair value of our debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. In determining the market interest yield curve, we considered our currently assigned ratings for unsecured debt. The following table presents the carrying value and fair value of our debt as of the following periods.
|
In millions
|
|
June 30, 2011
|
|
|
December 31, 2010
|
|
|
June 30, 2010
|
|
Long-term debt carrying amount (1)
|
|
$ |
2,174 |
|
|
$ |
1,973 |
|
|
$ |
1,853 |
|
Long-term debt fair value (1)
|
|
$ |
2,339 |
|
|
$ |
2,122 |
|
|
$ |
2,144 |
|
|
Short-term debt carrying amount (2)
|
|
$ |
144 |
|
|
$ |
733 |
|
|
$ |
394 |
|
Short-term debt fair value (2)
|
|
$ |
144 |
|
|
$ |
733 |
|
|
$ |
394 |
|
|
(1)
|
June 30, 2011 includes $10 million of medium-term notes that are due in June 2012. December 31, 2010 and June 30, 2010 include $300 million of senior notes repaid in January 2011.
|
|
(2)
|
June 30, 2011 excludes $10 million of medium-term notes that are due in June 2012. December 31, 2010 and June 30, 2010 exclude $300 million of senior notes repaid in January 2011.
|
Our risk management activities are monitored by our Risk Management Committee, which consists of members of senior management and is charged with reviewing and enforcing our risk management activities and policies. Our use of derivative financial instruments and physical transactions is limited to predefined risk tolerances associated with pre-existing or anticipated physical natural gas sales and purchases and system use and storage. We use the following types of derivative financial instruments and physical transactions to manage natural gas price, interest rate, weather and foreign currency risks:
- forward contracts;
- futures contracts;
- options contracts;
- financial swaps;
- treasury locks;
- weather derivative contracts;
- storage and transportation capacity transactions; and
- foreign currency forward contracts.
Our derivative financial instruments do not contain any material credit-risk-related or other contingent features that could increase the payments for collateral that we post in the normal course of business when our financial instruments are in net liability positions. Additional information on our energy marketing receivables and payables, which do have credit-risk-related or other contingent features, is discussed in Note 2.
On May 4, 2011, we entered into interest rate swaps with an aggregate notional amount of $250 million to effectively convert a portion of our fixed rate interest obligation on the $300 million 6.4% senior notes due July 15, 2016 to a variable-rate obligation. We pay a floating interest rate equal to the three-month London Inter-bank Offered Rate (LIBOR) plus 3.9%. We designated the interest rate swaps as fair value hedges. The fair values of our interest rate swaps were reflected as a long-term derivative asset of $3 million at June 30, 2011. For more information on our senior notes, see Note 7.
There have been no other significant changes to our derivative financial instruments, as described in Note 2 and Note 4 to our Consolidated Financial Statements and related notes included in Item 8 of our 2010 Form 10-K. The table below summarizes the various ways in which we account for our derivative instruments and the impact on our Condensed Consolidated Financial Statements:
| |
Recognition and Measurement
|
|
Accounting Treatment
|
Statement of Financial Position
|
Income Statement
|
|
Cash flow hedge
|
Recorded at fair value
|
Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
|
| |
Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss)
|
Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income (loss) into earnings when the forecasted transaction affects earnings
|
|
Fair value hedge
|
Recorded at fair value
|
Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
|
| |
Change in fair value of the derivative instrument is recorded as an adjustment to book value
|
Effective portion of the gain or loss on the derivative instrument is recognized in earnings
|
|
Not designated as hedges
|
Recorded at fair value
|
The gain or loss on the derivative instrument is recognized in earnings
|
| |
Elizabethtown Gas’ derivative financial instruments are recorded as a regulatory asset or liability until included in natural gas costs
|
The gain or loss on these derivative instruments is reflected in natural gas costs and is ultimately included in billings to customers
|
| |
Change in fair value of the derivative instrument is recorded as an adjustment to book value
|
Change in fair value of the derivative instrument is recognized in earnings
|
Quantitative Disclosures Related to Derivative Financial Instruments
As of the periods presented, our derivative financial instruments were comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas.
We had net long natural gas contracts outstanding in the following quantities:
| Natural gas contracts |
|
|
|
|
|
|
|
|
|
|
In Bcf
|
|
June 30,
2011 (1)
|
|
|
December 31, 2010
|
|
|
June 30,
2010
|
|
|
Hedge designation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
4 |
|
|
|
5 |
|
|
|
|
|
191 |
|
|
|
220 |
|
|
|
244 |
|
|
|
|
|
192 |
|
|
|
224 |
|
|
|
249 |
|
|
Hedge position:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,559 |
) |
|
|
(1,605 |
) |
|
|
(1,571 |
) |
|
|
|
|
1,751 |
|
|
|
1,829 |
|
|
|
1,820 |
|
|
|
|
|
192 |
|
|
|
224 |
|
|
|
249 |
|
(1) Approximately 97% of these contracts have durations of two years or less and the remaining 3% expire in 3 to 6 years.
Derivative Financial Instruments on the Condensed Consolidated Statements of Financial Position
In accordance with regulatory requirements, realized losses on derivative financial instruments used at Elizabethtown Gas in our distribution operations segment were reflected in deferred natural gas costs within our Condensed Consolidated Statements of Financial Position for the periods presented and are contained in the following table.
| |
|
Three months ended
June 30,
|
|
|
Six months ended
June 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
|
|
$ |
5 |
|
|
$ |
7 |
|
|
$ |
13 |
|
|
$ |
15 |
|
The following table presents the fair value and statements of financial position classification of our derivative financial instruments:
| |
|
|
|
|
As of |
|
|
|
|
|
|
In millions
|
Statement of financial position location (1) (2)
|
|
Jun. 30, 2011 |
|
Dec. 31, 2010
|
|
|
Jun. 30, 2010
|
|
|
|
Designated as cash flow and fair value hedges
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
Current natural gas contracts
|
Derivative financial instruments assets and liabilities – current portion
|
|
$ |
1 |
|
|
$ |
3 |
|
|
$ |
4 |
|
Interest rate swap agreements
|
Derivative financial instruments assets – long-term portion
|
|
|
3 |
|
|
|
0 |
|
|
|
0 |
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current natural gas contracts
|
Derivative financial instruments assets and liabilities – current portion
|
|
|
(2 |
) |
|
|
(5 |
) |
|
|
(8 |
) |
Interest rate swap agreements
|
Derivative financial instruments liabilities – long-term portion
|
|
|
0 |
|
|
|
0 |
|
|
|
(13 |
) |
|
|
|
|
|
2 |
|
|
|
(2 |
) |
|
|
(17 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Not designated as cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current natural gas contracts
|
Derivative financial instruments assets and liabilities – current portion
|
|
|
297 |
|
|
|
541 |
|
|
|
528 |
|
Noncurrent natural gas contracts
|
Derivative financial instruments assets and liabilities
|
|
|
70 |
|
|
|
105 |
|
|
|
120 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current natural gas contracts
|
Derivative financial instruments assets and liabilities – current portion
|
|
|
(263 |
) |
|
|
(489 |
) |
|
|
(458 |
) |
Noncurrent natural gas contracts
|
Derivative financial instruments assets and liabilities
|
|
|
(60 |
) |
|
|
(80 |
) |
|
|
(96 |
) |
|
Total
|
|
|
|
44 |
|
|
|
77 |
|
|
|
94 |
|
Total derivative financial instruments
|
|
$ |
46 |
|
|
$ |
75 |
|
|
$ |
77 |
|
|
(1)
|
These amounts are netted within our Condensed Consolidated Statements of Financial Position. Some of our derivative financial instruments have asset positions which are presented as a liability in our Condensed Consolidated Statements of Financial Position, and we have derivative instruments that have liability positions which are presented as an asset in our consolidated statements of financial position. |
|
(2)
|
As required by the authoritative guidance related to derivatives and hedging, the fair value amounts above are presented on a gross basis. As a result, the amounts above do not include cash collateral held on deposit in broker margin accounts of $77 million as of June 30, 2011, $57 million as of June 30, 2010 and $105 million as of December 31, 2010. Accordingly, the amounts above will differ from the amounts presented on our Condensed Consolidated Statements of Financial Position and the fair value information presented for our derivative financial instruments in the recurring values table of this note. |
Derivative Financial Instruments on the Condensed Consolidated Statements of Income
The following table presents the impacts of our derivative financial instruments in our Condensed Consolidated Statements of Income:
| |
|
For the three months ended June 30,
|
|
For the six months ended June 30,
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
Designated as cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
Natural gas contracts – loss reclassified from OCI into cost of gas for settlement of hedged item (1)
|
|
$ |
(1 |
) |
|
$ |
(3 |
) |
|
$ |
(1 |
) |
|
$ |
(10 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Not designated as hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas contracts – fair value adjustments recorded in operating revenues (2)
|
|
|
10 |
|
|
|
(2 |
) |
|
|
16 |
|
|
|
16 |
|
Natural gas contracts – net fair value adjustments recorded in cost of gas (3)
|
|
|
0 |
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(3 |
) |
Total gains (losses) on derivative instruments
|
|
$ |
9 |
|
|
$ |
(6 |
) |
|
$ |
14 |
|
|
$ |
3 |
|
|
(1)
|
We expect that $1 million of pre-tax net losses will be reclassified from OCI into cost of gas for the settlement of hedged items over the next twelve months.
|
|
(2)
|
Associated with the fair value of existing derivative instruments at June 30, 2011 and 2010.
|
|
(3)
|
Excludes gains recorded in cost of gas associated with weather derivatives of $4 million for the six months ended June 30, 2011 and losses of $20 million for the six months ended June 30, 2010.
|
Pension Benefits
We sponsor two tax-qualified defined benefit retirement plans for our eligible employees, the AGL Resources Inc. Retirement Plan and the Employees’ Retirement Plan of NUI Corporation. A defined benefit plan specifies the amount of benefits an eligible participant eventually will receive using information about the participant. Following are the combined cost components of our two defined pension plans for the periods indicated:
| |
|
Three months ended
June 30,
|
|
|
Six months ended
June 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
|
|
$ |
4 |
|
|
$ |
2 |
|
|
$ |
7 |
|
|
$ |
5 |
|
|
|
|
|
7 |
|
|
|
7 |
|
|
|
14 |
|
|
|
14 |
|
Expected return on plan assets
|
|
|
(8 |
) |
|
|
(7 |
) |
|
|
(16 |
) |
|
|
(15 |
) |
Amortization of prior service cost
|
|
|
0 |
|
|
|
0 |
|
|
|
(1 |
) |
|
|
(1 |
) |
Recognized actuarial loss
|
|
|
3 |
|
|
|
2 |
|
|
|
7 |
|
|
|
5 |
|
|
|
|
$ |
6 |
|
|
$ |
4 |
|
|
$ |
11 |
|
|
$ |
8 |
|
Postretirement Benefits
We sponsor a defined benefit postretirement health care plan for our eligible employees, the Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Postretirement Plan). Eligibility for these benefits is based on age and years of service. The AGL Postretirement Plan includes medical coverage for all eligible AGL Resources employees who were employed as of June 30, 2002, if they reach retirement age while working for the Company. Additionally, the AGL Postretirement Plan provides life insurance for all employees if they have a minimum of ten years service at retirement. The state regulatory commissions have approved phase-ins that defer a portion of other postretirement benefits expense for future recovery. Following are the cost components of the AGL Postretirement Plan for the periods indicated:
| |
|
Three months ended
June 30,
|
|
|
Six months ended
June 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
|
|
$ |
0 |
|
|
$ |
1 |
|
|
$ |
0 |
|
|
$ |
1 |
|
|
|
|
|
2 |
|
|
|
2 |
|
|
|
3 |
|
|
|
3 |
|
Expected return on plan assets
|
|
|
(2 |
) |
|
|
(2 |
) |
|
|
(3 |
) |
|
|
(3 |
) |
Amortization of prior service cost
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(2 |
) |
|
|
(2 |
) |
Recognized actuarial loss
|
|
|
0 |
|
|
|
0 |
|
|
|
1 |
|
|
|
1 |
|
|
|
|
$ |
(1 |
) |
|
$ |
0 |
|
|
$ |
(1 |
) |
|
$ |
0 |
|
Contributions
Our employees do not contribute to these pension and postretirement plans. We fund the qualified pension plans by contributing at least the minimum amount required by applicable regulations and as recommended by our actuary. However, we may also contribute in excess of the minimum required amount. As required by The Pension Protection Act (the Act) of 2006, we calculate the minimum amount of funding using the traditional unit credit cost method.
The Act contained new funding requirements for single employer defined benefit pension plans and established a 100% funding target (over a 7-year amortization period) for plan years beginning after December 31, 2007. If certain conditions are met, the Worker, Retiree and Employer Recovery Act of 2008 allowed us to measure our required minimum contributions based on a funding target of 100% during 2010 and 2011. In the first six months of 2011 we contributed $44 million to our qualified pension plans and $21 million during the same period last year.
Employee Savings Plan Benefits
We sponsor the Retirement Savings Plus Plan (RSP), a defined contribution benefit plan that allows eligible participants to make contributions to their accounts up to specified limits. Under the RSP, our matching contributions to participant accounts were $4 million in the first six months of 2011 and $3 million in the first six months of 2010.
