NICOR GAS COMPANY
(UNAUDITED)
|
|
Three months ended
|
|
|
Nine months ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
In millions
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
Operating revenues (includes revenue taxes of $14, $15, $96 and $121, respectively)
|
|
$
|
210
|
|
|
$
|
240
|
|
|
$
|
1,072
|
|
|
$
|
1,515
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
64
|
|
|
|
93
|
|
|
|
515
|
|
|
|
915
|
|
Operation and maintenance
|
|
|
63
|
|
|
|
60
|
|
|
|
219
|
|
|
|
209
|
|
Depreciation and amortization
|
|
|
49
|
|
|
|
47
|
|
|
|
146
|
|
|
|
141
|
|
Taxes other than income taxes
|
|
|
19
|
|
|
|
19
|
|
|
|
109
|
|
|
|
134
|
|
|
|
|
195
|
|
|
|
219
|
|
|
|
989
|
|
|
|
1,399
|
|
|
|
|
15
|
|
|
|
21
|
|
|
|
83
|
|
|
|
116
|
|
|
|
|
7
|
|
|
|
8
|
|
|
|
23
|
|
|
|
23
|
|
Earnings before income taxes
|
|
|
8
|
|
|
|
13
|
|
|
|
60
|
|
|
|
93
|
|
|
|
|
4
|
|
|
|
5
|
|
|
|
24
|
|
|
|
35
|
|
|
|
$
|
4
|
|
|
$
|
8
|
|
|
$
|
36
|
|
|
$
|
58
|
|
See Notes to Condensed Consolidated Financial Statements (Unaudited).
NICOR GAS COMPANY
(UNAUDITED)
|
|
Three months ended
|
|
|
Nine months ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
In millions
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
Comprehensive income
|
|
$
|
4
|
|
|
$
|
8
|
|
|
$
|
37
|
|
|
$
|
59
|
|
See Notes to Condensed Consolidated Financial Statements (Unaudited).
NICOR GAS COMPANY
(UNAUDITED)
|
|
Nine months ended
|
|
|
|
September 30,
|
|
In millions
|
|
2012
|
|
|
2011
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
Net income
|
|
$
|
36
|
|
|
$
|
58
|
|
Adjustments to reconcile net income to net cash flow provided by operating activities
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
146
|
|
|
|
141
|
|
Deferred income taxes
|
|
|
11
|
|
|
|
17
|
|
Change in derivative instrument assets and liabilities
|
|
|
(31
|
)
|
|
|
(19
|
)
|
Changes in certain assets and liabilities
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
210
|
|
|
|
222
|
|
Accrued natural gas costs
|
|
|
30
|
|
|
|
(9
|
)
|
Accounts payable
|
|
|
30
|
|
|
|
(34
|
)
|
Inventories
|
|
|
(25
|
)
|
|
|
(76
|
)
|
Other - net
|
|
|
42
|
|
|
|
57
|
|
Net cash flow provided by operating activities
|
|
|
449
|
|
|
|
357
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
Expenditures for property, plant and equipment
|
|
|
(146
|
)
|
|
|
(140
|
)
|
Other investing activities
|
|
|
5
|
|
|
|
4
|
|
Net cash flow used in investing activities
|
|
|
(141
|
)
|
|
|
(136
|
)
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
Dividends paid
|
|
|
(29
|
)
|
|
|
(64
|
)
|
Net payments and borrowings of short-term debt
|
|
|
(279
|
)
|
|
|
(115
|
)
|
Proceeds from issuing long-term debt
|
|
|
0
|
|
|
|
75
|
|
Payments of long-term debt
|
|
|
0
|
|
|
|
(75
|
)
|
Net repayments of loan from affiliates
|
|
|
0
|
|
|
|
(40
|
)
|
Other financing activities
|
|
|
0
|
|
|
|
(2
|
)
|
Net cash flow used in financing activities
|
|
|
(308
|
)
|
|
|
(221
|
)
|
Net increase in cash and cash equivalents
|
|
|
0
|
|
|
|
0
|
|
Cash and cash equivalents at beginning of period
|
|
|
0
|
|
|
|
0
|
|
Cash and cash equivalents at end of period
|
|
$
|
0
|
|
|
$
|
0
|
|
Cash paid (received) during the period for
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
21
|
|
|
$
|
23
|
|
Income taxes
|
|
$
|
0
|
|
|
$
|
(2
|
)
|
See Notes to Condensed Consolidated Financial Statements (Unaudited).
NICOR GAS COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 1
- Organization and Basis of Presentation
General
Nicor Gas is a natural gas distribution company that serves approximately 2.2 million customers in a service territory that encompasses most of the northern third of Illinois, excluding the city of Chicago. Unless the context requires otherwise, references to “we,” “us,” “our,” the “company,” or “Nicor Gas” mean consolidated Nicor Gas and its wholly owned subsidiary.
On December 9, 2011, AGL Resources and Nicor merged and we became a wholly owned subsidiary of AGL Resources. Because of our significant outstanding public debt, the impact of the acquisition (push-down accounting) is not required to be, and has not been, reflected in our unaudited Condensed Consolidated Financial Statements.
The December 31, 2011 Condensed Consolidated Statement of Financial Position data was derived from our audited financial statements, but does not include all disclosures required by GAAP. We have prepared the accompanying unaudited Condensed Consolidated Financial Statements under the rules and regulations of the SEC. In accordance with such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with GAAP. Our unaudited Condensed Consolidated Financial Statements reflect all adjustments of a normal recurring nature that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods. You should read these unaudited Condensed Consolidated Financial Statements in conjunction with our Consolidated Financial Statements and related notes included in Item 8 of our 2011 Form 10-K.
Due to the seasonal nature of our business and other factors, our results of operations and our financial condition for the periods presented are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.
Basis of Presentation
Our unaudited Condensed Consolidated Financial Statements include our accounts and the accounts of our wholly owned subsidiary. We have eliminated intercompany profits and transactions in consolidation. Certain amounts from prior periods have been reclassified and revised to conform to the current period presentation. The reclassifications and revisions had no material impact on our prior period balances.
Note 2
- Significant Accounting Policies and Methods of Application
Our accounting policies are described in Note 2 to our Consolidated Financial Statements and related notes included in Item 8 of our 2011 Form 10-K. There were no significant changes to our accounting policies during the nine months ended September 30, 2012.
Use of Accounting Estimates
The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. Our estimates are based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Our estimates may involve 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. The most significant estimates relate to our accrued unbilled revenues, environmental liability accruals, uncollectible accounts and other allowances for contingent losses, regulatory assets and liabilities, retirement plan benefit obligations, asset retirement obligations, derivative and hedging activities and provisions for income taxes. We evaluate our estimates on an ongoing basis and our actual results could differ from our estimates.
Inventory
Our inventory is carried at cost on a LIFO basis. Inventory decrements occurring during interim periods that are expected to be restored prior to year-end are charged to cost of goods sold at the estimated annual replacement cost, and the difference between this cost and the actual liquidated LIFO layer cost is recorded on the unaudited Condensed Consolidated Statements of Financial Position as a temporary LIFO inventory liquidation. Interim inventory decrements not expected to be restored prior to year-end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. As of September 30, 2012 and 2011, there was no inventory decrement.