AGL Capital Corporation, our wholly-owned finance subsidiary, provides for our ongoing financing needs through a commercial paper program, the issuance of various debt and hybrid securities and other financing arrangements. The following table provides maturity dates, weighted-average interest rates and amounts outstanding for our various debt securities and facilities. For additional information on our debt see Note 7 in our Consolidated Financial Statements and related notes in Item 8 of our 2010 Form 10-K.
| |
|
|
|
|
June 30, 2011
|
|
|
|
|
|
June 30, 2010
|
|
|
In millions
|
|
Year(s)
due
|
|
|
Weighted- average interest
rate
|
|
|
Outstanding
|
|
Outstanding at
December 31, 2010
|
|
|
Weighted-average interest
rate
|
|
|
Outstanding
|
|
|
Short-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011-2012 |
|
|
|
0.4 |
% |
|
$ |
142 |
|
|
$ |
732 |
|
|
|
0.4 |
% |
|
$ |
393 |
|
Current portion of long-term debt
|
|
|
2012 |
|
|
|
8.4 |
|
|
|
10 |
|
|
|
300 |
|
|
|
7.1 |
|
|
|
300 |
|
Current portion of capital leases
|
|
2011-2012 |
|
|
|
4.9 |
|
|
|
2 |
|
|
|
1 |
|
|
|
4.9 |
|
|
|
1 |
|
Total short-term debt and current portion of long-term debt
|
|
|
|
|
|
|
0.6 |
% |
|
$ |
154 |
|
|
$ |
1,033 |
|
|
|
3.9 |
% (1) |
|
$ |
694 |
|
|
Long-term debt - net of current portion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013-2041 |
|
|
|
5.5 |
% |
|
$ |
1,775 |
|
|
$ |
1,275 |
|
|
|
5.5 |
% |
|
$ |
1,275 |
|
Gas facility revenue bonds
|
|
2022-2033 |
|
|
|
1.2 |
|
|
|
200 |
|
|
|
200 |
|
|
|
1.8 |
|
|
|
79 |
|
|
|
|
2012-2027 |
|
|
|
7.8 |
|
|
|
186 |
|
|
|
196 |
|
|
|
7.8 |
|
|
|
196 |
|
AGL Capital interest rate swaps
|
|
|
2016 |
|
|
|
4.2 |
|
|
|
3 |
|
|
|
0 |
|
|
|
0.0 |
|
|
|
0 |
|
|
|
|
|
2012 |
|
|
|
0.0 |
|
|
|
0 |
|
|
|
2 |
|
|
|
4.9 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
5.0 |
% |
|
$ |
2,164 |
|
|
$ |
1,673 |
|
|
|
5.4 |
% (2) |
|
$ |
1,553 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.3 |
% |
|
$ |
2,318 |
|
|
$ |
2,706 |
|
|
|
5.0 |
% |
|
$ |
2,247 |
|
|
(1)
|
Excluding the $300 million of senior notes repaid in January 2011, the weighted-average short-term interest rate for the six months ended June 30, 2010 was 0.4%.
|
|
(2)
|
Including the $300 million of senior notes repaid in January 2011, the weighted-average long-term interest rate for the six months ended June 30, 2010 was 5.7%.
|
Senior Notes
On March 16, 2011, we completed a public offering of $500 million in 30 year senior notes with an interest rate of 5.9% and a maturity date of March 15, 2041. The net proceeds were used to repay commercial paper, a portion of which we borrowed to repay our $300 million in senior notes that matured on January 14, 2011. Following our issuance of these senior notes, and in accordance with the terms of our Bridge Facility, the principal amount of the Bridge Facility has been reduced from $1,050 million to $852 million.
On May 4, 2011, we entered into interest rate swaps with an aggregate notional amount of $250 million to effectively convert a portion of our $300 million 6.4% fixed-rate senior notes that mature July 15, 2016 to a variable-rate debt obligation. The interest rates reset quarterly based on three month LIBOR plus 3.9%. The effective variable interest rate at June 30, 2011, was 4.2%.
Financial and Non-Financial Covenants
Our Credit Facility includes a financial covenant that requires us to maintain a ratio, on a consolidated basis, of total debt to total capitalization of no more than 70%; however, our goal is to maintain this ratio at a level between 50% and 60%. Our ratio, on a consolidated basis, of total debt to total capitalization as calculated in accordance with our debt covenant includes standby letters of credit, performance/surety bonds and excludes certain pension and other post-retirement benefit adjustments and cash flow hedges that are not yet settled. Adjusting for these items, the following table contains our debt-to-capitalization ratio for the periods presented, which are within our targeted ranges.
| |
|
June 30, 2011
|
|
|
December 31, 2010
|
|
|
June 30, 2010
|
|
Debt-to-capitalization ratio
|
|
|
53 |
% |
|
|
58 |
% |
|
|
54 |
% |
The Credit Facility contains certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, restricted payments, asset dispositions, fundamental changes and other matters customarily restricted in such agreements. We are currently in compliance with all existing debt provisions and covenants. Our Bridge Facility contains the same financial covenant and similar non-financial covenants and default provisions; however, most of these are not in effect until we draw under the facility.
Default Provisions
Our debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. Our most important default provisions include:
- a maximum leverage ratio
- insolvency events and nonpayment of scheduled principal or interest payments
- acceleration of other financial obligations
- change of control provisions
We have no trigger events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that requires us to issue equity based on credit ratings or other trigger events.
On a quarterly basis we evaluate all of our joint venture interests to determine if they represent a variable interest entity (VIE) as defined by the authoritative accounting guidance on consolidation. We have determined that SouthStar is our only VIE. Additionally, we have concluded that we are the primary beneficiary of the VIE, which requires us to consolidate the assets, liabilities and statements of income of the joint venture. Our methodology for determining that we are the primary beneficiary, and that our involvement allows us to direct SouthStar’s activities that most significantly influence its performance, has not changed during the six months ended June 30, 2011. See Note 9 to our Consolidated Financial Statements and related notes included in Item 8 of our 2010 Form 10-K. Earnings in 2011 and 2010 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, and under various other trade names to retail customers in Ohio, Florida and New York and to commercial and industrial customers principally in Alabama, Florida, North Carolina, South Carolina and Tennessee.
During the six months ended June 30, 2011, there have been no significant changes to the primary risks associated with SouthStar as discussed in our risk factors included in Item 1A of our 2010 Form 10-K. See Note 10 for Summarized Statements of Income, Statements of Financial Position and capital expenditure information related to the retail energy operations segment, which is primarily comprised of SouthStar. The following table illustrates the effect that our 2009 purchase of an additional 15% ownership interest, which became effective in January 2010, had on our equity for the six months ended June 30, 2010.
|
In millions
|
|
Premium on common stock
|
|
|
Accumulated other comprehensive loss
|
|
|
Total
|
|
Purchase of additional 15% ownership interest
|
|
$ |
(51 |
) |
|
$ |
(1 |
) |
|
$ |
(52 |
) |
SouthStar’s financial results are seasonal in nature, with the business depending to a great extent on the first and fourth quarters of each year for the majority of its earnings. SouthStar’s current assets consist primarily of natural gas inventory, derivative financial instruments and receivables from its customers. SouthStar also has receivables from us due to its participation in our commercial paper program. See Note 2 for additional discussions of SouthStar’s inventories. SouthStar’s restricted assets consist of customer deposits and are immaterial as of June 30, 2011 and 2010. SouthStar’s current liabilities consist primarily of accrued natural gas costs, other accrued expenses, customer deposits, derivative financial instruments and payables to us from its participation in our commercial paper program.
As of June 30, 2011, SouthStar’s current assets, which approximate fair value, exceeded its current liabilities, long-term assets and other deferred debits and long-term liabilities and other deferred credits by approximately $103 million. 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 such contracts were terminated. As a result, our maximum exposure to a loss at SouthStar is considered to be immaterial. SouthStar’s creditors have no recourse to our general credit beyond the corporate guarantees 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. Additionally, 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 financial instruments.
Cash flows used in our financing activities includes SouthStar’s distributions to the noncontrolling interest, which reflects the cash distribution to Piedmont for its ownership interest in SouthStar’s annual earnings from the prior year. Generally this distribution occurs in the first or second quarter. In the six months ended June 30, 2011 SouthStar distributed $16 million to Piedmont and $27 million during the same period last year. This decrease of $11 million was primarily the result of our increased ownership percentage of SouthStar in 2010.
The following table provides additional information on SouthStar’s assets and liabilities as of the periods presented, which are consolidated within our Condensed Consolidated Statements of Financial Position.
| |
|
June 30, 2011 |
|
|
December 31, 2010 |
|
|
June 30, 2010 |
|
|
In millions
|
|
Consolidated |
|
|
SouthStar (1)
|
|
|
|
% (2) |
|
|
Consolidated |
|
|
SouthStar (1)
|
|
|
|
% (2) |
|
|
Consolidated |
|
|
SouthStar (1)
|
|
|
|
% (2) |
|
|
|
|
$ |
1,603 |
|
|
$ |
164 |
|
|
|
10 |
% |
|
$ |
2,166 |
|
|
$ |
239 |
|
|
|
11 |
% |
|
$ |
1,525 |
|
|
$ |
154 |
|
|
|
10 |
% |
Long-term assets and other deferred debits
|
|
|
5,614 |
|
|
|
9 |
|
|
|
0 |
|
|
|
5,356 |
|
|
|
9 |
|
|
|
0 |
|
|
|
5,261 |
|
|
|
9 |
|
|
|
0 |
|
|
|
|
$ |
7,217 |
|
|
$ |
173 |
|
|
|
2 |
% |
|
$ |
7,522 |
|
|
$ |
248 |
|
|
|
3 |
% |
|
$ |
6,786 |
|
|
$ |
163 |
|
|
|
2 |
% |
|
|
|
$ |
1,399 |
|
|
$ |
52 |
|
|
|
4 |
% |
|
$ |
2,432 |
|
|
$ |
93 |
|
|
|
4 |
% |
|
$ |
1,862 |
|
|
$ |
40 |
|
|
|
2 |
% |
Long-term liabilities and other deferred credits
|
|
|
3,904 |
|
|
|
0 |
|
|
|
0 |
|
|
|
3,254 |
|
|
|
0 |
|
|
|
0 |
|
|
|
3,097 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
5,303 |
|
|
|
52 |
|
|
|
1 |
|
|
|
5,686 |
|
|
|
93 |
|
|
|
2 |
|
|
|
4,959 |
|
|
|
40 |
|
|
|
1 |
|
|
|
|
|
1,914 |
|
|
|
121 |
|
|
|
6 |
|
|
|
1,836 |
|
|
|
155 |
|
|
|
8 |
|
|
|
1,827 |
|
|
|
123 |
|
|
|
7 |
|
Total liabilities and equity
|
|
$ |
7,217 |
|
|
$ |
173 |
|
|
|
2 |
% |
|
$ |
7,522 |
|
|
$ |
248 |
|
|
|
3 |
% |
|
$ |
6,786 |
|
|
$ |
163 |
|
|
|
2 |
% |
|
(1)
|
These amounts reflect information for SouthStar and do not include intercompany eliminations and the balances of our wholly-owned subsidiary with an 85% ownership interest in SouthStar. Accordingly, the amounts will not agree to the identifiable and total assets for our retail energy operations segment reported in Note 10.
|
|
(2)
|
SouthStar’s percentage of the amount on our Condensed Consolidated Statements of Financial Position.
|
Contractual Obligations and Commitments
We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities that are reasonably likely to have a material effect on liquidity or the availability of capital resources. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. There were no significant changes to our contractual obligations described in Note 10 to our Consolidated Financial Statements and related notes as filed in Item 8 of our 2010 Form 10-K.
Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. The following table illustrates our contingent financial commitments as of June 30, 2011:
| |
|
Commitments due before
December 31,
|
|
|
In millions
|
|
Total
|
|
|
2011
|
|
|
2012 & thereafter
|
|
Standby letters of credit and performance and surety bonds
|
|
$ |
14 |
|
|
$ |
6 |
|
|
$ |
8 |
|
Litigation
We are involved in litigation arising in the normal course of business. The ultimate resolution of such litigation is not expected to have a material adverse effect on our Condensed Consolidated Statement of Financial Position, Income or Cash Flows.
In February 2008, a class action lawsuit was filed in the Superior Court of Fulton County in the State of Georgia against Georgia Natural Gas alleging that it charged its customers on variable rate plan prices for natural gas that were in excess of the published price, failed to give proper notice regarding the availability of potentially lower price plans and that it changed its methodology for computing variable rates. This lawsuit was dismissed in September 2008. The plaintiffs appealed the dismissal of the lawsuit and, in May 2009, the Georgia Court of Appeals reversed the lower court’s order. In June 2009, Georgia Natural Gas filed a petition for reconsideration with the Georgia Supreme Court. In October 2009, the Georgia Supreme Court agreed to review the Court of Appeals’ decision and held oral arguments in January 2010. In March 2010 the Georgia Supreme Court upheld the Court of Appeals’ decision. The case has been remanded back to the Superior Court of Fulton County for further proceedings. Georgia Natural Gas asserts that no violation of law or Georgia Commission rules has occurred. This case has not had, and is not expected to have, a material impact on our results of operation or financial condition.
We have been named as a defendant in several class action lawsuits brought by purported Nicor shareholders challenging Nicor’s proposed merger with us. The complaints allege that we aided and abetted alleged breaches of fiduciary duty by Nicor’s Board of Directors. The shareholder lawsuits seek, among other things, declaratory and injunctive relief, including orders enjoining the defendants from completing the proposed merger and, in certain circumstances, damages. In March 2011, the parties entered into an agreement to resolve all of the shareholder lawsuits, subject to court approval, based on Nicor providing certain supplemental disclosures to our joint proxy statement filed on April 28, 2011. The parties expect to submit the agreement to the court for approval shortly. For more information on our proposed merger with Nicor see Note 3.
Environmental Remediation Costs
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. Except in those instances where a better estimate is known, we have recorded the lower end of the cost estimate range. The following table provides more information on the costs related to remediation of our former operating sites.
|
In millions
|
|
Cost estimate range
|
|
|
Amount recorded
|
|
|
Expected costs over next twelve months
|
|
|
|
|
$ |
39 - $101 |
|
|
$ |
56 |
|
|
$ |
5 |
|
|
|
|
|
124 - 175 |
|
|
|
124 |
|
|
|
12 |
|
|
|
|
|
11 - 16 |
|
|
|
11 |
|
|
|
3 |
|
|
|
|
$ |
174 - $292 |
|
|
$ |
191 |
|
|
$ |
20 |
|
The increase in our consolidated environmental remediation cost liability of $48 million from December 31, 2010 is primarily a result of increases in estimated excavation and remediation costs at our sites in New Jersey based on updated studies completed during the second quarter of 2011. For more information on our environmental remediation costs, see Note 10 to our Consolidated Financial Statements and related notes as filed in Item 8 of our 2010 Form 10-K
We generate nearly all our operating revenues through the sale, distribution, transportation and storage of natural gas. Our operating segments comprise revenue-generating components of our company for which we produce separate 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 four operating segments – distribution operations, retail energy operations, wholesale services and energy investments and a nonoperating corporate segment.
Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia. 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 energy operations segment includes retail natural gas marketing to end-use customers primarily in Georgia. Our wholesale services segment includes natural gas asset management and related logistics activities for each of our utilities as well as for nonaffiliated companies, natural gas storage arbitrage and related activities. Our energy investments segment includes a number of aggregated businesses that are related and complementary to our primary business. The most significant is the development and operation of high-deliverability natural gas storage assets. Our corporate segment includes intercompany eliminations and aggregated subsidiaries that are not significant enough on a stand-alone basis to warrant treatment as an operating segment, and that do not fit into one of our four operating segments.
We evaluate segment performance based primarily on the non-GAAP measure of EBIT, which includes the effects of corporate expense allocations. EBIT includes operating income and other income and expenses. Items we do not include in EBIT are financing costs, including interest and debt expense and income taxes, each of which we evaluate on a consolidated level. We believe EBIT is a useful measurement of our performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.
You should not consider EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company.
Following are the reconciliations of EBIT to operating income, earnings before income taxes and net income for the periods presented.
| |
|
Three months ended
June 30,
|
|
|
Six months ended
June 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
Operating income
|
|
$ |
60 |
|
|
$ |
48 |
|
|
$ |
298 |
|
|
$ |
301 |
|
|
Other income
|
|
|
2 |
|
|
|
0 |
|
|
|
3 |
|
|
|
2 |
|
|
|
|
|
62 |
|
|
|
48 |
|
|
|
301 |
|
|
|
303 |
|
|
Interest expense, net
|
|
|
32 |
|
|
|
26 |
|
|
|
61 |
|
|
|
54 |
|
|
Earnings before income taxes
|
|
|
30 |
|
|
|
22 |
|
|
|
240 |
|
|
|
249 |
|
|
Income taxes
|
|
|
11 |
|
|
|
8 |
|
|
|
87 |
|
|
|
90 |
|
|
Net income
|
|
$ |
19 |
|
|
$ |
14 |
|
|
$ |
153 |
|
|
$ |
159 |
|
Information by segment on our Statements of Financial Position as of December 31, 2010, is as follows:
|
In millions
|
|
Identifiable and total assets (1)
|
|
|
Goodwill
|
|
|
|
|
$ |
5,498 |
|
|
$ |
404 |
|
|
|
|
|
259 |
|
|
|
0 |
|
|
|
|
|
1,326 |
|
|
|
0 |
|
|
|
|
|
479 |
|
|
|
14 |
|
|
|
|
|
(40 |
) |
|
|
0 |
|
|
Consolidated
|
|
$ |
7,522 |
|
|
$ |
418 |
|
|
(1)
|
Identifiable assets are those assets used in each segment’s operations.
|
|
(2)
|
Our corporate segments assets consist primarily of cash and cash equivalents and property, plant and equipment 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 June 30, 2011
|
In millions
|
|
Distribution operations
|
|
|
Retail energy operations
|
|
|
Wholesale services
|
|
|
Energy investments
|
|
Corporate and intercompany eliminations (3) |
|
|
Consolidated AGL Resources Inc.
|
|
Operating revenues from external parties
|
|
$ |
237 |
|
|
$ |
117 |
|
|
$ |
9 |
|
|
$ |
10 |
|
|
$ |
2 |
|
|
$ |
375 |
|
Intercompany revenues (1)
|
|
|
41 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
(41 |
) |
|
|
0 |
|
|
|
|
|
278 |
|
|
|
117 |
|
|
|
9 |
|
|
|
10 |
|
|
|
(39 |
) |
|
|
375 |
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70 |
|
|
|
100 |
|
|
|
1 |
|
|
|
2 |
|
|
|
(39 |
) |
|
|
134 |
|
Operation and maintenance
|
|
|
89 |
|
|
|
15 |
|
|
|
12 |
|
|
|
3 |
|
|
|
8 |
|
|
|
127 |
|
Depreciation and amortization
|
|
|
35 |
|
|
|
0 |
|
|
|
1 |
|
|
|
3 |
|
|
|
3 |
|
|
|
42 |
|
Taxes other than income taxes
|
|
|
9 |
|
|
|
1 |
|
|
|
0 |
|
|
|
1 |
|
|
|
1 |
|
|
|
12 |
|
|
|
|
|
203 |
|
|
|
116 |
|
|
|
14 |
|
|
|
9 |
|
|
|
(27 |
) |
|
|
315 |
|
|
|
|
|
75 |
|
|
|
1 |
|
|
|
(5 |
) |
|
|
1 |
|
|
|
(12 |
) |
|
|
60 |
|
|
|
|
|
1 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
1 |
|
|
|
2 |
|
|
|
|
$ |
76 |
|
|
$ |
1 |
|
|
$ |
(5 |
) |
|
$ |
1 |
|
|
$ |
(11 |
) |
|
$ |
62 |
|
|
|
|
$ |
87 |
|
|
$ |
0 |
|
|
$ |
1 |
|
|
$ |
8 |
|
|
$ |
6 |
|
|
$ |
102 |
|
Three months ended June 30, 2010
|
In millions
|
|
Distribution operations
|
|
|
Retail energy operations
|
|
|
Wholesale services
|
|
|
Energy investments
|
|
Corporate and intercompany eliminations (3) |
|
|
Consolidated AGL Resources Inc.
|
|
Operating revenues from external parties
|
|
$ |
226 |
|
|
$ |
117 |
|
|
$ |
(8 |
) |
|
$ |
23 |
|
|
$ |
1 |
|
|
$ |
359 |
|
Intercompany revenues (1)
|
|
|
34 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
(34 |
) |
|
|
0 |
|
|
|
|
|
260 |
|
|
|
117 |
|
|
|
(8 |
) |
|
|
23 |
|
|
|
(33 |
) |
|
|
359 |
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
62 |
|
|
|
99 |
|
|
|
1 |
|
|
|
11 |
|
|
|
(32 |
) |
|
|
141 |
|
Operation and maintenance
|
|
|
86 |
|
|
|
17 |
|
|
|
9 |
|
|
|
9 |
|
|
|
(2 |
) |
|
|
119 |
|
Depreciation and amortization
|
|
|
34 |
|
|
|
0 |
|
|
|
1 |
|
|
|
1 |
|
|
|
3 |
|
|
|
39 |
|
Taxes other than income taxes
|
|
|
10 |
|
|
|
0 |
|
|
|
1 |
|
|
|
1 |
|
|
|
0 |
|
|
|
12 |
|
|
|
|
|
192 |
|
|
|
116 |
|
|
|
12 |
|
|
|
22 |
|
|
|
(31 |
) |
|
|
311 |
|
|
|
|
|
68 |
|
|
|
1 |
|
|
|
(20 |
) |
|
|
1 |
|
|
|
(2 |
) |
|
|
48 |
|
|
|
|
|
1 |
|
|
|
0 |
|
|
|
0 |
|
|
|
(1 |
) |
|
|
0 |
|
|
|
0 |
|
|
|
|
$ |
69 |
|
|
$ |
1 |
|
|
$ |
(20 |
) |
|
$ |
0 |
|
|
$ |
(2 |
) |
|
$ |
48 |
|
|
|
|
$ |
92 |
|
|
$ |
0 |
|
|
$ |
1 |
|
|
$ |
36 |
|
|
$ |
6 |
|
|
$ |
135 |
|
Six months ended June 30, 2011
|
In millions
|
|
Distribution operations
|
|
|
Retail energy operations
|
|
|
Wholesale services
|
|
|
Energy investments
|
|
Corporate and intercompany eliminations (3) |
|
|
Consolidated AGL Resources Inc.
|
|
Operating revenues from external parties
|
|
$ |
742 |
|
|
$ |
407 |
|
|
$ |
62 |
|
|
$ |
40 |
|
|
$ |
2 |
|
|
$ |
1,253 |
|
Intercompany revenues (1)
|
|
|
79 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
(79 |
) |
|
|
0 |
|
|
|
|
|
821 |
|
|
|
407 |
|
|
|
62 |
|
|
|
40 |
|
|
|
(77 |
) |
|
|
1,253 |
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
338 |
|
|
|
301 |
|
|
|
4 |
|
|
|
23 |
|
|
|
(77 |
) |
|
|
589 |
|
Operation and maintenance
|
|
|
179 |
|
|
|
35 |
|
|
|
28 |
|
|
|
8 |
|
|
|
8 |
|
|
|
258 |
|
Depreciation and amortization
|
|
|
71 |
|
|
|
1 |
|
|
|
1 |
|
|
|
5 |
|
|
|
5 |
|
|
|
83 |
|
Taxes other than income taxes
|
|
|
18 |
|
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
|
3 |
|
|
|
25 |
|
|
|
|
|
606 |
|
|
|
338 |
|
|
|
34 |
|
|
|
38 |
|
|
|
(61 |
) |
|
|
955 |
|
|
|
|
|
215 |
|
|
|
69 |
|
|
|
28 |
|
|
|
2 |
|
|
|
(16 |
) |
|
|
298 |
|
|
|
|
|
2 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
1 |
|
|
|
3 |
|
|
|
|
$ |
217 |
|
|
$ |
69 |
|
|
$ |
28 |
|
|
$ |
2 |
|
|
$ |
(15 |
) |
|
$ |
301 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable and total assets (2)
|
|
$ |
5,606 |
|
|
$ |
189 |
|
|
$ |
1,038 |
|
|
$ |
485 |
|
|
$ |
(101 |
) |
|
$ |
7,217 |
|
|
|
|
$ |
404 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
14 |
|
|
$ |
0 |
|
|
$ |
418 |
|
|
|
|
$ |
167 |
|
|
$ |
1 |
|
|
$ |
1 |
|
|
$ |
15 |
|
|
$ |
12 |
|
|
$ |
196 |
|
Six months ended June 30, 2010
|
In millions
|
|
Distribution operations
|
|
|
Retail energy operations
|
|
|
Wholesale services
|
|
|
Energy investments
|
|
|
Corporate and intercompany eliminations (3)
|
|
|
Consolidated AGL Resources Inc.
|
|
Operating revenues from external parties
|
|
$ |
754 |
|
|
$ |
510 |
|
|
$ |
59 |
|
|
$ |
37 |
|
|
$ |
2 |
|
|
$ |
1,362 |
|
Intercompany revenues (1)
|
|
|
72 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
(72 |
) |
|
|
0 |
|
|
|
|
|
826 |
|
|
|
510 |
|
|
|
59 |
|
|
|
37 |
|
|
|
(70 |
) |
|
|
1,362 |
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
364 |
|
|
|
396 |
|
|
|
9 |
|
|
|
13 |
|
|
|
(70 |
) |
|
|
712 |
|
Operation and maintenance
|
|
|
173 |
|
|
|
37 |
|
|
|
24 |
|
|
|
15 |
|
|
|
(5 |
) |
|
|
244 |
|
Depreciation and amortization
|
|
|
68 |
|
|
|
1 |
|
|
|
1 |
|
|
|
3 |
|
|
|
6 |
|
|
|
79 |
|
Taxes other than income taxes
|
|
|
19 |
|
|
|
1 |
|
|
|
2 |
|
|
|
2 |
|
|
|
2 |
|
|
|
26 |
|
|
|
|
|
624 |
|
|
|
435 |
|
|
|
36 |
|
|
|
33 |
|
|
|
(67 |
) |
|
|
1,061 |
|
|
|
|
|
202 |
|
|
|
75 |
|
|
|
23 |
|
|
|
4 |
|
|
|
(3 |
) |
|
|
301 |
|
|
|
|
|
3 |
|
|
|
0 |
|
|
|
0 |
|
|
|
(1 |
) |
|
|
0 |
|
|
|
2 |
|
|
|
|
$ |
205 |
|
|
$ |
75 |
|
|
$ |
23 |
|
|
$ |
3 |
|
|
$ |
(3 |
) |
|
$ |
303 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable and total assets (2)
|
|
$ |
5,225 |
|
|
$ |
175 |
|
|
$ |
987 |
|
|
$ |
530 |
|
|
$ |
(131 |
) |
|
$ |
6,786 |
|
|
|
|
$ |
404 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
14 |
|
|
$ |
0 |
|
|
$ |
418 |
|
|
|
|
$ |
162 |
|
|
$ |
1 |
|
|
$ |
1 |
|
|
$ |
76 |
|
|
$ |
9 |
|
|
$ |
249 |
|
|
(1)
|
Intercompany revenues - wholesale services records its energy marketing and risk management revenues on a net basis, which includes intercompany revenues of $102 million and $249 million for the three and six months ended June 30, 2011 and $91 million and $271 million for the three and six months ended June 30, 2010.
|
|
(2)
|
Identifiable assets are those used in each segments operations.
|
|
(3)
|
Our corporate segments assets consist primarily of cash and cash equivalents, property, plant and equipment and reflect the effect of intercompany eliminations.
|
ITEM 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 the Condensed Consolidated Financial Statements in this quarterly filing, as well as our 2010 Form 10-K.
Forward-Looking Statements
Certain expectations and projections regarding our future performance referenced in this Management’s Discussion and Analysis of Financial Condition and Results of Operations section and elsewhere in this report, as well as in other reports and proxy statements we file with the SEC or otherwise release to the public and on our website are forward-looking statements within the meaning of the U.S. 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," “goaI,” "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 currently available information, our expectations are subject to future events, risks and uncertainties, and there are numerous factors, many of which are 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; the impact of acquisitions and divestitures; direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions, including disruptions in the capital markets and lending environment and the current economic uncertainty; and general economic conditions; uncertainties about environmental issues and the related impact of such issues; the impact of changes in weather, including climate change, on the temperature-sensitive portions of our business; the impact of natural disasters such as hurricanes on the supply and price of natural gas; acts of war or terrorism; and other factors described in detail in our filings with the SEC.
In addition, actual results may differ materially due to the expected timing and likelihood of completion of the proposed merger with Nicor, including the timing, receipt and terms and conditions of any required governmental and regulator approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management’s time and attention from our ongoing business during this time period, the ability to maintain relationships with customers, employees or suppliers as well as the ability to successfully integrate the businesses and realize cost savings and any other synergies and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect.
We caution readers that, in addition to the important factors described in Item 1A, Risk Factors and elsewhere in this report, the factors set forth in Item 1A, “Risk Factors” of our 2010 Form 10-K, among others, could cause our business, results of operations or financial condition in 2011 and thereafter to differ significantly from those expressed in any forward-looking statements. There also may be other factors that we cannot anticipate or that are not described in our 2010 Form 10-K or in this report that could cause our actual results to differ significantly from our expectations. Forward-looking statements are only as of the date they are made. We undertake no 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 U.S. federal securities law.
We are an energy services holding company whose principal business is the distribution of natural gas through our regulated natural gas distribution business. As of June 30, 2011, our six utilities served approximately 2.3 million end-use customers. We are also involved in several related and complementary businesses, including retail natural gas marketing to end-use customers in Georgia, Ohio, Florida and New York; natural gas asset management and related logistics activities for each of our utilities as well as for non-affiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability underground natural gas storage assets. We manage these businesses through four operating segments - distribution operations, retail energy operations, wholesale services and energy investments and one non-operating corporate segment.
The distribution operations segment is subject to regulation and oversight by agencies in each of the six 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 operating expenses and to earn a reasonable return for our shareholders.