Fair Value Measurements
We have several financial and nonfinancial assets and liabilities subject to fair value measures. The financial assets and liabilities include cash and cash equivalents, receivables, derivative assets and liabilities, accounts payable and debt. The carrying values of cash and cash equivalents, derivative assets and liabilities, short-term debt and other current assets and liabilities approximate fair value. The nonfinancial assets and liabilities include pension and other retirement benefits, which are presented in Note 3 to our Consolidated Financial Statements and related notes included in Item 8 of our 2011 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 valuing 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 to 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 classify fair value balances based on the reliability of those inputs in accordance with the fair value hierarchy.
Revenue Taxes
We charge customers for revenue taxes and remit amounts owed to various governmental authorities. Our policy is to
record all such taxes charged to customers as operating revenues and the related taxes incurred as operating expenses in our unaudited Condensed Consolidated Statements of Income, regardless of whether the tax is assessed on the company or the customer. Revenue taxes included in operating expenses were $14 million and $95 million for the three and nine months ended September 30, 2012 and $14 million and $119 million for the three and nine months ended September 30, 2011.
Natural Gas Derivative Instruments
As required by the authoritative guidance, derivative assets and liabilities are classified in the fair value hierarchy in their entirety based on the least reliable level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors required under the guidance. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities. To mitigate the risk that a counterparty to a derivative instrument defaults on settlement or otherwise fails to perform under contractual terms, we have established procedures to monitor the creditworthiness of counterparties, seek guarantees or collateral back-up in the form of cash or letters of credit and, in most instances, enter into netting arrangements.
Cash flows from derivative instruments are recognized in the unaudited Condensed Consolidated Statements of Cash Flows, and gains and losses are recognized in the unaudited Condensed Consolidated Statements of Income, in the same categories as the underlying transactions.
Cash flow hedge accounting may be elected only for highly effective hedges, based upon an assessment, performed at least quarterly, of the historical and probable future correlation of cash flows from the derivative instrument to changes in the expected future cash flows of the hedged item. To the extent cash flow hedge accounting is applied, the effective portion of any changes in the fair value of the derivative instruments is reported as a component of accumulated OCI. Ineffectiveness, if any, is immediately recognized in operating income. The amount in accumulated OCI is reclassified to earnings when the forecasted transaction is recognized in the Condensed Consolidated Statements of Income, even if the derivative instrument is sold, extinguished or terminated prior to the transaction occurring. If the forecasted transaction is no longer expected to occur, the amount in accumulated OCI is immediately reclassified to operating income.
The fair value of natural gas derivative instruments we use to manage exposures arising from changing natural gas prices reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 4 for additional derivative disclosures.
Subject to review by the Illinois Commission, we enter into derivative instruments to hedge the purchase of natural gas for our customers. The costs and impacts associated with each instrument are collected from customers through the PGA mechanism as a component of the cost of gas. In accordance with the authoritative guidance related to derivatives and hedging, such derivative transactions are accounted for at fair value each reporting period in our unaudited Condensed Consolidated Statements of Financial Position. In accordance with regulatory requirements, any realized gains and losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. Thus, hedge accounting is not elected and, in accordance with accounting guidance pertaining to rate-regulated entities, unrealized
changes in the fair value of these derivative instruments are deferred or accrued as regulatory assets or liabilities until the related revenue is recognized.
We also enter into swap agreements to reduce the earnings volatility of certain forecasted operating costs arising from fluctuations in natural gas prices, such as the purchase of natural gas for company use. These derivative instruments are carried at fair value. To the extent hedge accounting is not elected, changes in such fair values are recorded in the current period as operation and maintenance expense.
We maintain margin accounts related to financial derivative transactions. Our policy is not to offset the fair value of assets and liabilities recognized for derivative instruments or any related margin account. See Note 4 - Derivative Instruments for additional derivative disclosures.
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 in the current period are capitalized as regulatory assets when it is probable that such costs or expenditures will be recovered in future rates. 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 Illinois Commission. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover these costs consistent with our historical recoveries. In the event that the authoritative guidance related to regulated operations were no longer applicable, we would recognize a write-off of regulatory assets and liabilities that would result in net income.
Our regulatory assets and liabilities are summarized in the following table.
In millions
|
|
September 30, 2012
|
|
|
December 31,
2011
|
|
|
September 30, 2011
|
|
Regulatory assets -
current
|
|
|
|
|
|
|
|
|
|
Recoverable pension and other retirement benefit costs
|
|
$
|
27
|
|
|
$
|
29
|
|
|
$
|
21
|
|
Recoverable ERC
|
|
|
26
|
|
|
|
0
|
|
|
|
0
|
|
Deferred natural gas costs
|
|
|
0
|
|
|
|
0
|
|
|
|
18
|
|
Other
|
|
|
6
|
|
|
|
7
|
|
|
|
10
|
|
Total regulatory assets - current
|
|
|
59
|
|
|
|
36
|
|
|
|
49
|
|
Regulatory assets - noncurrent
|
|
|
|
|
|
|
|
|
|
|
|
|
Recoverable pension and other retirement benefit costs
|
|
|
219
|
|
|
|
253
|
|
|
|
182
|
|
Recoverable ERC
|
|
|
212
|
|
|
|
134
|
|
|
|
47
|
|
Unamortized losses on reacquired debt
|
|
|
11
|
|
|
|
12
|
|
|
|
12
|
|
Other
|
|
|
4
|
|
|
|
5
|
|
|
|
6
|
|
Total regulatory assets - noncurrent
|
|
|
446
|
|
|
|
404
|
|
|
|
247
|
|
Total regulatory assets
|
|
$
|
505
|
|
|
$
|
440
|
|
|
$
|
296
|
|
Regulatory liabilities -
current
|
|
|
|
|
|
|
|
|
|
Accrued natural gas costs
|
|
$
|
59
|
|
|
$
|
29
|
|
|
$
|
0
|
|
Bad debt rider
|
|
|
30
|
|
|
|
30
|
|
|
|
27
|
|
Regulatory asset retirement liability
|
|
|
14
|
|
|
|
14
|
|
|
|
17
|
|
Other
|
|
|
4
|
|
|
|
4
|
|
|
|
2
|
|
Total regulatory liabilities - current
|
|
|
107
|
|
|
|
77
|
|
|
|
46
|
|
Regulatory liabilities - noncurrent
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory asset retirement liability
|
|
|
932
|
|
|
|
896
|
|
|
|
879
|
|
Unamortized investment tax credit
|
|
|
21
|
|
|
|
22
|
|
|
|
23
|
|
Bad debt rider
|
|
|
16
|
|
|
|
14
|
|
|
|
16
|
|
Regulatory income tax liability
|
|
|
11
|
|
|
|
13
|
|
|
|
13
|
|
Other
|
|
|
2
|
|
|
|
1
|
|
|
|
1
|
|
Total regulatory liabilities - noncurrent
|
|
|
982
|
|
|
|
946
|
|
|
|
932
|
|
Total regulatory liabilities
|
|
$
|
1,089
|
|
|
$
|
1,023
|
|
|
$
|
978
|
|
Other than the increase in the estimates of recoverable ERC, there have been no significant changes to our regulatory assets or liabilities from those discussed in Note 2 to our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K. See Note 7 - Commitment, Guarantees and Contingencies for additional ERC disclosures.