The operating revenues and EBIT of our distribution operations and retail energy operations segments are seasonal. During the Heating Season, natural gas usage and operating revenues are generally higher because more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather. Our base operating expenses, excluding cost of gas, interest expense and certain incentive compensation costs, are incurred relatively equally over any given year. Thus, our operating results vary significantly from quarter to quarter as a result of seasonality.
With the exception of Atlanta Gas Light, our 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. Various mechanisms exist that limit our exposure to weather changes within typical ranges in all of our jurisdictions.
Virginia Natural Gas and Chattanooga Gas both have decoupled rates, which separate the recovery of fixed costs for providing service from the volumes of customer throughput. In traditional rate designs, our utilities’ recovery of a significant portion of their fixed customer service and pipeline infrastructure costs is tied to assumed natural gas volumes used by our customers. We believe that separating the recoverable amount of these costs from the customer throughput volumes, or amounts of natural gas used by our customers, allows us to encourage our customers’ energy conservation and ensures a more stable recovery of our fixed costs.
Our retail energy operations segment, which consists primarily of SouthStar, uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to mitigate potential weather impacts. Our Sequent subsidiary within our wholesale services segment generally has greater opportunity to capture operating margin due to price volatility as a result of extreme weather. Our energy investments segment’s primary activity is our natural gas storage business, which develops, acquires and operates high-deliverability salt-dome storage assets in the Gulf Coast region of the United States. While this business can also generate additional revenue during times of peak market demand for natural gas storage services, the majority of our storage services are covered under medium to long-term contracts with third parties at a fixed market rate. For additional information on our operating segments see Item 1, “Business” of our 2010 Form 10-K.
Changes in commodity prices subject a significant portion of our operations to earnings variability. 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. For more information on our derivative financial instruments see Note 5.
Proposed merger with Nicor
In December 2010, we entered into a Merger Agreement with Nicor, which we expect to complete during the second half of 2011. We continue to work on securing the necessary approvals, all of which we anticipate we will obtain, which are discussed below.
|
·
|
In January 2011, we filed a joint application with Nicor with the Illinois Commerce Commission for approval of the proposed merger. The application did not request a rate increase and included a commitment to maintain 2,070 full-time equivalent employees involved in the operation of Nicor’s gas distribution subsidiary for a period of three years following the completion of the merger. The Illinois Commerce Commission has eleven months to act on the application with the deadline for action being December 16, 2011.
|
|
·
|
In April 2011, the Staff of the Illinois Commerce Commission and several intervenors who are participating in the proceeding submitted initial testimony recommending that the Illinois Commerce Commission deny the joint application or that it impose various requirements on the joint applicants as conditions of approval. We and Nicor submitted joint rebuttal testimony to the Illinois Commerce Commission in May 2011. Hearings were held on the matter in July 2011.
|
|
·
|
In April 2011, the Department of Justice and the Federal Trade Commission granted us early termination of the waiting period under the Hart-Scott-Rodino Act.
|
|
·
|
In April 2011, the SEC declared our registration statement on Form S-4 effective.
|
|
·
|
In May 2011, we received approval from the California Public Utilities Commission to transfer ownership of Central Valley Gas Storage from Nicor to us.
|
|
·
|
In June 2011, we and Nicor held special shareholder meetings where the shareholders of both companies approved the proposed merger.
|
We continue to make significant progress towards our financing related to the proposed merger with Nicor, and have secured a portion of the financing requirements for the cash portion of the merger. For additional information relating to the proposed merger please see our Form 8-K filed on December 7, 2010, Note 3, Note 9 and Liquidity and Capital Resources. Further information concerning the proposed merger was included in a joint proxy statement / prospectus contained in our amended registration statement on Form S-4/A that was filed with the SEC on April 28, 2011.
Regulatory Strategy
We continue to pursue a regulatory strategy that focuses on creating value for our various stakeholders, by maintaining a reasonable rate of return for our investors and investing in the reliability and safety of our energy infrastructure. For additional information on our regulatory strategy, see caption “Utility Regulation and Rate Design” under Item 1 “Business” of our 2010 Form 10-K.
In February 2011, Virginia Natural Gas filed a rate case proceeding with the Virginia Commission, requesting a net increase in base rates of $25 million. If approved, the revised rate design would reflect the first increase in customer base rates since 1996. The rate adjustment is designed to recover the cost of investments in our pipeline infrastructure over the past ten years, including the Hampton Roads pipeline project, which was completed in January 2010. The rate application seeks a return on equity of 10.95%, and an authorization of equity to total capitalization ratio of 51%. Rates are expected to be effective by October 1, 2011, subject to refund.
Under the proposed rate design, the typical residential customer’s bill would reflect an increase of $6.27 per month, or approximately nine percent. In consideration of current depressed economic conditions, we proposed a three year phase-in approach that would adjust monthly customer charges by $3.11 during the first year, with incremental increases of less than $2.00 per month in each of the second and third years. The Virginia Commission has scheduled a formal hearing in October 2011 and a final commission order is expected in the first half of 2012.
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, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure. The table below and the following discussions provide updates on some of our larger capital projects.
Distribution Operations
| |
|
Six months ended June 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
Pipeline replacement program
|
|
$ |
35 |
|
|
$ |
32 |
|
|
Integrated System Reinforcement Program
|
|
|
43 |
|
|
|
4 |
|
|
Integrated Customer Growth Program
|
|
|
2 |
|
|
|
1 |
|
|
Enhanced infrastructure program
|
|
|
3 |
|
|
|
26 |
|
|
Total
|
|
$ |
83 |
|
|
$ |
63 |
|
Atlanta Gas Light In October 2009, the Georgia Commission approved Atlanta Gas Light’s STRIDE program. As approved, STRIDE is comprised of the ongoing pipeline replacement program, which was started in 1998 and the new Integrated System Reinforcement Program (i-SRP).
The purpose of the i-SRP program under STRIDE is to upgrade Atlanta Gas Light’s distribution system and liquefied natural gas facilities in Georgia, improve its system reliability and operational flexibility and create a platform to meet long-term forecasted growth. Under STRIDE, Atlanta Gas Light is required to file an updated ten-year forecast of infrastructure requirements under i-SRP along with a new three-year construction plan every three years for review and approval by the Georgia Commission.
In January 2010, the Georgia Commission also approved the Integrated Customer Growth Program (i-CGP) under STRIDE which authorized Atlanta Gas Light to extend Atlanta Gas Light’s pipeline facilities to serve customers who are currently without pipeline access and create new economic development opportunities in Georgia.
Elizabethtown Gas In 2009, the New Jersey BPU approved an accelerated enhanced infrastructure program, which was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. A regulatory cost recovery mechanism has been established whereby estimated rates go into effect at the beginning of each year. At the end of the program the regulatory cost recovery mechanism will be trued-up and any remaining costs not previously collected will be included in base rates. In May 2011, the New Jersey BPU approved Elizabethtown Gas’ request to spend an additional $40 million under this program before the end of 2012.
Energy Investments
Golden Triangle Storage Our Golden Triangle Storage project consists of a salt-dome storage facility in the Gulf Coast region of the U.S. designed for 13 Bcf of working natural gas capacity and total cavern capacity of 19 Bcf. The first cavern with 6 Bcf of working capacity was completed and began commercial service in September 2010. Golden Triangle Storage expects the second cavern will now consist of approximately 7 Bcf of working capacity and is expected to be placed into commercial service in 2012. Our estimate to complete both caverns, based on current prices for labor, materials and pad gas, is approximately $325 million. We spent approximately $6 million in capital expenditures for this project for the six months ended June 30, 2011 and $71 million for the same period last year.
At June 30, 2011, of the approximate 6 Bcf of working natural gas capacity available for subscription, Golden Triangle Storage had 2 Bcf of capacity subscribed with a third party and 2 Bcf under contract with Sequent. In July 2011, Golden Triangle Storage completed an agreement with a third party for the remaining 2 Bcf of working natural gas capacity. Accordingly, cavern one at Golden Triangle Storage has no remaining capacity available for subscription until March 2013.
Jefferson Island In June 2010, Jefferson Island filed a permit application with the Louisiana Department of Natural Resources to expand its natural gas storage facility through the addition of two caverns. We continue to seek approval to expand our storage facility; however, we cannot predict when this approval will be obtained. The caverns would expand the working gas capacity at Jefferson Island from 7.5 Bcf to approximately 19.5 Bcf.
Energy Marketing Activities
Sequent’s expected natural gas withdrawals from physical salt dome and reservoir storage are presented in the following table along with the operating revenues expected at the time of withdrawal for June 2011 and June 2010. Sequent’s expected operating revenues are net of the estimated impact of profit sharing and reflect the amounts that are realizable in future periods based on its expected inventory withdrawal schedule and forward natural gas prices at June 30, 2011 and 2010. A portion of Sequent’s storage inventory is economically hedged with futures contracts, which results in realization of substantially fixed operating revenues, timing notwithstanding.
| |
|
Withdrawal schedule
|
|
|
|
|
| |
|
(in Bcf)
|
|
|
Expected
|
|
| |
|
Salt dome (WACOG $4.12)
|
|
|
Reservoir (WACOG $4.18)
|
|
|
operating revenues
(in millions)
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
Third quarter
|
|
|
0 |
|
|
|
9 |
|
|
$ |
2 |
|
|
Fourth quarter
|
|
|
3 |
|
|
|
10 |
|
|
|
4 |
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter
|
|
|
1 |
|
|
|
6 |
|
|
|
5 |
|
|
Total at June 30, 2011
|
|
|
4 |
|
|
|
25 |
|
|
$ |
11 |
|
|
Total at June 30, 2010
|
|
|
3 |
|
|
|
29 |
|
|
$ |
25 |
|
If Sequent’s storage withdrawals associated with existing inventory positions are executed as planned, it expects operating revenues from storage withdrawals of approximately $11 million during the next twelve months. This will change as Sequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months and as forward NYMEX prices fluctuate.
Asset Management Transactions
In March 2011, the New Jersey BPU authorized the renewal of the asset management agreement between Elizabethtown Gas and Sequent. Expiring in March 2014, the renewed agreement requires Sequent to pay minimum annual fees of $5 million to Elizabethtown Gas and includes overall margin sharing levels of 30% to Sequent and 70% to Elizabethtown Gas.
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 gas, which excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes and the gain or loss on the sale of our assets. These items are included in our calculation of operating income as reflected in our Condensed Consolidated Statements of Income. EBIT is also a non-GAAP measure that includes operating income, other income and expenses. Items that we do not include in EBIT are financing costs, including interest and debt expense and income taxes, each of which we evaluate on a consolidated level.
We believe operating margin is a better indicator than operating revenues for the contribution resulting from customer growth in our distribution operations segment since the cost of gas can vary significantly and is generally billed directly to our customers. We also consider operating margin to be a better indicator in our retail energy operations, wholesale services and energy investments segments since it is a direct measure of operating margin before overhead costs. We believe EBIT is a useful measurement of our operating segments’ performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.
You should not consider operating margin or EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP. In addition, our operating margin or EBIT measures may not be comparable to similarly titled measures from other companies. The following table sets forth a reconciliation of our operating margin to operating income and EBIT to our earnings before income taxes and net income, together with other consolidated financial information for the periods presented.
| |
|
Three months ended June 30,
|
|
|
Six months ended June 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
Change
|
|
|
2011
|
|
|
2010
|
|
|
Change
|
|
|
Operating revenues
|
|
$ |
375 |
|
|
$ |
359 |
|
|
$ |
16 |
|
|
$ |
1,253 |
|
|
$ |
1,362 |
|
|
$ |
(109 |
) |
|
Cost of gas
|
|
|
134 |
|
|
|
141 |
|
|
|
(7 |
) |
|
|
589 |
|
|
|
712 |
|
|
|
(123 |
) |
|
Operating margin (1)
|
|
|
241 |
|
|
|
218 |
|
|
|
23 |
|
|
|
664 |
|
|
|
650 |
|
|
|
14 |
|
|
Operating expenses
|
|
|
181 |
|
|
|
170 |
|
|
|
11 |
|
|
|
366 |
|
|
|
349 |
|
|
|
17 |
|
|
Operating income
|
|
|
60 |
|
|
|
48 |
|
|
|
12 |
|
|
|
298 |
|
|
|
301 |
|
|
|
(3 |
) |
|
Other income
|
|
|
2 |
|
|
|
0 |
|
|
|
2 |
|
|
|
3 |
|
|
|
2 |
|
|
|
1 |
|
|
EBIT (1)
|
|
|
62 |
|
|
|
48 |
|
|
|
14 |
|
|
|
301 |
|
|
|
303 |
|
|
|
(2 |
) |
|
Interest expense, net
|
|
|
32 |
|
|
|
26 |
|
|
|
6 |
|
|
|
61 |
|
|
|
54 |
|
|
|
7 |
|
|
Earnings before income taxes
|
|
|
30 |
|
|
|
22 |
|
|
|
8 |
|
|
|
240 |
|
|
|
249 |
|
|
|
(9 |
) |
|
Income tax expense
|
|
|
11 |
|
|
|
8 |
|
|
|
3 |
|
|
|
87 |
|
|
|
90 |
|
|
|
(3 |
) |
|
Net income
|
|
|
19 |
|
|
|
14 |
|
|
|
5 |
|
|
|
153 |
|
|
|
159 |
|
|
|
(6 |
) |
|
Net income attributable to the noncontrolling interest
|
|
|
1 |
|
|
|
0 |
|
|
|
1 |
|
|
|
11 |
|
|
|
11 |
|
|
|
0 |
|
|
Net income attributable to AGL Resources Inc.
|
|
$ |
18 |
|
|
$ |
14 |
|
|
$ |
4 |
|
|
$ |
142 |
|
|
$ |
148 |
|
|
$ |
(6 |
) |
(1) These are non-GAAP measurements.
For the second quarter of 2011, net income attributable to AGL Resources Inc. increased by $4 million or 29% compared to the same period last year. The increase was primarily the result of higher operating margins at wholesale services and distribution operations. This increase was partially offset by lower operating margins at energy investments and retail energy operations and increased income taxes as a result of higher earnings. Additionally, during the three months ended June 30, 2011, we recorded approximately $13 million ($8 million net of tax) of transaction expenses associated with the proposed merger with Nicor. These costs are expensed as incurred. The variances for each operating segment are contained within the second quarter 2011 compared to second quarter 2010 discussion on the following pages.