We do not earn a return on our recoverable retirement benefit costs. Our recoverable retirement benefit costs are expected to be recovered from ratepayers over a period of approximately 9 to 11 years. The regulatory assets related to debt are not included in rate base, but are recovered over the term of the debt through the rate of return authorized by the Illinois Commission. Our rate riders for natural gas costs, certain environmental costs and energy efficiency costs provide a return on investment during the period of recovery. However, there is no interest associated with under or over collections of bad debt expense.
Accounting Developments
On January 1, 2012, we adopted authoritative guidance related to fair value measurements. The guidance expands the qualitative and quantitative disclosures required for Level 3 significant unobservable inputs. The guidance also limits the application of the highest and best use premise to non-financial assets and liabilities. This guidance had no impact on our unaudited Condensed Consolidated Financial Statements. See Note 3 for additional fair value disclosures.
On January 1, 2012, we adopted authoritative guidance related to comprehensive income. The guidance eliminates the option to present OCI in the unaudited Condensed Consolidated Statements of Equity, but allows companies to elect to present net income and OCI in one continuous statement (unaudited Condensed Consolidated Statements of Comprehensive Income) or in two consecutive statements. This guidance does not change any of the components of net income or OCI and earnings per share will continue to be calculated based on net income. This guidance did not have a material impact on our unaudited Condensed Consolidated Financial Statements.
Note 3
- Fair Value Measurements
The methods used to determine the fair value of our assets and liabilities are described within Note 2 - Significant Accounting Policies and Methods of Application.
Derivative Instruments
The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were accounted for at fair value on a recurring basis as of the periods presented. See Note 4 - Derivative Instruments for additional derivative instrument information.
|
|
Recurring fair values
|
|
|
|
Derivative instruments
|
|
|
|
September 30, 2012
|
|
|
December 31, 2011
|
|
|
September 30, 2011
|
|
In millions
|
|
Assets
|
|
|
Liabilities
|
|
|
Assets
|
|
|
Liabilities
|
|
|
Assets
|
|
|
Liabilities
|
|
Natural gas derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted prices in active markets (Level 1)
|
|
$
|
5
|
|
|
$
|
(1
|
)
|
|
$
|
0
|
|
|
$
|
(14
|
)
|
|
$
|
0
|
|
|
$
|
(20
|
)
|
Significant other observable inputs (Level 2)
|
|
|
6
|
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
(11
|
)
|
|
|
0
|
|
|
|
(10
|
)
|
Unobservable inputs (Level 3)
|
|
|
0
|
|
|
|
0
|
|
|
|
2
|
|
|
|
0
|
|
|
|
5
|
|
|
|
(1
|
)
|
Total carrying value
|
|
$
|
11
|
|
|
$
|
(2
|
)
|
|
$
|
3
|
|
|
$
|
(25
|
)
|
|
$
|
5
|
|
|
$
|
(31
|
)
|
There were no transfers between Level 1 and Level 2 for any of the periods presented.
We maintain margin accounts related to financial derivative transactions. The following table presents the unaudited Condensed Consolidated Statements of Financial Position classification of margin accounts related to derivative instruments.
In millions
|
|
September 30, 2012
|
|
|
December 31, 2011
|
|
|
September 30, 2011
|
|
Assets
|
|
|
|
|
|
|
|
|
|
Margin accounts - derivative instruments
|
|
$
|
0
|
|
|
$
|
21
|
|
|
$
|
27
|
|
Other long-term assets and other deferred debits
|
|
|
0
|
|
|
|
0
|
|
|
|
1
|
|
Debt
Our long-term debt is recorded at amortized cost. At September 30, 2012 and December 31, 2011, we estimated the fair value of our debt using a discounted cash flow technique that incorporated a market interest yield curve with adjustments for duration, optionality and risk profile. At September 30, 2011, we estimated the fair value of debt for our public first mortgage bonds using quoted market pricing information. The following table presents the amortized cost and fair value of our long-term debt as of the following periods.
In millions
|
|
September 30,
2012
|
|
|
December 31,
2011
|
|
|
September 30,
2011
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt amortized cost
|
|
$
|
499
|
|
|
$
|
499
|
|
|
$
|
499
|
|
Long-term debt fair value (1)
|
|
|
630
|
|
|
|
610
|
|
|
|
621
|
|
(1)
|
Valued using Level 2 inputs.
|
Note 4
- Derivative Instruments
A description of our objectives and strategies for using derivative instruments, related accounting policies and methods used to determine their fair value are described in Note 2 - Significant Accounting Policies and Methods of Application. See Note 3 - Fair Value Measurements for additional fair value disclosures.
Credit-risk-related contingent features.
Provisions within certain derivative agreements require us to post collateral if our net liability position exceeds a specified threshold. Also, certain derivative agreements contain credit-risk-related contingent features, whereby we would be required to provide additional collateral or pay the amount due to the counterparty when a credit event occurs, such as if our credit rating was lowered. For agreements with such features, derivative instruments with liability fair values totaled $1 million at September 30, 2012, $6 million at December 31, 2011 and $3 million at September 30, 2011, for which we had posted no collateral to our counterparties. If it was assumed that we had to post the maximum contractually specified collateral or settle the liability, we would have been required to pay $6 million at December 31, 2011 and $3 million at September 30, 2011.
Quantitative Disclosures Related to Derivative Instruments
As of the periods presented,
our derivative instruments were comprised of long natural gas positions. A long position is a contract to purchase natural gas. We had long natural gas contracts outstanding in the following quantities.
In Bcf
|
|
September 30, 2012
(1)
|
|
|
December 31, 2011
|
|
|
September 30, 2011
|
|
Hedge designation:
|
|
|
|
|
|
|
|
|
|
Customer use - not designated as hedges
|
|
|
26
|
|
|
|
30
|
|
|
|
30
|
|
Company use - designated as cash flow hedges
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
Total
|
|
|
27
|
|
|
|
31
|
|
|
|
31
|
|
(1)
|
These contracts have durations of three years or less.
|
The volumes above exclude variable-priced
contracts, which are accounted for as derivatives but whose fair values are not directly impacted by changes in commodity prices.
Derivative Instruments Impact on the Unaudited Condensed Consolidated Statements of Financial Position
The following table presents the fair value and unaudited Condensed Consolidated Statements of Financial Position classification of our derivative instruments as of the periods presented.
In millions
|
Unaudited Condensed Consolidated Statements of Financial Position Location
|
|
September 30,
2012
|
|
|
December 31, 2011
|
|
|
September 30,
2011
|
|
Designated as cash flow hedges
|
|
|
|
|
|
|
|
|
|
Liability Instruments
|
|
|
|
|
|
|
|
|
|
Current natural gas contracts
|
Derivative instrument liabilities - current portion
|
|
$
|
0
|
|
|
$
|
(1
|
)
|
|
$
|
(1
|
)
|
Total designated as cash flow hedges
|
|
|
0
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Not designated as cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
Current natural gas contracts
|
Derivative instrument assets - current portion
|
|
|
10
|
|
|
|
2
|
|
|
|
3
|
|
Noncurrent natural gas contracts
|
Derivative instrument assets - long-term portion
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
Liability Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
Current natural gas contracts
|
Derivative instrument liabilities - current portion
|
|
|
(2
|
)
|
|
|
(24
|
)
|
|
|
(30
|
)
|
Total not designated as cash flow hedges
|
|
|
9
|
|
|
|
(21
|
)
|
|
|
(25
|
)
|
Total net gain (loss) on derivative instruments
|
|
$
|
9
|
|
|
$
|
(22
|
)
|
|
$
|
(26
|
)
|
Derivative Instruments Impact on the Unaudited Condensed Consolidated Statements of Income
Derivatives used to hedge the purchase of natural gas for our customers are not designated as hedging instruments. Gains or losses on these derivatives are not recognized in pre-tax earnings, but are deferred as regulatory assets or liabilities until the related revenue is recognized. Net gains (losses) deferred were $10 million and $(8) million for the three and nine months ended September 30, 2012 and $(29) million and $(33) million for the three and nine months ended September 30, 2011.
Non-designated derivatives used to hedge purchases of natural gas for company use are recorded within operation and maintenance expense. Our earnings are subject to volatility for other derivatives not designated as hedges. Gains and losses recognized in income were immaterial for the three and nine months ended September 30, 2012 and 2011.
Note 5
- Employee Benefit Plans
Overview
We maintain a noncontributory defined benefit pension plan covering substantially all employees hired prior to 1998. Pension benefits are based on years of service and the highest average salary for management employees and job level for collectively bargained employees. We also provide health care and life insurance benefits to eligible retired employees under our other retirement benefit plan that includes a limit on our share of the cost for employees hired after 1982.
Our pension and other retirement plan benefit costs have historically been considered in rate proceedings in the period they are accrued. As a regulated utility, we expect continued rate recovery of the eligible costs of these plans and, accordingly, associated changes in the plans’ funded status have been deferred as a regulatory asset or liability until recognized in net income, instead of being recorded in accumulated OCI. However, to the extent our employees perform services for affiliates and to the extent such employees are eligible to participate in these plans, the affiliates are charged for the cost of these benefits and the changes in the funded status relating to such services are recorded in accumulated OCI.
About one-fourth of the net benefit cost related to these plans has been capitalized as a cost of constructing gas distribution facilities and the remainder is included in operation and maintenance expense, net of amounts charged to affiliates.
The Health Care Act contains provisions that may impact our obligation for retiree health care benefits. We do not currently believe that these provisions will materially increase our other retirement plan benefit obligation, but we will continue to evaluate the impact of future regulations and interpretations.
In July 2012, the Pension Protection Act of 2006 was changed to provide near-term funding relief to certain pension plans and to increase Pension Benefit Guaranty Corporation premiums. As a result, any required cash contributions, which statutorily were based on the two-year average of interest rates, will be adjusted so that they are within 10% of the discount rate derived using a 25-year average and 30% of the 25-year average interest rate beginning in 2016. Due to our plan’s current funding status, we do not believe this legislation will have a material impact to us.
Pension Benefits
Following are the cost components of our defined benefit pension plan for the periods indicated:
|
|
Three months ended
September 30,
|
|
|
Nine months ended
September 30,
|
|
In millions
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
Service cost
|
|
$
|
3
|
|
|
$
|
2
|
|
|
$
|
9
|
|
|
$
|
7
|
|
Interest cost
|
|
|
4
|
|
|
|
4
|
|
|
|
12
|
|
|
|
12
|
|
Expected return on plan assets
|
|
|
(8
|
)
|
|
|
(7
|
)
|
|
|
(24
|
)
|
|
|
(23
|
)
|
Recognized actuarial loss
|
|
|
4
|
|
|
|
3
|
|
|
|
12
|
|
|
|
8
|
|
Net pension benefit cost
|
|
$
|
3
|
|
|
$
|
2
|
|
|
$
|
9
|
|
|
$
|
4
|
|
Other Retirement Benefits
Following are the cost components of our other retirement plan for the periods indicated:
|
|
Three months ended
September 30,
|
|
|
Nine months ended
September 30,
|
|
In millions
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
Service cost
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
2
|
|
|
$
|
2
|
|
Interest cost
|
|
|
3
|
|
|
|
3
|
|
|
|
9
|
|
|
|
9
|
|
Recognized actuarial loss
|
|
|
1
|
|
|
|
2
|
|
|
|
5
|
|
|
|
5
|
|
Net benefit cost
|
|
$
|
5
|
|
|
$
|
6
|
|
|
$
|
16
|
|
|
$
|
16
|
|
In the second quarter of 2012, the estimated benefit obligation for our retiree medical plan decreased to $263 million as a result of final updated census data and claims costs. As of December 31, 2011, our retiree medical plan benefit obligation was $283 million.
Note 6
- Debt and Credit Facility
The following table provides maturity dates, weighted average interest rates and amounts outstanding for our various debt securities that are included in our unaudited Condensed Consolidated Statements of Financial Position. For additional information on our debt, see Note 6 in our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K.
|
|
September 30, 2012
|
|
|
|
|
|
September 30, 2011
|
|
Dollars in millions
|
|
Year(s) due
|
|
|
Weighted
average interest rate
(1)
|
|
|
Outstanding
|
|
|
Outstanding at December 31, 2011
|
|
|
Weighted average interest rate
(1)
|
|
|
Outstanding
|
|
Commercial paper
(2)
|
|
2012
|
|
|
|
0.5
|
%
|
|
$
|
173
|
|
|
$
|
452
|
|
|
|
0.2
|
%
|
|
$
|
310
|
|
Long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First mortgage bonds
|
|
|
2016-2038
|
|
|
|
5.6
|
%
|
|
$
|
500
|
|
|
$
|
500
|
|
|
|
5.6
|
%
|
|
$
|
500
|
|
Less: Unamortized debt discount, net of premium
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
1
|
|
|
|
1
|
|
|
|
n/a
|
|
|
|
1
|
|
Total long-term debt
|
|
|
|
|
|
|
5.6
|
%
|
|
$
|
499
|
|
|
$
|
499
|
|
|
|
5.6
|
%
|
|
$
|
499
|
|
Total debt
|
|
|
|
|
|
|
|
|
|
$
|
672
|
|
|
$
|
951
|
|
|
|
|
|
|
$
|
809
|
|
(1)
|
Interest rates are calculated based on the daily weighted average balance for the applicable category outstanding for the nine months ended September 30.
|
(2)
|
Weighted average interest rate was 0.4% as of September 30, 2012 and 0.2% as of September 30, 2011.
|
Financial and Non-Financial Covenants
Our credit facility includes a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month. Our ratio, as calculated in accordance with our debt covenant, includes standby letters of credit and surety bonds and excludes accumulated OCI. Adjusting for these items, our debt-to-capitalization ratio for September 30, 2012 was 51%, which is within our required range.
The credit facility also contains certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations and other matters customarily restricted in such agreements.
Default Provisions
Our credit facility and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. The most important default events include:
·
|
a maximum leverage ratio
|
·
|
insolvency events and nonpayment of scheduled principal or interest payments
|
·
|
acceleration of other financial obligations
|
·
|
change of control provisions
|
We have no triggering events in our debt instruments that are tied to changes in our specified credit ratings. We were in compliance with all existing debt provisions and covenants, both financial and non-financial, for all periods presented.