For the six months ended June 30, 2011, net income attributable to AGL Resources Inc. decreased by $6 million or 4% compared to the same period last year. The decrease was primarily the result of reduced operating margins at retail energy operations and energy investments, as well as higher operating expenses primarily at distribution operations. This decrease was partially offset by higher operating margins at distribution operations and wholesale services and decreased income taxes as a result of lower year to date earnings. Additionally, during the six months ended June 30, 2011, we recorded approximately $18 million ($11 million net of tax) of transaction expenses associated with the proposed merger with Nicor. These costs are expensed as incurred. The variances for each operating segment are contained within the year-to-date 2011 compared to year-to-date 2010 discussion on the following pages.
Our income tax expense increased by $3 million or 38% for the second quarter of 2011 compared to the second quarter of 2010. This was primarily due to higher consolidated earnings. Our income tax expense decreased by $3 million or 3% for the six months ending June 30, 2011 compared to the same period of 2010. Our income tax expense is determined from earnings before income taxes less net income attributable to the noncontrolling interest.
Selected weather, customer and volume metrics, which we consider to be some of the key performance indicators for our operating segments, for the three and six months ended June 30, 2011 and 2010, are presented in the following tables. We measure the effects of weather on our business through Heating Degree Days. Generally, increased Heating Degree Days result in greater demand for gas on our distribution systems. However, extended and unusually mild weather during the Heating Season can have a significant negative impact on demand for natural gas. Our customer metrics highlight the average number of customers to which we provide services. This number of customers can be impacted by natural gas prices, economic conditions and competition from alternative fuels.
Volume metrics for distribution operations and retail energy operations present the effects of weather and our customers’ demand for natural gas. Wholesale services’ daily physical sales represent the daily average natural gas volumes sold to its customers. Within our energy investments 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.
|
Weather
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heating degree days (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Three months ended
June 30,
|
|
|
2011 vs. normal colder
|
|
|
2011 vs. 2010 colder |
|
Six months ended
June 30,
|
2011 vs. normal colder
|
|
|
2011 vs. 2010 colder
|
|
|
| |
|
Normal
|
|
|
2011
|
|
|
2010
|
|
|
(warmer)
|
|
|
(warmer) |
|
Normal
|
|
|
2011
|
|
|
2010
|
|
|
(warmer)
|
|
|
(warmer)
|
|
|
|
Georgia
|
|
|
142 |
|
|
|
130 |
|
|
|
70 |
|
|
|
(8 |
)% |
|
|
86 |
% |
|
|
1,640 |
|
|
|
1,600 |
|
|
|
2,022 |
|
|
|
(2 |
)% |
|
|
(21 |
)% |
|
New Jersey
|
|
|
472 |
|
|
|
379 |
|
|
|
325 |
|
|
|
(20 |
)% |
|
|
17 |
% |
|
|
3,000 |
|
|
|
2,928 |
|
|
|
2,722 |
|
|
|
(2 |
)% |
|
|
8 |
% |
|
Virginia
|
|
|
260 |
|
|
|
183 |
|
|
|
192 |
|
|
|
(30 |
)% |
|
|
(5 |
)% |
|
|
2,089 |
|
|
|
2,091 |
|
|
|
2,221 |
|
|
|
0 |
% |
|
|
(6 |
)% |
|
Florida
|
|
|
14 |
|
|
|
3 |
|
|
|
1 |
|
|
|
(79 |
)% |
|
|
200 |
% |
|
|
377 |
|
|
|
244 |
|
|
|
743 |
|
|
|
(35 |
)% |
|
|
(67 |
)% |
|
Tennessee
|
|
|
173 |
|
|
|
173 |
|
|
|
94 |
|
|
|
0 |
% |
|
|
84 |
% |
|
|
1,864 |
|
|
|
1,846 |
|
|
|
2,210 |
|
|
|
(1 |
)% |
|
|
(16 |
)% |
|
Maryland
|
|
|
479 |
|
|
|
366 |
|
|
|
375 |
|
|
|
(24 |
)% |
|
|
(2 |
)% |
|
|
3,000 |
|
|
|
2,996 |
|
|
|
2,852 |
|
|
|
0 |
% |
|
|
5 |
% |
|
Ohio
|
|
|
432 |
|
|
|
394 |
|
|
|
294 |
|
|
|
(9 |
)% |
|
|
34 |
% |
|
|
3,031 |
|
|
|
3,010 |
|
|
|
3,125 |
|
|
|
(1 |
)% |
|
|
(4 |
)% |
|
(1)
|
Obtained from weather stations relevant to our service areas at the National Oceanic and Atmospheric Administration, National Climatic Data Center. Normal represents ten-year averages from 2002 through June 30, 2011. |
| |
|
|
Customers
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
|
|
|
| |
|
2011
|
|
|
2010
|
|
|
% change
|
|
|
2011
|
|
|
2010
|
|
|
% change
|
|
|
Distribution Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average end-use customers (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlanta Gas Light
|
|
|
1,552 |
|
|
|
1,560 |
|
|
|
(0.5 |
)% |
|
|
1,561 |
|
|
|
1,564 |
|
|
|
(0.2 |
)% |
|
Elizabethtown Gas
|
|
|
276 |
|
|
|
274 |
|
|
|
0.7 |
% |
|
|
276 |
|
|
|
275 |
|
|
|
0.4 |
% |
|
Virginia Natural Gas
|
|
|
278 |
|
|
|
275 |
|
|
|
1.1 |
% |
|
|
279 |
|
|
|
276 |
|
|
|
1.1 |
% |
|
Florida City Gas
|
|
|
104 |
|
|
|
104 |
|
|
|
0.0 |
% |
|
|
104 |
|
|
|
104 |
|
|
|
0.0 |
% |
|
Chattanooga Gas
|
|
|
62 |
|
|
|
62 |
|
|
|
0.0 |
% |
|
|
62 |
|
|
|
62 |
|
|
|
0.0 |
% |
|
Elkton Gas
|
|
|
6 |
|
|
|
6 |
|
|
|
0.0 |
% |
|
|
6 |
|
|
|
6 |
|
|
|
0.0 |
% |
|
Total
|
|
|
2,278 |
|
|
|
2,281 |
|
|
|
(0.1 |
)% |
|
|
2,288 |
|
|
|
2,287 |
|
|
|
0.0 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail Energy Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average customers (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Georgia
|
|
|
492 |
|
|
|
503 |
|
|
|
(2 |
)% |
|
|
495 |
|
|
|
505 |
|
|
|
(2 |
)% |
|
Ohio and Florida (2)
|
|
|
95 |
|
|
|
71 |
|
|
|
34 |
% |
|
|
84 |
|
|
|
88 |
|
|
|
(5 |
)% |
|
Total
|
|
|
587 |
|
|
|
574 |
|
|
|
2 |
% |
|
|
579 |
|
|
|
593 |
|
|
|
(2 |
)% |
|
Market share in Georgia
|
|
|
32 |
% |
|
|
33 |
% |
|
|
(3 |
)% |
|
|
32 |
% |
|
|
33 |
% |
|
|
(3 |
)% |
|
(2)
|
A portion of the Ohio customers represents customer equivalents, which are computed by the actual delivered volumes divided by the expected average customer usage. |
| |
|
Volumes
In billion cubic feet (Bcf)
|
|
Three months ended June 30,
|
|
|
|
|
|
Six months ended June 30,
|
|
|
|
|
| |
|
2011
|
|
|
2010
|
|
|
% change
|
|
|
2011
|
|
|
2010
|
|
|
% change
|
|
|
Distribution Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm
|
|
|
26 |
|
|
|
26 |
|
|
|
0 |
% |
|
|
128 |
|
|
|
148 |
|
|
|
(14 |
)% |
|
Interruptible
|
|
|
26 |
|
|
|
22 |
|
|
|
18 |
% |
|
|
53 |
|
|
|
49 |
|
|
|
8 |
% |
|
Total
|
|
|
52 |
|
|
|
48 |
|
|
|
8 |
% |
|
|
181 |
|
|
|
197 |
|
|
|
(8 |
)% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail Energy Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Georgia firm
|
|
|
4 |
|
|
|
4 |
|
|
|
0 |
% |
|
|
22 |
|
|
|
28 |
|
|
|
(21 |
)% |
|
Ohio and Florida
|
|
|
1 |
|
|
|
1 |
|
|
|
0 |
% |
|
|
5 |
|
|
|
7 |
|
|
|
(29 |
)% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily physical sales (Bcf/day)
|
|
|
4.7 |
|
|
|
3.9 |
|
|
|
21 |
% |
|
|
5.2 |
|
|
|
4.4 |
|
|
|
18 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
As of June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
2011 |
|
|
|
2010 |
|
|
% change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working natural gas capacity
|
|
|
13.5 |
|
|
|
7.5 |
|
|
|
80 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
% of capacity under subscription (3)
|
|
|
74 |
% |
|
|
92 |
% |
|
|
(20 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3)
|
The percentage of capacity under subscription includes the 4 Bcf of capacity under contract with Sequent at June 30, 2011 and 2 Bcf of capacity under contract with Sequent at June 30, 2010.
|
Second quarter 2011 compared to second quarter 2010
Operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the three months ended June 30, 2011 and 2010.
| |
|
2011
|
|
|
2010
|
|
|
In millions
|
|
Operating margin (1)
|
|
|
Operating expenses
|
|
|
EBIT (1)
|
|
|
Operating margin (1)
|
|
|
Operating expenses
|
|
|
EBIT (1)
|
|
|
Distribution operations
|
|
$ |
208 |
|
|
$ |
133 |
|
|
$ |
76 |
|
|
$ |
198 |
|
|
$ |
130 |
|
|
$ |
69 |
|
|
Retail energy operations
|
|
|
17 |
|
|
|
16 |
|
|
|
1 |
|
|
|
18 |
|
|
|
17 |
|
|
|
1 |
|
|
Wholesale services
|
|
|
8 |
|
|
|
13 |
|
|
|
(5 |
) |
|
|
(9 |
) |
|
|
11 |
|
|
|
(20 |
) |
|
Energy investments
|
|
|
8 |
|
|
|
7 |
|
|
|
1 |
|
|
|
12 |
|
|
|
11 |
|
|
|
0 |
|
|
Corporate (2)
|
|
|
0 |
|
|
|
12 |
|
|
|
(11 |
) |
|
|
(1 |
) |
|
|
1 |
|
|
|
(2 |
) |
|
Consolidated
|
|
$ |
241 |
|
|
$ |
181 |
|
|
$ |
62 |
|
|
$ |
218 |
|
|
$ |
170 |
|
|
$ |
48 |
|
|
(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.
|
|
(2)
|
The increase in operating expenses of $11 million is primarily due to transaction expenses associated with the proposed merger with Nicor. For more information see Note 3. Additionally, includes intercompany eliminations.
|
Distribution operations’ EBIT increased by $7 million or 10% compared to last year as shown in the following table.
|
In millions
|
|
|
|
|
|
|
|
EBIT for second quarter of 2010
|
|
|
|
|
$ |
69 |
|
| |
|
|
|
|
|
|
|
|
Operating margin
|
|
|
|
|
|
|
|
|
Increased revenues from new rates and regulatory infrastructure program revenues at Atlanta Gas Light
|
|
$ |
8 |
|
|
|
|
|
|
Increased revenues from customer growth, higher usage and enhanced infrastructure program revenues at Elizabethtown Gas
|
|
|
2 |
|
|
|
|
|
|
Increase in operating margin
|
|
|
|
|
|
|
10 |
|
| |
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
Increased compensation expenses
|
|
$ |
2 |
|
|
|
|
|
|
Increased pension expense
|
|
|
1 |
|
|
|
|
|
|
Increased depreciation expense
|
|
|
1 |
|
|
|
|
|
|
Decreased bad debt and other expenses
|
|
|
(1 |
) |
|
|
|
|
|
Increase in operating expenses
|
|
|
|
|
|
|
3 |
|
|
EBIT for second quarter of 2011
|
|
|
|
|
|
$ |
76 |
|
Retail energy operations’ EBIT was flat compared to last year as shown in the following table.
|
In millions
|
|
|
|
|
|
|
|
EBIT for second quarter of 2010
|
|
|
|
|
$ |
1 |
|
| |
|
|
|
|
|
|
|
|
Operating margin
|
|
|
|
|
|
|
|
|
Increased average customer usage due to weather
|
|
$ |
1 |
|
|
|
|
|
|
Decrease related to retail pricing plan mix and optimization of storage and transportation
|
|
|
(1 |
) |
|
|
|
|
|
Other
|
|
|
(1 |
) |
|
|
|
|
|
Decrease in operating margin
|
|
|
|
|
|
|
(1 |
) |
| |
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
Decreased bad debt and other expenses
|
|
$ |
(1 |
) |
|
|
|
|
|
Decrease in operating expenses
|
|
|
|
|
|
|
(1 |
) |
|
EBIT for second quarter of 2011
|
|
|
|
|
|
$ |
1 |
|
Wholesale services’ EBIT increased by $15 million or 75% compared to last year as shown in the following table.
|
In millions
|
|
|
|
|
|
|
|
EBIT for second quarter of 2010
|
|
|
|
|
$ |
(20 |
) |
| |
|
|
|
|
|
|
|
|
Operating margin
|
|
|
|
|
|
|
|
|
Change in commercial activity
|
|
$ |
1 |
|
|
|
|
|
|
Change in transportation hedge movements from the narrowing of transportation basis spreads in 2011 as compared to the widening of transportation basis spreads in 2010
|
|
|
10 |
|
|
|
|
|
|
Change in storage hedge movements as a result of changing NYMEX natural gas prices
|
|
|
6 |
|
|
|
|
|
|
Increase in operating margin
|
|
|
|
|
|
|
17 |
|
| |
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
Increased incentive compensation, payroll and other employee related costs
|
|
$ |
2 |
|
|
|
|
|
|
Increase in operating expenses
|
|
|
|
|
|
|
2 |
|
|
EBIT for second quarter of 2011
|
|
|
|
|
|
$ |
(5 |
) |
The following table indicates the components of wholesale services’ operating margin for the three months ended June 30, 2011 and 2010.
|
In millions
|
|
2011
|
|
|
2010
|
|
|
Gain (loss) on transportation hedges
|
|
$ |
4 |
|
|
$ |
(6 |
) |
|
Gain (loss) on storage hedges
|
|
|
4 |
|
|
|
(2 |
) |
|
Commercial activity recognized
|
|
|
- |
|
|
|
(1 |
) |
|
Operating margin
|
|
$ |
8 |
|
|
$ |
(9 |
) |
Energy investments’ EBIT increased by $1 million compared to last year as shown in the following table.