Note 7
- Commitments, Guarantees and Contingencies
There were no significant changes to our contractual obligations described in Note 7 of our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K other than those related to ERC and SNG contracts as described below.
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.
Substitute Natural Gas
In 2011, Illinois enacted laws that required us and other large utilities in Illinois to elect to either sign contracts to purchase SNG from coal gasification plants to be constructed in Illinois or instead file rate cases with the Illinois Commission in 2012, 2014 and 2016.
On September 30, 2011, we signed an agreement to purchase approximately 25 Bcf of SNG annually for a 10-year term beginning as early as 2015. The agreement required, among other things, the developer to begin construction of the SNG plant by July 1, 2012. The developer did not meet this deadline and, as a result, the agreement automatically terminated.
Additionally, on October 11, 2011, the Illinois Power Agency (IPA) approved the form of a draft 30-year contract for the purchase by us of approximately 20 Bcf per year of SNG from a second proposed plant beginning as early as 2018. The purchase price of the SNG that may be produced from this proposed coal gasification plant may significantly exceed market prices for natural gas and is expected to be dependent upon a variety of factors, including the developer’s financing, plant construction costs and volumes sold, which are currently not determinable. The Illinois law pertaining to this plant provides that the price paid for SNG purchased from the plant is to be considered prudent and not subject to review or disallowance by the Illinois Commission. As such, Illinois law effectively requires our customers to provide subordinated financial support to the developer.
In November 2011, we filed a lawsuit against the IPA and the developer of this second proposed plant contending that the draft contract approved by the IPA does not conform to certain requirements of the enabling legislation. The lawsuit is pending in circuit court in DuPage County, Illinois. In accordance with the enabling legislation, the draft contract approved by the IPA for the second proposed plant was submitted to the Illinois Commission for further approvals by that regulatory body. The Illinois Commission issued an order on January 10, 2012 approving a final form of the contract for the second plant. The final form of contract approved by the Illinois Commission modified the draft contract submitted by the IPA in various respects. Both we and the developer of the plant filed applications for a rehearing with the Illinois Commission seeking changes to the final form of the contract. The Illinois Commission agreed to grant a rehearing. On July 11, 2012, the Illinois Commission issued its order on rehearing, in which it modified its earlier order to change certain of the terms of the approved form of SNG purchase contract. The Illinois state court denied our appeal of the Illinois Commission’s order, but that does not impact the pending DuPage County lawsuit challenging the IPA’s earlier order approving the draft form of contract. In May 2012, the Illinois legislature passed a bill that directed the Illinois Commission to approve a final form of contract that differed in certain respects from the form the Illinois Commission approved in its July 11, 2012 order and that purported to address issues raised in our pending lawsuit against the IPA. This bill was vetoed by the Governor of Illinois on August 10, 2012. As a result of pending litigation challenging aspects of the IPA and Illinois Commission decisions regarding the contract terms, we have not yet signed a contract with the developer to purchase SNG from the second proposed plant.
Contingencies and Guarantees
Indemnities
In certain instances, we have undertaken to indemnify current property owners and others against costs associated with the effects and/or remediation of contaminated sites for which we may be responsible under applicable federal or state environmental laws, generally with no limitation as to the amount. These indemnifications relate primarily to remediation of MGP sites, as discussed in Environmental Matters. We believe that the likelihood of payment under our other environmental indemnifications is remote. No liability has been recorded for such indemnifications.
We have also indemnified, to the fullest extent permitted under the laws of the state of Illinois and any other applicable laws, our present and former directors, officers and employees against expenses they may incur in connection with litigation to which they are a party by reason of their association with us. There is generally no limitation as to the amount. While we do not expect to incur significant costs under these indemnifications, it is not possible to estimate the maximum future potential payments.
Environmental Matters
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at our current and former operating sites.
We have identified 26 former manufactured gas plant sites in Illinois for which we may have some responsibility. Most of these sites are not presently owned by us. We are party to an agreement to cooperate in cleaning up residue at many of these sites. The agreement allocates to us 51.73% of cleanup costs for 23 sites, no portion of the cleanup costs for 14 other sites and 50% of general remediation program costs that do not relate exclusively to particular sites. In addition to the sites from the agreement, there are 3 sites in which we have sole responsibility. Information regarding preliminary site reviews has been presented to the Illinois Environmental Protection Agency for certain sites. More detailed investigations and remedial activities are complete, in progress or planned at many of these sites. The results of the detailed site-by-site investigations will determine the extent additional remediation is necessary and provide a basis for estimating additional future costs.
Our ERC liabilities are estimates of future remediation costs for our former operating sites that are contaminated. Our estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, which is generally the case when remediation has not commenced or during the early years of a remediation effort. For those elements of the program where we cannot perform engineering estimates, there remains considerable variability in future cost estimates. Accordingly, we have established a probabilistic model to determine a range of potential expenditures to remediate and monitor our former operating sites. We cannot at this time identify any single number within this range as a better estimate of likely future costs, and we generally have recorded the low end of the range for our probabilistic cost estimates.
As we conduct the actual remediation and enter into cleanup contracts, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering assumptions, which we refine and update on an ongoing basis. During the second quarter of 2012
,
we completed our probabilistic models and engineering estimates, which resulted in a $109 million increase from the amount recorded at December 31, 2011
.
In accordance with Illinois Commission authorization, these costs are recoverable from our customers as they are paid subject to annual prudence reviews and, accordingly, we have recorded a regulatory asset associated with the recorded liabilities. The following table provides more information on the costs related to remediation of our former operating sites as of September 30, 2012:
In millions
|
|
Probabilistic model cost estimate range
(1)
|
|
|
Engineering estimates
(1)
|
|
|
Amount recorded
|
|
|
Expected costs over next twelve months
|
|
|
|
$
|
193
-
$443
|
|
|
$
|
50
|
|
|
$
|
242
|
|
|
$
|
26
|
|
(1)
|
There were no material changes to the estimates disclosed in our June 30, 2012 Form 10-Q. As such, the estimates above were not changed for revised assumptions or actual remediation expenses incurred.
|
Litigation
We are involved in litigation arising in the normal course of business. Although in some cases we are unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require us to take charges against, or will result in reductions in, future earnings. It is the opinion of management that the resolution of these contingencies, either individually or in aggregate, could be material to earnings in a particular period but will not have a material adverse effect on our consolidated financial position or cash flows. For additional litigation information, see Note 7 in our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K.
PBR Proceeding
Our PBR plan for natural gas costs went into effect in 2000 and was terminated by us effective January 1, 2003. Under this plan, our total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. The PBR plan is currently under review by the Illinois Commission as there are allegations that we acted improperly in connection with the PBR plan. On June 27, 2002, the Citizens Utility Board (CUB) filed a motion to reopen the record in the Illinois Commission’s proceedings to review the PBR plan. As a result of the motion to reopen, we entered into a stipulation with the staff of the Illinois Commission and CUB providing for additional discovery. The Illinois Attorney General’s Office (IAGO) has also intervened in this matter. In addition, the IAGO issued Civil Investigation Demands (CIDs) to CUB and the Illinois Commission staff. The CIDs ordered that CUB and the Illinois Commission staff produce all documents relating to any claims that we may have presented, or caused to be presented, regarding false information related to our PBR plan. The staff of the Illinois Commission, IAGO and CUB submitted direct testimony to the Illinois Commission in April 2009 and rebuttal testimony in October 2011. In rebuttal testimony, the staff of the Illinois Commission, IAGO and CUB requested refunds of $85 million, $255 million and $305 million, respectively. We have committed to cooperate fully in the reviews of the PBR plan.