|
In millions
|
|
|
|
|
|
|
|
EBIT for second quarter of 2010
|
|
|
|
|
$ |
0 |
|
| |
|
|
|
|
|
|
|
|
Operating margin
|
|
|
|
|
|
|
|
|
Decreased operating revenues due to sale of AGL Networks, LLC
|
|
$ |
(5 |
) |
|
|
|
|
|
Increased revenues at Golden Triangle Storage as a result of the start of commercial service in September 2010
|
|
|
1 |
|
|
|
|
|
|
Decrease in operating margin
|
|
|
|
|
|
|
(4 |
) |
| |
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
Decreased operating expenses due to sale of AGL Networks, LLC
|
|
$ |
(6 |
) |
|
|
|
|
|
Increase in operating and depreciation expenses at Golden Triangle Storage as a result of the start of commercial service in September 2010
|
|
|
2 |
|
|
|
|
|
|
Decrease in operating expenses
|
|
|
|
|
|
|
(4 |
) |
|
Increase in other income
|
|
|
|
|
|
|
1 |
|
|
EBIT for second quarter of 2011
|
|
|
|
|
|
$ |
1 |
|
Year-to-date 2011 compared to Year-to-date 2010
Operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the six months ended June 30, 2011 and 2010.
| |
|
2011
|
|
|
2010
|
|
|
In millions
|
|
Operating margin (1)
|
|
|
Operating expenses
|
|
|
EBIT (1)
|
|
|
Operating margin (1)
|
|
|
Operating expenses
|
|
|
EBIT (1)
|
|
|
Distribution operations
|
|
$ |
483 |
|
|
$ |
268 |
|
|
$ |
217 |
|
|
$ |
462 |
|
|
$ |
260 |
|
|
$ |
205 |
|
|
Retail energy operations
|
|
|
106 |
|
|
|
37 |
|
|
|
69 |
|
|
|
114 |
|
|
|
39 |
|
|
|
75 |
|
|
Wholesale services
|
|
|
58 |
|
|
|
30 |
|
|
|
28 |
|
|
|
50 |
|
|
|
27 |
|
|
|
23 |
|
|
Energy investments
|
|
|
17 |
|
|
|
15 |
|
|
|
2 |
|
|
|
24 |
|
|
|
20 |
|
|
|
3 |
|
|
Corporate (2)
|
|
|
0 |
|
|
|
16 |
|
|
|
(15 |
) |
|
|
0 |
|
|
|
3 |
|
|
|
(3 |
) |
|
Consolidated
|
|
$ |
664 |
|
|
$ |
366 |
|
|
$ |
301 |
|
|
$ |
650 |
|
|
$ |
349 |
|
|
$ |
303 |
|
|
(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.
|
|
(2)
|
The increase in operating expenses of $13 million is primarily due to transaction expenses associated with the proposed merger with Nicor. For more information see Note 3. Additionally, includes intercompany eliminations.
|
Distribution operations’ EBIT increased by $12 million or 6% compared to last year as shown in the following table.
|
In millions
|
|
|
|
|
|
|
|
EBIT for six months of 2010
|
|
|
|
|
$ |
205 |
|
| |
|
|
|
|
|
|
|
|
Operating margin
|
|
|
|
|
|
|
|
|
Increased revenues from new rates and regulatory infrastructure program revenues at Atlanta Gas Light
|
|
$ |
17 |
|
|
|
|
|
|
Increased revenues from customer growth, higher usage and enhanced infrastructure program revenues at Elizabethtown Gas
|
|
|
5 |
|
|
|
|
|
|
Decreased revenues from lower usage at Florida City Gas due to warmer weather in the first quarter of 2011
|
|
|
(1 |
) |
|
|
|
|
|
Increase in operating margin
|
|
|
|
|
|
|
21 |
|
| |
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
Increased compensation expenses
|
|
$ |
5 |
|
|
|
|
|
|
Increased pension expense
|
|
|
2 |
|
|
|
|
|
|
Increased depreciation expense
|
|
|
3 |
|
|
|
|
|
|
Decreased bad debt and other expenses
|
|
|
(2 |
) |
|
|
|
|
|
Increase in operating expenses
|
|
|
|
|
|
|
8 |
|
|
Decrease in other income
|
|
|
|
|
|
|
(1 |
) |
|
EBIT for six months of 2011
|
|
|
|
|
|
$ |
217 |
|
Retail energy operations’ EBIT decreased by $6 million or 8% compared to last year as shown in the following table.
|
In millions
|
|
|
|
|
|
|
|
EBIT for six months of 2010
|
|
|
|
|
$ |
75 |
|
| |
|
|
|
|
|
|
|
|
Operating margin
|
|
|
|
|
|
|
|
|
Decreased average customer usage due to warmer weather mainly in the first quarter of 2011
|
|
$ |
(3 |
) |
|
|
|
|
|
Decrease related to retail pricing plan mix and optimization of storage and transportation
|
|
|
(3 |
) |
|
|
|
|
|
Other
|
|
|
(2 |
) |
|
|
|
|
|
Decrease in operating margin
|
|
|
|
|
|
|
(8 |
) |
| |
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
Decreased bad debt and other expenses
|
|
$ |
(2 |
) |
|
|
|
|
|
Decrease in operating expenses
|
|
|
|
|
|
|
(2 |
) |
|
EBIT for six months of 2011
|
|
|
|
|
|
$ |
69 |
|
Wholesale services’ EBIT increased by $5 million or 22% compared to last year as shown in the following table.
|
In millions
|
|
|
|
|
|
|
|
EBIT for six months of 2010
|
|
|
|
|
$ |
23 |
|
| |
|
|
|
|
|
|
|
|
Operating margin
|
|
|
|
|
|
|
|
|
Change in commercial activity
|
|
$ |
17 |
|
|
|
|
|
|
Change in LOCOM adjustment
|
|
|
2 |
|
|
|
|
|
|
Change in storage hedge gains as a result of changing NYMEX natural gas prices
|
|
|
(12 |
) |
|
|
|
|
|
Change in transportation hedge gains due to narrowing of transportation basis spreads
|
|
|
1 |
|
|
|
|
|
|
Increase in operating margin
|
|
|
|
|
|
|
8 |
|
| |
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
Increased incentive compensation costs slightly offset by lower operating expenses
|
|
$ |
3 |
|
|
|
|
|
|
Increase in operating expenses
|
|
|
|
|
|
|
3 |
|
|
EBIT for six months of 2011
|
|
|
|
|
|
$ |
28 |
|
The following table indicates the components of wholesale services’ operating margin for the six months ended June 30, 2011 and 2010.
|
In millions
|
|
2011
|
|
|
2010
|
|
|
Commercial activity recognized
|
|
$ |
52 |
|
|
$ |
35 |
|
|
Gain on transportation hedges
|
|
|
4 |
|
|
|
3 |
|
|
Gain on storage hedges
|
|
|
2 |
|
|
|
14 |
|
|
Inventory LOCOM adjustment, net of estimated current period recoveries
|
|
|
0 |
|
|
|
(2 |
) |
|
Operating margin
|
|
$ |
58 |
|
|
$ |
50 |
|
Energy investments’ EBIT decreased by $1 million compared to last year as shown in the following table.
|
In millions
|
|
|
|
|
|
|
|
EBIT for six months of 2010
|
|
|
|
|
$ |
3 |
|
| |
|
|
|
|
|
|
|
|
Operating margin
|
|
|
|
|
|
|
|
|
Decreased operating revenues due to sale of AGL Networks, LLC
|
|
$ |
(11 |
) |
|
|
|
|
|
Increased revenues at Golden Triangle Storage as a result of the start of commercial service in September 2010
|
|
|
4 |
|
|
|
|
|
|
Decrease in operating margin
|
|
|
|
|
|
|
(7 |
) |
| |
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
Decreased operating expenses due to sale of AGL Networks, LLC
|
|
$ |
(9 |
) |
|
|
|
|
|
Increase in operating and depreciation expenses at Golden Triangle Storage as a result of the start of commercial service in September 2010
|
|
|
4 |
|
|
|
|
|
|
Decrease in operating expenses
|
|
|
|
|
|
|
(5 |
) |
|
Decrease in other expense
|
|
|
|
|
|
|
(1 |
) |
|
EBIT for six months of 2011
|
|
|
|
|
|
$ |
2 |
|
Overview The acquisition of natural gas, pipeline capacity, payment of dividends and working capital requirements 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 by cash from operations are primarily satisfied with short-term borrowings under our commercial paper program, which is supported by our 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.
Our capital market strategy has continued to focus on maintaining a strong Consolidated Statement 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 combination of equity or long-term debt securities.
Our issuance of various securities, including long-term and short-term debt and equity, is subject to customary approval or review by state and federal regulatory bodies including the various public service commissions of the states in which we conduct business, the SEC and the FERC. Furthermore, a substantial portion of our consolidated assets, earnings and cash flow are derived from the operation of our regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation.
We believe the amounts available to us under our senior notes, Credit Facility and Bridge 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, construction expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments, common share repurchases, financing requirements for the proposed Nicor merger and other cash needs through the next several years. Our ability to satisfy our working capital requirements and 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 natural gas, the demand for natural gas and operational risks.
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, the proposed merger with Nicor and other factors. See Item 1A, “Risk Factors,” of our 2010 Form 10-K, for additional information on items that could impact our liquidity and capital resource requirements.
Our capitalization and financing strategy is intended to ensure that we are properly capitalized with the appropriate mix of equity and debt securities. This strategy includes active management of the percentage of total debt relative to total capitalization, appropriate mix of debt with fixed to floating interest rates (our variable-rate debt target is 20% to 45% of total debt), as well as the term and interest rate profile of our debt securities. As of June 30, 2011, our variable-rate debt was 24% of our total debt, compared to 19% as of June 30, 2010.
Proposed Merger Financing On the date of the merger, each outstanding share of Nicor common stock, other than shares to be cancelled and Dissenting Shares, as defined in the Merger Agreement, will be converted into the right to receive consideration of (i) 0.8382 of a share of our common stock and (ii) $21.20 in cash. The value of the consideration to be paid to Nicor shareholders is equal to $2.6 billion based upon the closing price of our common stock on the New York Stock Exchange on July 29, 2011 and the amount of Nicor shares outstanding as of March 31, 2011; however, this amount will fluctuate with changes in the price of our common stock. A 10% change in the market price of our common stock would increase or decrease the total consideration by approximately $158 million, which would be reflected as an increase in or decrease to the purchase price to be paid to the shareholders of Nicor. We anticipate incurring indebtedness in connection with financing the cash portion of the purchase price equal to approximately $980 million, and for transaction fees and expenses. At the closing of the proposed Nicor merger, we will also assume all of Nicor’s outstanding debt, which was approximately $650 million at March 31, 2011.
In December 2010, we entered into a 364-day Bridge Facility to provide temporary financing in the event that permanent financing cannot be completed prior to date of the proposed merger. The Bridge Facility allowed us to borrow up to $1.05 billion, with proceeds to be used to fund the cash portion of our proposed merger and pay related fees and expenses. Following our issuance of the March 2011 senior notes, the principal amount of the Bridge Facility was reduced from $1.05 billion to approximately $852 million.
We have secured, and are in the process of securing the permanent debt financing for the cash portion of the purchase price. This includes approximately $200 million from our $500 million in senior notes that were issued in March 2011. Additionally, we are finalizing documentation with various institutional investors in the private placement market for $275 million in senior unsecured notes. When issued, we expect the senior unsecured notes to include $120 million of Series A senior notes due 2016, and $155 million of Series B senior notes due 2018. We anticipate the notes will be issued in conjunction with the closing of the Nicor merger, but in any event on or prior to December 31, 2011, subject to the satisfaction of customary closing conditions. The Bridge Facility will be further reduced by the net proceeds of this issuance of senior unsecured notes.
Credit Ratings Our borrowing costs and ability to obtain adequate and cost effective financing are directly impacted by our credit ratings as well as the availability of financial markets. In addition, credit ratings are important to counterparties when we engage in certain transactions including over-the-counter derivatives. It is our long-term objective to maintain or improve our credit ratings on our debt 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. Each rating should be evaluated independently of any other rating. The rating agencies regularly review our performance, prospects and financial condition and reevaluate their ratings of our long-term debt and short-term borrowings, including our corporate ratings. 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.
Factors we consider important in assessing our credit ratings include our Statements of Financial Position leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any trigger events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any agreements that would require us to issue equity based on credit ratings or other trigger events. The following table summarizes our credit ratings as of June 30, 2011, and reflects no change from December 31, 2010.
| |
|
S&P
|
|
|
Moody’s
|
|
|
Fitch
|
|
|
Corporate rating
|
|
A- |
|
|
|
|
|
A- |
|
|
Commercial paper
|
|
A-2 |
|
|
P-2 |
|
|
F2 |
|
|
Senior unsecured
|
|
BBB+
|
|
|
Baa1
|
|
|
A- |
|
|
Ratings outlook
|
|
Negative
|
|
|
Stable
|
|
|
Stable
|
|
In December 2010, subsequent to the announcement of our proposed merger with Nicor, S&P placed our long-term debt ratings and our corporate credit ratings on credit watch with negative implications. The primary reason for this change is the increased leverage we will assume to complete the proposed merger and the uncertainties that exist with the proposed merger.
Our credit ratings depend largely on our financial performance, and a downgrade in our current ratings, particularly below investment grade, could adversely affect our borrowing costs and significantly 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 would decrease.
Default provisions As of June 30, 2011, December 31, 2010 and June 30, 2010, we were in compliance with all of our debt provisions and covenants, both financial and non-financial. Additionally, our Bridge Facility contains the same financial covenant and similar non-financial covenants and default provisions as contained in our Credit Facility; however, most of these are not in effect until we draw under the facility.