In February 2012, we committed to a stipulated resolution of issues with the staff of the Illinois Commission, which includes crediting our customers $64 million, which is not recoverable from our customers. This liability is reflected in our unaudited Condensed Consolidated Statements of Financial Position at September 30, 2012 and December 31, 2011. The stipulated resolution does not constitute an admission of fault, and it is not final and is subject to review and approval by the Illinois Commission. CUB and IAGO are not parties to the stipulated resolution and continue to pursue their claims in this proceeding. Evidentiary hearings before the Administrative Law Judge were held during the first quarter of 2012 and post-trial legal briefs from the parties were submitted during the second quarter of 2012. Following the submission of legal briefs, the Administrative Law Judge will issue a proposed decision. There is no date scheduled for the issuance of that proposed decision.
We are unable to predict the outcome of the Illinois Commission’s review or our potential exposure. Since the PBR plan and historical gas costs are still under Illinois Commission review, the final outcome could be materially different than the amount reflected in our financial statements as of September 30, 2012.
Other
We are also involved in service warranty product actions, municipal tax matters, an action challenging our estimated billing practices and an investigation by the United States Environmental Protection Agency regarding the applicable regulatory requirements for polychlorinated biphenyl (PCB) in our distribution system. While we are unable to predict the outcome of these matters or to reasonably estimate our potential exposure related thereto, if any, and have not recorded a liability associated with these contingencies, the final disposition of these matters is not expected to have a material adverse impact on our liquidity or financial condition. For additional litigation information on these matters, see Note 7 in our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K.
In addition to the matters set forth above, we are involved with legal or administrative proceedings before various courts and agencies with respect to general claims, taxes, environmental, gas cost prudence reviews and other matters. Although we are unable to determine the ultimate outcome of these other contingencies, we believe that these amounts are appropriately reflected in our financial statements, including the recording of appropriate liabilities when reasonably estimable.
Note 8
- Related Party Transactions
In the ordinary course of business, under the terms of agreements approved by the Illinois Commission, we enter into transactions with our affiliates for the use of facilities and services. The charges for these transactions are cost-based, except in certain circumstances where the charging party has a prevailing price for which the facility or service is provided to the general public. We had net charges from affiliates of $22 million and $40 million for the three and nine months ended September 30, 2012 and net charges to affiliates of less than $1 million and $10 million for the three and nine months ended September 30, 2011.
Our key executives and managerial employees participate in our parent company’s stock-based compensation plans. We recognized the compensation expense related to these plans in operation and maintenance expense. Charges related to these plans from AGL Services Company were less than $1 million for the three and nine months ended September 30, 2012 and charges from Nicor were $2 million and $4 million for the three and nine months ended September 30, 2011.
We are currently prohibited by regulations of the Illinois Commission from loaning money to affiliates. However, we are permitted under these regulations to receive cash advances from AGL Resources. The balance of any such advances may not exceed the balance of funds available to us under our existing credit agreements or commercial paper facilities with unaffiliated third parties. Interest is charged on such loans at the lower of our commercial paper rate or AGL Resources’ actual interest cost for the funds obtained or used to provide us the cash advance. We received no cash advances from AGL Resources during the nine months ended September 30, 2012.
Under its utility-bill management products, Nicor Solutions pays us for the utility bills issued to their utility-bill management customers. We recorded revenues of $3 million and $17 million for the three and nine months ended September 30, 2012 and $3 million and $24 million for the three and nine months ended September 30, 2011 associated with the payments Nicor Solutions made to us on behalf of its customers.
As a natural gas supplier, Nicor Advanced Energy pays us for delivery charges, administrative charges and applicable taxes. Nicor Advanced Energy paid us $1 million and $4 million for the three and nine months ended September 30, 2012 and 2011. Additionally, Nicor Advanced Energy may pay or receive inventory imbalance adjustments. The amounts Nicor Advanced Energy received from us for the three and nine months ended September 30, 2012 were $1 million and the amounts for the three and nine months ended September 30, 2011 were less than $1 million.
Horizon Pipeline charged us $3 million and $8 million for the three and nine months ended September 30, 2012 and 2011 for natural gas transportation under rates that have been accepted by the FERC.
In addition, certain related parties may acquire regulated utility services at rates approved by the Illinois Commission.
We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. The only material subsequent event of which we are aware is as follows:
On October 26, 2012, Nicor Gas effected a supplemental indenture (the “Supplemental Indenture”) to the Indenture, dated January 1, 1954 (the “Indenture”), governing all of our outstanding series of First Mortgage Bonds. The Supplemental Indenture amends the Indenture to remove the Indenture’s requirement that we file periodic reports with the SEC and replaces this requirement with a requirement that, in the event we are not otherwise required to file reports with the SEC, we will supplementally make available quarterly and annual financial information to holders and potential purchasers of the First Mortgage Bonds. This summary of the Supplemental Indenture is qualified by reference to the Supplemental Indenture, a copy of which is filed as Exhibit 4.1 to this Quarterly Report and incorporated herein by reference.
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 our unaudited Condensed Consolidated Financial Statements in this quarterly filing, as well as our 2011 Form 10-K. Results for the interim periods presented are not necessarily indicative of the results to be expected for the full fiscal period due to seasonal and other factors.
Certain expectations and projections regarding our future performance referenced in this section and elsewhere in this report, as well as in other reports we file with the SEC or otherwise release to the public and on our website, are forward-looking statements within the meaning of the United States federal securities laws and are subject to uncertainties and risks. Senior officers and other employees may also make verbal statements to analysts, regulators, the media and others that are forward-looking.
Forward-looking statements involve matters that are not historical facts, and because these statements involve anticipated events or conditions, forward-looking statements often include words such as "anticipate," "assume," “believe,” "can," "could," "estimate," "expect," "forecast," "future," “goal,” "indicate," "intend," "may," “outlook,” "plan," “potential,” "predict," "project,” “proposed,” "seek," "should," "target," "would," or similar expressions. You are cautioned not to place undue reliance on our forward-looking statements. Our expectations are not guarantees and are based on currently available competitive, financial and economic data along with our operating plans. While we believe that our expectations are reasonable in view of currently available information, our expectations are subject to future events, risks and uncertainties, and there are numerous factors - many beyond our control - that could cause our actual results to vary significantly from our expectations.
Such events, risks and uncertainties include, but are not limited to, changes in price, supply and demand for natural gas and related products; the impact of changes in state and federal legislation and regulation, including any changes related to climate change; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; the impact on cost and timeliness of construction projects by government and other approvals, development project delays, adequacy of supply of diversified vendors, unexpected changes in project costs, including the cost of funds to finance these projects
; limits on pipeline capacity; the impact of acquisitions and divestitures; direct or indirect effects on our business, financial condition or liquidity resulting from
any change in our credit ratings resulting from the merger between AGL Resources and Nicor or otherwise, or any change in the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions, including disruptions in the capital markets and lending environment and the economic downturn; general economic conditions; uncertainties about environmental issues and the related impact of such issues, including our environmental remediation plans; 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; the outcome of litigation; and other factors discussed elsewhere herein and in our filings with the SEC.
We caution readers that the important factors described elsewhere in this report, among others, could cause our business, results of operations or financial condition to differ significantly from those expressed in any forward-looking statements. There also may be other factors that we cannot anticipate or that are not described 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 United States federal securities law.
We are a natural gas distribution company whose operations are subject to regulation and oversight by the Illinois Commission. The Illinois Commission approves natural gas rates designed to provide us the opportunity to generate revenues to recover the cost of natural gas delivered to our customers and our fixed and variable costs such as depreciation, interest, maintenance and overhead costs, and to earn a reasonable return. Our earnings 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.
On December 9, 2011, AGL Resources and Nicor merged and we became a wholly owned subsidiary of AGL Resources. As a condition to the Illinois Commission’s approval of the merger, we are not allowed to initiate a rate case proceeding that would increase our rates prior to December 9, 2014.
Because of our significant outstanding public debt, the impact of the acquisition (push-down accounting) was not required to be, and has not been, reflected in our unaudited Condensed Consolidated Financial Statements.
We primarily generate our operating revenues through the sale and distribution of natural gas. We include in our consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed, to residential, commercial and industrial customers, from the date of the last bill to the end of the reporting period. No individual customer or industry accounts for a significant portion of our revenues.
We evaluate our performance using the measures of operating margin and EBIT. Operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of goods sold and revenue tax expense. Operating margin excludes operation and maintenance expense, depreciation and amortization, certain taxes other than income taxes, and the gain or loss on the sale of our assets, if any. These items are included in our calculation of operating income as reflected in our unaudited Condensed Consolidated Statements of Income. EBIT is also a non-GAAP measure that includes operating income and other income and expenses. Items that we do not include in EBIT are financing costs, including interest and debt expense and income taxes, each of which we evaluate on a consolidated basis.
We believe operating margin is a better indicator than operating revenues for the contribution resulting from customer growth since the cost of goods sold and revenue tax expense can vary significantly and are generally billed directly to our customers. We have a franchise gas cost rider, an energy efficiency rider and a bad debt rider. Changes in revenue and operating margin attributable to these riders are generally expected to be offset by changes within operation and maintenance expense with generally no impact on operating income.
We believe EBIT is a useful measurement of our performance because it provides information that can be used to evaluate the effectiveness of our business 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 our 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 as determined in accordance with GAAP. In addition, our operating margin and EBIT measures may not be comparable to similarly titled measures of other companies. The following table reconciles operating revenue and operating margin to operating income and EBIT to earnings before income taxes and net income, together with other consolidated financial information for the periods presented.
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
In millions
|
|
2012
|
|
|
2011
|
|
|
Change
|
|
|
2012
|
|
|
2011
|
|
|
Change
|
|
Operating revenues
|
|
$
|
210
|
|
|
$
|
240
|
|
|
$
|
(30
|
)
|
|
$
|
1,072
|
|
|
$
|
1,515
|
|
|
$
|
(443
|
)
|
Cost of goods sold
|
|
|
(64
|
)
|
|
|
(93
|
)
|
|
|
29
|
|
|
|
(515
|
)
|
|
|
(915
|
)
|
|
|
400
|
|
Revenue tax expense
(1)
|
|
|
(14
|
)
|
|
|
(14
|
)
|
|
|
0
|
|
|
|
(95
|
)
|
|
|
(119
|
)
|
|
|
24
|
|
Operating margin
|
|
|
132
|
|
|
|
133
|
|
|
|
(1
|
)
|
|
|
462
|
|
|
|
481
|
|
|
|
(19
|
)
|
Revenue tax expense
(1)
|
|
|
14
|
|
|
|
14
|
|
|
|
0
|
|
|
|
95
|
|
|
|
119
|
|
|
|
(24
|
)
|
Operating expenses
|
|
|
(131
|
)
|
|
|
(126
|
)
|
|
|
(5
|
)
|
|
|
(474
|
)
|
|
|
(484
|
)
|
|
|
10
|
|
Total operating expenses
(2)
|
|
|
(117
|
)
|
|
|
(112
|
)
|
|
|
(5
|
)
|
|
|
(379
|
)
|
|
|
(365
|
)
|
|
|
(14
|
)
|
Operating income and EBIT
|
|
|
15
|
|
|
|
21
|
|
|
|
(6
|
)
|
|
|
83
|
|
|
|
116
|
|
|
|
(33
|
)
|
Interest expense, net
|
|
|
(7
|
)
|
|
|
(8
|
)
|
|
|
1
|
|
|
|
(23
|
)
|
|
|
(23
|
)
|
|
|
0
|
|
Earnings before income taxes
|
|
|
8
|
|
|
|
13
|
|
|
|
(5
|
)
|
|
|
60
|
|
|
|
93
|
|
|
|
(33
|
)
|
Income tax expense
|
|
|
(4
|
)
|
|
|
(5
|
)
|
|
|
1
|
|
|
|
(24
|
)
|
|
|
(35
|
)
|
|
|
11
|
|
Net income
|
|
$
|
4
|
|
|
$
|
8
|
|
|
$
|
(4
|
)
|
|
$
|
36
|
|
|
$
|
58
|
|
|
$
|
(22
|
)
|
(1)
|
Adjustment for revenue tax expenses which are passed directly through to our customers.
|
(2)
|
Excludes cost of goods sold and revenue tax expense.
|
Our EBIT in the third quarter decreased by $6 million or 29% compared to last year as shown in the following table.
In millions
|
|
|
|
EBIT - for third quarter of 2011
|
|
$
|
21
|
|
|
|
|
|
|
Operating margin
|
|
|
|
|
Reduced revenues primarily from lower customer late payment charges
|
|
|
(1
|
)
|
Decrease in operating margin
|
|
|
(1
|
)
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
Increased depreciation expense
|
|
|
2
|
|
Increased operation and maintenance expenses
|
|
|
3
|
|
Increase in operating expenses
|
|
|
5
|
|
EBIT - for third quarter of 2012
|
|
$
|
15
|
|
Our EBIT for the nine months ended September 30, 2012, decreased by $33 million or 28% compared to last year as shown in the following table.
In millions
|
|
|
|
EBIT - for nine months of 2011
|
|
$
|
116
|
|
|
|
|
|
|
Operating margin
|
|
|
|
|
Reduced revenues primarily from warmer weather and reduced demand
|
|
|
(26
|
)
|
Increased revenues due to the impact of cost-recovery riders which are offset in operation and maintenance expense
|
|
|
7
|
|
Decrease in operating margin
|
|
|
(19
|
)
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
Increased expenses due to the impact of cost-recovery riders which are offset in revenue and operating margin
|
|
|
7
|
|
Increased depreciation expense
|
|
|
5
|
|
Other
|
|
|
2
|
|
Increase in operating expenses
|
|
|
14
|
|
EBIT - for nine months of 2012
|
|
$
|
83
|
|
Our income tax expense decreased by $1 million for the third quarter 2012 and $11 million for the nine months ended September 30, 2012, compared to the same periods in 2011 primarily due to lower earnings.