Our ratio, on a consolidated basis, of total debt to total capitalization 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 intend to maintain our capitalization ratio 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 7. The components of our capital structure, as calculated from our Condensed Consolidated Statements of Financial Position, as of the dates indicated, are provided in the following table.
| |
|
Jun. 30, 2011
|
|
|
Dec. 31, 2010
|
|
|
Jun. 30, 2010
|
|
|
Short-term debt
|
|
|
4 |
% |
|
|
23 |
% |
|
|
17 |
% |
|
Long-term debt
|
|
|
51 |
|
|
|
37 |
|
|
|
38 |
|
|
Total debt
|
|
|
55 |
|
|
|
60 |
|
|
|
55 |
|
|
Equity
|
|
|
45 |
|
|
|
40 |
|
|
|
45 |
|
|
Total capitalization
|
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
Cash Flows
The following table provides a summary of our operating, investing and financing cash flows for the periods presented.
| |
|
Six months ended June 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
Operating activities
|
|
$ |
660 |
|
|
$ |
715 |
|
|
Investing activities
|
|
|
(196 |
) |
|
|
(251 |
) |
|
Financing activities
|
|
|
(467 |
) |
|
|
(474 |
) |
|
Net decrease in cash and cash equivalents
|
|
$ |
(3 |
) |
|
$ |
(10 |
) |
Cash Flow from Operating Activities In the first six months of 2011, our net cash flow provided from operating activities was $660 million, a decrease of $55 million or 8% from the same period in 2010. This decrease was primarily a result of fluctuations associated with working capital variances in the ordinary course of business, driven by an increased use of $59 million in cash from our net energy marketing receivables and payables due to increased purchases of natural gas and a $17 million decrease in cash received from our inventories primarily driven by lower weighted average cost of gas inventory sold in 2011 compared to 2010. Additionally, we had a $44 million decrease in operating cash flow from loaned gas activities associated with park and loan gas transactions in part due to fewer opportunities resulting from a weakening of storage price differentials. Offsetting these decreases was an increase in cash of $25 million from deferred natural gas costs as a result of fluctuations in natural gas prices as well as an increase in cash of $29 million in trade payables primarily due to decreased capital spending.
Cash Flow from Investing Activities Our investing activities consisted of PP&E expenditures of $196 million for the six months ended June 30, 2011 compared to $249 million for the same period in 2010. The decrease of $53 million or 21% in PP&E expenditures was primarily due to a $65 million decrease in expenditures for the construction of the Golden Triangle Storage natural gas storage facility due to the completion of base infrastructure spending and completion of the first cavern, a $23 million decrease in expenditures for utility infrastructure enhancements at Elizabethtown Gas due to the initial program ending and an $8 million reduction in expenditures for AGL Networks projects which was sold in July 2010. This was offset by increased expenditures of $39 million for STRIDE.
Cash Flow from Financing Activities
Short-term debt Our short-term debt during the six months was composed of borrowings and payments under our Credit Facility and commercial paper program, Term Loan Facility, the current portion of our capital leases and our senior notes maturing in less than one year.
|
In millions
|
|
Period end balance outstanding (1)
|
|
|
Daily average balance outstanding (2)
|
|
|
Largest
balance outstanding (2)
|
|
|
Commercial paper
|
|
$ |
142 |
|
|
$ |
318 |
|
|
$ |
835 |
|
|
Current portion of long-term debt
|
|
|
10 |
|
|
|
24 |
|
|
|
300 |
|
|
Capital leases
|
|
|
2 |
|
|
|
2 |
|
|
|
2 |
|
|
Term loan facility
|
|
|
0 |
|
|
|
25 |
|
|
|
150 |
|
|
(2)
|
For the six months ended June 30, 2011.
|
The largest amounts borrowed on our commercial paper borrowings are important when assessing the intra-period fluctuation of our short-term borrowings and any potential liquidity risk. Our short-term debt financing generally increases between June and December as we purchase natural gas in advance of the Heating Season. The variation of when we pay our suppliers for natural gas purchases and when we recover our costs from our customers through their monthly bills can significantly affect our short-term cash requirements. Our short-term debt balances are typically reduced during the Heating Season because a significant portion of our current assets, primarily natural gas inventories, are converted into cash.
During the six months ended June 30, of 2011, our short-term debt balances were also impacted by our $300 million senior notes, which were current at December 31, 2010 and matured in January 2011. These senior notes were initially repaid with a $150 million funding under our Term Loan Facility and borrowings under our commercial paper program.
In February 2011, the Term Loan Facility was repaid through additional commercial paper borrowings at which time the Term Loan Facility expired. In March 2011, we completed a new $500 million senior note offering, using a portion of the proceeds to reduce outstanding commercial paper to $142 million at June 30, 2011, as compared to $732 million at December 31, 2010 and $393 million at June 30, 2010.
The timing of natural gas withdrawals is dependent on the weather and natural gas market conditions, both of which impact the price of natural gas. Increasing natural gas commodity prices can have a significant impact on our commercial paper borrowings. Based on current natural gas prices and our expected purchases during the upcoming injection season, we have sufficient liquidity to cover our working capital needs for the upcoming Heating Season.
The lenders under our Credit Facility and Bridge Facility are all major financial institutions with approximately $2.1 billion of committed balances and all have investment grade credit ratings as of June 30, 2011. It is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal. As of June 30, 2011 and 2010, we had no outstanding borrowings on our Credit Facility or Bridge Facility.
Long-term debt Our long-term debt matures more than one year from the date of our Statements of Financial Position and consists of medium-term notes, senior notes and gas facility revenue bonds.
In March 2011, we completed a public offering of $500 million 30 year senior notes with an interest rate of 5.9%. A portion of the net proceeds of this offering was used to pay down the commercial paper borrowings that were used to repay the $300 million of senior notes that matured in January 2011. Additionally, as previously discussed the remaining proceeds are expected to be used to pay a portion of the cash consideration and expenses incurred in connection with the proposed merger with Nicor, if completed, or for other general corporate purposes.
Noncontrolling Interest We recorded a cash distribution for SouthStar’s dividends paid to Piedmont of $16 million for the six months ended June 30, 2011 and $27 million for the six months ended June 30, 2010. The primary reason for the reduction in the distribution to Piedmont is due to our increased ownership percentage in SouthStar in 2010, as the current year distribution was paid on 2010 earnings and the 2010 distribution was paid on the 2009 earnings.
Dividends on Common Stock Our common stock dividend payments were $68 million for the six months ended June 30, 2011 and $66 million for the six months ended June 30, 2010. The increase was generally the result of an annual dividend increase of $0.04 per share last year. For information about restrictions on our ability to pay dividends on our common stock, see Note 2.
Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities that are reasonably likely to have a material effect on liquidity or the availability of 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.
Pension Contributions In the first six months of 2011 we contributed $44 million to our qualified pension plans and an additional $6 million in July 2011 for a total of $50 million during 2011. We plan to make additional contributions up to $6 million, for a total of up to $56 million during 2011. Based on the funding status of the plans as of December 31, 2010, we were required to make a minimum contribution to the plans of $30 million in 2011. In the six months ended June 30, 2010, we contributed $21 million to our pension plans and through July 2010, we contributed $26 million.
During the six months ended June 30, 2011, we recorded net periodic benefit costs of $10 million related to our defined pension and postretirement benefit plans compared to $8 million during the same period last year. We estimate that during the remainder of 2011, we will record net periodic pension and other postretirement benefit costs in the range of $9 million to $11 million, a $2 million increase compared to 2010. In determining our estimated expenses for 2011, our actuarial consultant assumed an 8.50% expected return on plan assets and a discount rate of 5.40% for the AGL Retirement Plan and 5.20% for the NUI Retirement Plan and for our postretirement plan.
The following table illustrates our expected future contractual obligation payments such as debt and lease agreements, and commitments and contingencies as of June 30, 2011.
| |
|
|
|
|
|
|
|
2012 &
|
|
|
2014 &
|
|
|
2016 &
|
|
|
In millions
|
|
Total
|
|
|
2011
|
|
|
2013
|
|
|
2015
|
|
|
Thereafter
|
|
|
Recorded contractual obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$ |
2,164 |
|
|
$ |
0 |
|
|
$ |
230 |
|
|
$ |
200 |
|
|
$ |
1,734 |
|
|
Regulatory infrastructure program costs (1)
|
|
|
258 |
|
|
|
27 |
|
|
|
231 |
|
|
|
0 |
|
|
|
0 |
|
|
Environmental remediation liabilities (1)
|
|
|
191 |
|
|
|
7 |
|
|
|
57 |
|
|
|
50 |
|
|
|
77 |
|
|
Short-term debt
|
|
|
154 |
|
|
|
143 |
|
|
|
11 |
|
|
|
0 |
|
|
|
0 |
|
|
Total
|
|
$ |
2,767 |
|
|
$ |
177 |
|
|
$ |
529 |
|
|
$ |
250 |
|
|
$ |
1,811 |
|
|
Unrecorded contractual obligations and commitments (2) (7):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline charges, storage capacity and gas supply (3)
|
|
$ |
1,845 |
|
|
$ |
306 |
|
|
$ |
747 |
|
|
$ |
304 |
|
|
$ |
488 |
|
|
Interest charges (4)
|
|
|
1,692 |
|
|
|
56 |
|
|
|
214 |
|
|
|
190 |
|
|
|
1,232 |
|
|
Operating leases (5)
|
|
|
107 |
|
|
|
12 |
|
|
|
41 |
|
|
|
21 |
|
|
|
33 |
|
|
Asset management agreements (6)
|
|
|
23 |
|
|
|
6 |
|
|
|
16 |
|
|
|
1 |
|
|
|
0 |
|
|
Standby letters of credit, performance / surety bonds
|
|
|
14 |
|
|
|
6 |
|
|
|
8 |
|
|
|
0 |
|
|
|
0 |
|
|
Total
|
|
$ |
3,681 |
|
|
$ |
386 |
|
|
$ |
1,026 |
|
|
$ |
516 |
|
|
$ |
1,753 |
|
|
(1)
|
Includes charges recoverable through rate rider mechanisms. For more on our environmental remediation liabilities, see Note 9.
|
|
(2)
|
In accordance with GAAP, these items are not reflected in our Condensed Consolidated Statements of Financial Position.
|
|
(3)
|
Charges recoverable through a natural gas cost recovery mechanism or alternatively billed to Marketers, and includes demand charges associated with Sequent. Also includes SouthStar’s natural gas purchase commitments of 15 Bcf at floating gas prices calculated using forward natural gas prices as of June 30, 2011, and are valued at $68 million.
|
|
(4)
|
Floating rate debt is based on the interest rate as of June 30, 2011, and the maturity of the underlying debt instrument. As of June 30, 2011, we have $41 million of accrued interest on our Condensed Consolidated Statements of Financial Position that will be paid over the next 12 months.
|
|
(5)
|
We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with authoritative guidance related to leases. However, this lease accounting treatment does not affect the future annual operating lease cash obligations as shown herein. Additionally, minimum payments have not been reduced by minimum sublease rentals of $14 million due in the future under noncancelable subleases.
|
|
(6)
|
Represent fixed-fee minimum payments for Sequent’s asset management agreements.
|
|
(7)
|
The Merger Agreement with Nicor contains termination rights for both us and Nicor and provides that, if we terminate the agreement under specified circumstances, we may be required to pay a termination fee of $67 million. In addition, if we terminate the agreement due to a failure to obtain the necessary financing for the transaction, we may also be required to pay Nicor $115 million.
|
The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience, where applicable, and various other assumptions that we believe to be reasonable under the circumstances. We evaluate our estimates on an ongoing basis, and our actual results may differ from these estimates. Our critical accounting estimates used in the preparation of our Condensed Consolidated Financial Statements include the following:
|
·
|
Regulatory Infrastructure Program Liabilities
|
|
·
|
Environmental Remediation Liabilities
|
|
·
|
Derivatives and Hedging Activities
|
|
·
|
Pension and Other Postretirement Plans
|
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 Operation as filed on our 2010 Form 10-K.
In May 2011, the FASB issued authoritative guidance related to fair value measurements. The guidance expands the qualitative and quantitative disclosures for Level 3 significant unobservable inputs, permits the use of premiums and discounts to value an instrument if it is standard practice and limits best use valuation to non-financial assets and liabilities. This guidance will be effective for us beginning January 1, 2012. We do not expect the guidance to have a material impact on our consolidated financial statements.
In June 2011, the FASB issued authoritative guidance related to comprehensive income. The guidance eliminates the option to present other comprehensive income in the Statements of Equity, but instead allows companies to elect to present net income and other comprehensive income in one continuous statement (Statements of Comprehensive Income) or in two consecutive statements. This guidance does not change any of the components of net income or other comprehensive income and earnings per share will still be calculated based on net income. This guidance will be effective for us beginning January 1, 2012. This guidance will not have a material impact on our consolidated financial statements.
We are exposed to risks associated with natural gas prices, interest rates and credit. Natural gas price risk is defined as the potential loss that we may incur as a result of changes in the fair value of natural gas. Interest rate risk results from our portfolio of debt and equity instruments that we issue to provide financing and liquidity for our business. Credit risk results from the extension of credit throughout all aspects of our business, but is particularly concentrated at Atlanta Gas Light in distribution operations and in wholesale services.
Our Risk Management Committee (RMC) is responsible for establishing the overall risk management policies and monitoring compliance with, and adherence to, the terms within these policies, including approval and authorization levels and delegation of these levels. Our RMC consists of members of senior management who monitor open natural gas price risk positions and other types of risk, corporate exposures, credit exposures and overall results of our risk management activities. It is chaired by our chief risk officer, who is responsible for ensuring that appropriate reporting mechanisms exist for the RMC to perform its monitoring functions. Our risk management activities and related accounting treatment for our derivative financial instruments are described in further detail in Note 5.
The following tables include the fair value and average values of our consolidated derivative financial instruments as of the dates indicated. We base the average values on monthly averages for the six months ended June 30, 2011 and 2010.
| |
|
Derivative financial instruments average values (1) at June 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
Asset
|
|
$ |
195 |
|
|
$ |
228 |
|
|
Liability
|
|
|
41 |
|
|
|
91 |
|
|
(1)
|
Excludes cash collateral amounts.
|
| |
|
Derivative financial instruments fair values netted with cash collateral at
|
|
|
In millions
|
|
Jun. 30,
2011
|
|
|
Dec. 31,
2010
|
|
|
Jun. 30,
2010
|
|
|
Asset
|
|
$ |
152 |
|
|
$ |
228 |
|
|
$ |
209 |
|
|
Liability
|
|
|
29 |
|
|
|
48 |
|
|
|
75 |
|
The following tables illustrate the change in the net fair value of our derivative financial instruments during the periods presented, and provide details of the net fair value of contracts outstanding as of the periods presented.
| |
|
Three months ended
|
|
|
Six months ended
|
|
| |
|
June 30,
|
|
|
June 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
Net fair value of derivative financial instruments outstanding at beginning of period
|
|
$ |
37 |
|
|
$ |
73 |
|
|
$ |
75 |
|
|
$ |
121 |
|
|
Derivative financial instruments realized or otherwise settled during the period
|
|
|
(5 |
) |
|
|
(17 |
) |
|
|
(55 |
) |
|
|
(88 |
) |
|
Change in the net fair value of derivative financial instruments
|
|
|
14 |
|
|
|
21 |
|
|
|
26 |
|
|
|
44 |
|
|
Net fair value of derivative financial instruments outstanding at end of period
|
|
|
46 |
|
|
|
77 |
|
|
|
46 |
|
|
|
77 |
|
|
Netting of cash collateral
|
|
|
77 |
|
|
|
57 |
|
|
|
77 |
|
|
|
57 |
|
|
Cash collateral and net fair value of derivative financial instruments outstanding at end of period
|
|
$ |
123 |
|
|
$ |
134 |
|
|
$ |
123 |
|
|
$ |
134 |
|
The sources of net fair value of our derivative financial instruments at June 30, 2011, are as follows:
|
In millions
|
|
|
Prices actively quoted (Level 1) (1)
|
|
|
Significant other observable inputs
(Level 2) (2)
|
|
|
Mature through
|
|
|
|
|
|
|
|
| |
2011
|
|
|
$ |
(15 |
) |
|
$ |
27 |
|
| |
2012 – 2013 |
|
|
|
(23 |
) |
|
|
52 |
|
| |
2014 – 2016 |
|
|
|
2 |
|
|
|
3 |
|
|
Total derivative financial instruments (3)
|
|
|
$ |
(36 |
) |
|
$ |
82 |
|
|
(1)
|
Valued using NYMEX futures prices and other quoted sources.
|
|
(2)
|
Values primarily related to 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.
|
Natural Gas Price Risk
Value at Risk 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 its open positions.
Management actively monitors open natural gas positions and the resulting VaR. We continue to maintain a relatively matched book, where our total buy volume is close to sell volume with minimal open natural gas price risk. Based on a 95% confidence interval and employing a 1-day holding period for all positions, our portfolio of positions for the periods presented had the following VaRs.
| |
|
Three months ended
|
|
|
Six months ended
|
|
| |
|
June 30,
|
|
|
June 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
Period end
|
|
$ |
1.5 |
|
|
$ |
1.9 |
|
|
$ |
1.5 |
|
|
$ |
1.9 |
|
|
Average
|
|
|
1.3 |
|
|
|
1.3 |
|
|
|
1.3 |
|
|
|
1.4 |
|
|
High
|
|
|
1.9 |
|
|
|
2.4 |
|
|
|
1.9 |
|
|
|
3.0 |
|
|
Low
|
|
|
0.9 |
|
|
|
0.8 |
|
|
|
0.9 |
|
|
|
0.7 |
|
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 $552 million of variable-rate debt outstanding at June 30, 2011, a 100 basis point change in average market interest rates would have resulted in an increase in pretax interest expense of $6 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. The interest rate resets quarterly based on LIBOR plus 3.9%. This helps us achieve our desired mix of variable to fixed rate debt (i.e. variable debt target of 20% to 45% of total debt). For additional information, see Note 5.
Credit Risk
Wholesale Services Sequent has established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. Sequent also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Sequent is engaged in more than one outstanding derivative transaction with the same counterparty and it has a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Sequent’s credit risk. Sequent also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Sequent to net certain assets and liabilities by counterparty. Sequent also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions.
Additionally, Sequent may require counterparties to pledge additional collateral when deemed necessary. Sequent conducts credit evaluations and obtains appropriate internal approvals for its counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, Sequent requires credit enhancements by way of guaranty, cash deposit or letter of credit for counterparties that do not have investment grade ratings.
Sequent, which provides services to marketers and utility and industrial customers, also has a concentration of credit risk as measured by its 30-day receivable exposure plus forward exposure. As of June 30, 2011, Sequent’s top 20 counterparties represented approximately 56% of the total counterparty exposure of $383 million. Sequent’s counterparties, or the counterparties’ guarantors, had a weighted-average S&P equivalent credit rating of A- at June 30, 2011 and June 30, 2010, and BBB+ at December 31, 2010. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P and Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being the equivalent to AAA/Aaa by S&P and Moody’s and 1 being D or Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios for that counterparty. To arrive at the weighted-average credit rating, each counterparty is assigned an internal ratio, which is multiplied by their credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties’ exposures, and this numeric value is then converted to an S&P equivalent.
The following table shows Sequent’s third-party natural gas contracts receivable and payable positions as of the periods presented.
| |
|
Gross receivables
|
|
|
Gross payables
|
|
| |
|
Jun. 30,
|
|
|
Dec. 31,
|
|
|
Jun. 30,
|
|
|
Jun. 30,
|
|
|
Dec. 31,
|
|
|
Jun. 30,
|
|
|
In millions
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
|
Netting agreements in place:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparty is investment grade
|
|
$ |
388 |
|
|
$ |
515 |
|
|
$ |
399 |
|
|
$ |
293 |
|
|
$ |
341 |
|
|
$ |
301 |
|
|
Counterparty is non-investment grade
|
|
|
8 |
|
|
|
11 |
|
|
|
11 |
|
|
|
29 |
|
|
|
40 |
|
|
|
29 |
|
|
Counterparty has no external rating
|
|
|
212 |
|
|
|
260 |
|
|
|
108 |
|
|
|
357 |
|
|
|
363 |
|
|
|
264 |
|
|
No netting agreements in place:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Counterparty is investment grade
|
|
|
6 |
|
|
|
2 |
|
|
|
2 |
|
|
|
2 |
|
|
|
0 |
|
|
|
3 |
|
|
Counterparty has no external rating
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
2 |
|
|
Amount recorded on statements of financial position
|
|
$ |
614 |
|
|
$ |
788 |
|
|
$ |
520 |
|
|
$ |
681 |
|
|
$ |
744 |
|
|
$ |
599 |
|
Sequent has certain trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, Sequent would need to post collateral to continue transacting business with some of its counterparties. If such collateral were not posted, Sequent’s ability to continue transacting business with these counterparties would be negatively impacted. If our credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $23 million at June 30, 2011, which would not have a material impact to our condensed consolidated results of operations, cash flows or financial condition.
There have been no other significant changes to our credit risk related to our other segments, as described in Item 7A ”Quantitative and Qualitative Disclosures about Market Risk” of our 2010 Form 10-K.
(a) Evaluation of disclosure controls and procedures. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of June 30, 2011, 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 June 30, 2011, 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 second quarter ended June 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 1. Legal Proceedings
The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities and litigation incidental to the business. For information regarding pending federal and state regulatory matters see “Note 9 - Commitments and Contingencies” contained in Item 1 of Part I under the caption “Notes to Condensed Consolidated Financial Statements (Unaudited).”
With regard to legal proceedings, we are a party, as both plaintiff and defendant, to a number of other suits, claims and counterclaims on an ongoing basis. Management believes that the outcome of all such other litigation in which it is involved has not had and will not have a material adverse effect on our Consolidated Financial Statements.
In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, "Item 1A. Risk Factors" in our 2010 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this report and in our 2010 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 immaterial also may materially adversely affect our business, financial condition or future results. The following risk factors have changed since filing our 2010 Form 10-K.
Risks Related to Our Proposed Merger with Nicor
The merger may not be completed, which could adversely affect our business operations and stock price.
We have not yet obtained the approval of the Illinois Commerce Commission required to complete the merger. The Illinois Commerce Commission could still seek to block or challenge the merger or could impose restrictions they deem necessary or desirable in the public interest as a condition to approving the merger. If this approval is not received, or it is not received on terms that satisfy the conditions set forth in the Merger Agreement, then we will not be obligated to complete the merger.
In addition, the Merger Agreement contains other customary closing conditions which may not be satisfied or waived. If we are unable to complete the merger, we would be subject to a number of risks, including, but not limited to, the following:
|
·
|
we would not realize the anticipated benefits of the merger, including, among other things, increased operating efficiencies
|
|
·
|
the attention of our management may have been diverted to the merger rather than to our operations and the pursuit of other opportunities that could have been beneficial to us
|
|
·
|
the potential loss of key personnel during the pendency of the merger as employees may experience uncertainty about their future roles with the combined company
|
|
·
|
we will have been subject to certain restrictions on the conduct of our business, which may prevent us from making certain acquisitions or dispositions or pursuing certain business opportunities while the merger is pending
|
|
·
|
the trading price of our common stock may decline to the extent that the current market price reflects a market assumption that the merger will be completed.
|
We are required to pay Nicor a termination fee and the reimbursement of merger-related out-of-pocket expenses if we terminate the merger under certain circumstances specified in the Merger Agreement.
The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations or the trading price of our common stock.
The merger is subject to receipt of consent or approval from governmental entities that could delay or prevent the completion of the merger or impose conditions that could have a material adverse effect on the combined company or that could cause abandonment of the merger.
To complete the merger, we and Nicor still need to obtain approval from the Illinois Commerce Commission. While we believe that we will receive the required statutory approval, there can be no assurance as to the receipt or timing of receipt of the approval. If approval is received, the Illinois Commerce Commission may impose terms (i) that do not satisfy the conditions set forth in the Merger Agreement, which could permit us or Nicor to terminate the Merger Agreement or (ii) that could reasonably be expected to have a detrimental impact on the combined company following completion of the merger. A substantial delay in obtaining the required approval or the imposition of unfavorable terms, conditions or restrictions contained in such approval could prevent the completion of the merger or have an adverse effect on the anticipated benefits of the merger, thereby impacting the business, financial condition or results of operations of the combined company.
The Department of Justice and the Federal Trade Commission have granted us early termination of the waiting period under the Hart-Scott-Rodino Act, the SEC has declared effective our registration statement on Form S-4, we have received approval from the California Public Utilities Commission to transfer ownership of Central Valley Gas Storage from Nicor to us and we and Nicor held special shareholder meetings where the shareholders of both companies approved the merger. Additionally, the parties involved in the shareholder litigation related to the merger have entered into an agreement to resolve all of the pending lawsuits, subject to court approval.
Even though the statutory antitrust law waiting period has expired, governmental authorities could seek to block or challenge the merger as they deem necessary or desirable in the public interest.
The merger may be subject to review by the governmental authorities of various other federal, state or local jurisdictions under the antitrust and utility regulation or other applicable laws of those jurisdictions.
We provided a voluntary notice of the merger to the New Jersey BPU and the Maryland Public Service Commission (Maryland Commission), which included a description of the transaction, described the benefits of the transaction and explained why we do not believe that the approval of the New Jersey BPU or Maryland Commission is required to complete the merger. In May 2011, the Maryland Commission issued a letter stating that it had reviewed the notification of proposed merger filed by the Company and after considering the matter, noted the transaction.. It is possible that the New Jersey BPU will open proceedings to determine whether they have jurisdiction over the merger. In the event that they are determined to have jurisdiction over the merger transaction, there can be no assurance that the reviewing authorities will approve the merger without restrictions or conditions (which are difficult to predict or quantify) that would have a material adverse effect on the combined company if the merger were completed.
Our indebtedness following the merger will be higher than our existing indebtedness, which could limit our operations and opportunities, make it more difficult for us to pay or refinance our debts and may cause us to issue additional equity in the future, which would increase the dilution of our shareholders or reduce earnings.
In connection with the merger, we will assume Nicor’s outstanding debt and incur additional debt to pay the merger consideration and transaction expenses. Our total indebtedness as of December 31, 2010 was approximately $2.7 billion. Our pro forma total indebtedness as of December 31, 2010, after giving effect to the merger, would have been approximately $4.7 billion (including approximately $0.3 billion of currently payable long-term debt, approximately $1.2 billion of short-term borrowings and approximately $3.2 billion of long-term debt and other long-term obligations).
Our debt service obligations with respect to this increased indebtedness could have an adverse impact on our earnings and cash flows (which after the merger would include the earnings and cash flows of Nicor) for as long as the indebtedness is outstanding.
This increased indebtedness could also have important consequences to shareholders. For example, it could:
|
·
|
make it more difficult for us to pay or refinance our debts as they become due during adverse economic and industry conditions because any decrease in revenues could cause us to not have sufficient cash flows from operations to make our scheduled debt payments
|
|
·
|
limit our flexibility to pursue other strategic opportunities or react to changes in our business and the industry in which we operate and, consequently, place us at a competitive disadvantage to competitors with less debt
|
|
·
|
require a substantial portion of our cash flows from operations to be used for debt service payments, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions, dividend payments and other general corporate purposes
|
|
·
|
result in a downgrade in the credit rating of our indebtedness, which could limit our ability to borrow additional funds or increase the interest rates applicable to our indebtedness (after the announcement of the merger, Standard & Poor's Ratings Services placed its long-term ratings on AGL Resources on negative watch)
|
|
·
|
reduce the amount of credit available to us to support hedging activities
|
|
·
|
result in higher interest expense in the event of increases in interest rates since some of our borrowings are, and will continue to be, at variable rates.
|
Based upon current levels of operations, we expect to be able to generate sufficient cash on a consolidated basis to make all of the principal and interest payments when such payments are due under our existing credit agreements, indentures and other instruments governing our outstanding indebtedness, and under the indebtedness of Nicor and its subsidiaries that may remain outstanding after the merger; but there can be no assurance that we will be able to repay or refinance such borrowings and obligations.
We are committed to maintaining and improving our credit ratings. In order to maintain and improve these credit ratings, we may consider it appropriate to reduce the amount of indebtedness outstanding following the merger. This may be accomplished in several ways, including issuing additional shares of common stock or securities convertible into shares of common stock, reducing discretionary uses of cash or a combination of these and other measures. Issuances of additional shares of common stock or securities convertible into shares of common stock would have the effect of diluting the ownership percentage that shareholders will hold in the combined company and might reduce the reported earnings per share. The specific measures that we may ultimately decide to use to maintain or improve our credit ratings and their timing, will depend upon a number of factors, including market conditions and forecasts at the time those decisions are made.
Pending shareholder suits could delay or prevent the closing of the merger or otherwise adversely impact our business and operations.
Several class action lawsuits have been brought by purported Nicor shareholders challenging Nicor’s proposed merger with us. The complaints allege that we aided and abetted alleged breaches of fiduciary duty by Nicor’s Board of Directors. The shareholder actions seek, among other things, declaratory and injunctive relief, including orders enjoining the defendants from completing the proposed merger and, in certain circumstances, damages. No assurances can be given as to the outcome of these lawsuits, including the costs associated with defending these lawsuits or any other liabilities or costs the parties may incur in connection with the litigation or settlement of these lawsuits. Furthermore, one of the conditions to closing the merger is that there are no injunctions issued by any court preventing the completion of the transactions. No assurance can be given that these lawsuits will not result in such an injunction being issued which could prevent or delay the closing of the merger.
In March 2011, the parties entered into an agreement to resolve all of the shareholder lawsuits, subject to court approval, based on Nicor providing certain supplemental disclosures to our joint proxy statement filed on April 28, 2011. The parties expect to submit the agreement to the court for approval.
There have been no other significant changes to our risk factors included in Item 1A of our 2010 Form 10-K.