Selected weather, customer and volume metrics as of and for the three and nine months ended September 30, 2012 and 2011, which we consider to be some of the key performance indicators for our business, 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 system. However, extended and unusually warm weather during the first quarter of 2012 had 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. Volumes delivered to customers, as shown in the following table, reflect the effects of warmer weather and our customers’ demand for natural gas compared to the prior year.
|
|
|
|
|
|
|
|
|
Heating degree days (1)
|
|
|
|
|
|
|
|
|
Nine months ended
September 30,
|
|
|
2012 vs. normal
|
|
|
2012 vs. 2011
|
|
|
Normal
|
|
|
2012
|
|
|
2011
|
|
|
colder (warmer)
|
|
|
colder (warmer)
|
Illinois
|
|
|
3,610
|
|
|
|
2,973
|
|
|
|
4,082
|
|
|
|
(18
|
)%
|
|
|
(27
|
)%
|
|
|
Three months ended September 30,
|
|
|
2012 vs. 2011
|
|
|
Nine months ended September 30,
|
|
|
2012 vs. 2011
|
|
Customers
(in thousands)
|
|
2012
|
|
|
2011
|
|
|
% change
|
|
|
2012
|
|
|
2011
|
|
|
% change
|
|
Average end-use customers
|
|
|
2,181
|
|
|
|
2,174
|
|
|
|
0.3
|
%
|
|
|
2,188
|
|
|
|
2,186
|
|
|
|
0.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
2012 vs. 2011
|
|
|
Nine months ended September 30,
|
|
|
2012 vs. 2011
|
|
Volumes
(in Bcf)
|
|
2012
|
|
|
2011
|
|
|
% change
|
|
|
2012
|
|
|
2011
|
|
|
% change
|
|
Delivered
|
|
|
54.7
|
|
|
|
52.8
|
|
|
|
4
|
%
|
|
|
287.1
|
|
|
|
333.7
|
|
|
|
(14
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Obtained from the Chicago Midway Airport weather station. Normal represents a ten-year average from 1998 through 2007, which was established in our last rate case.
|
Overview
The acquisition of natural gas and pipeline capacity 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. 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 Statements of Financial Position, ensuring ample cash resources and daily liquidity, accessing capital markets at favorable times as necessary, managing critical business risks and maintaining a balanced capital structure through the appropriate issuance of long-term debt securities. Our issuance of long-term debt is subject to customary approval or review by state and federal regulatory bodies including the Illinois Commission and at times the SEC.
We believe the amounts available to us under our credit facility, through the issuance of debt securities, combined with cash provided by operating activities, will continue to allow us to meet our needs for working capital, capital expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs for the foreseeable future. Our ability to satisfy our working capital requirements and our debt service obligations, or fund planned capital expenditures, will substantially depend upon our future operating performance (which will be affected by prevailing economic conditions), and financial, business and other factors, some of which we are unable to control. These factors include, among others, regulatory changes, the price of and demand for natural gas and operational risks.
We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by rating agencies and other factors. See Item 1A - Risk Factors in our 2011 Form 10-K for additional information on items that could impact our liquidity and capital resource requirements.
Credit Ratings
Our borrowing costs and our ability to obtain adequate and cost effective financing are directly impacted by our credit ratings as well as the availability of financial markets. Credit ratings are important to our counterparties when we engage in certain transactions including over-the-counter derivatives. It is our long-term objective to maintain or improve our credit ratings in order to manage our existing financing costs.
Credit ratings and outlooks are opinions that are subject to ongoing review by the rating agencies and may periodically change. The rating agencies regularly review our performance, prospects and financial condition and reevaluate their ratings of our long-term debt and short-term borrowings, our corporate ratings and our ratings outlook. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. A credit rating is not a recommendation to buy, sell or hold securities and each rating should be evaluated independently of other ratings.
Factors we consider important in assessing our credit ratings include our Consolidated Statements of Financial Position leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any trigger events in our debt instruments that are tied to changes in our specified credit ratings. The following table summarizes our credit ratings as of September 30, 2012 and reflects no change from December 31, 2011.
|
|
S&P
|
|
|
Moody’s
|
|
|
Fitch
|
|
Corporate rating
|
|
BBB+
|
|
|
|
n/a
|
|
|
|
A
|
|
Commercial paper
|
|
|
A-2
|
|
|
|
P-2
|
|
|
|
F-1
|
|
Senior unsecured
|
|
BBB+
|
|
|
|
A3
|
|
|
|
A+
|
|
Senior secured
|
|
|
A
|
|
|
|
A1
|
|
|
AA-
|
|
Ratings outlook
|
|
Stable
|
|
|
Stable
|
|
|
Stable
|
|
Our credit ratings depend largely on our financial performance, and a downgrade in our current ratings, particularly below investment grade, would increase our borrowing costs and could limit our access to the commercial paper market. In addition, we would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease.
Default Provisions
Our debt instruments and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. Our credit facility contains customary events of default, including, but not limited to, the failure to pay any interest or principal when due, the failure to furnish financial statements within the timeframe established by each debt facility, the failure to comply with certain affirmative and negative covenants, cross-defaults to certain other material indebtedness in excess of specified amounts, incorrect or misleading representations or warranties, insolvency or bankruptcy, fundamental change of control, the occurrence of certain Employee Retirement Income Security Act events, judgments in excess of specified amounts and certain impairments to the guarantee.
Our credit facility contains certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations, and other matters customarily restricted in such agreements.
Our credit facility also includes a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month. This ratio, as defined within our debt agreements, includes standby letters of credit and surety bonds and excludes accumulated OCI. Adjusting for these items, our debt-to-capitalization ratio for September 30, 2012 was 51%, which is within our required range.
We were in compliance with all of our debt provisions and covenants, both financial and non-financial, for all periods presented.
Our ratio of total debt to total capitalization 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. Maintaining sufficient cash flow is necessary to maintain attractive credit ratings. For more information on our default provisions see Note 6 to our unaudited Condensed Consolidated Financial Statements under item 1 herein.
Cash Flows
The following table provides a summary of our operating, investing and financing cash flows for the periods presented.
|
|
Nine months ended September 30,
|
|
|
|
|
In millions
|
|
2012
|
|
|
2011
|
|
|
Variance
|
|
Net cash provided by (used in):
|
|
|
|
|
Operating activities
|
|
$
|
449
|
|
|
$
|
357
|
|
|
$
|
92
|
|
Investing activities
|
|
|
(141
|
)
|
|
|
(136
|
)
|
|
|
(5
|
)
|
Financing activities
|
|
|
(308
|
)
|
|
|
(221
|
)
|
|
|
(87
|
)
|
Net increase in cash and cash equivalents
|
|
$
|
0
|
|
|
$
|
0
|
|
|
$
|
0
|
|
Cash Flow from Operating Activities
Year-over-year changes in our operating cash flows are due primarily to working capital changes resulting from the impact of weather, the price of natural gas and natural gas storage, and the timing of natural gas purchases and related recoveries from customers.
We maintain margin accounts related to financial derivative transactions. These margin accounts may cause large fluctuations in cash needs or sources in a relatively short period of time due to daily settlements resulting from changes in natural gas futures prices. We manage these fluctuations with short-term borrowings and investments.
Net cash flow provided from operating activities increased $92 million, or 26%, for the nine months ended September 30, 2012 compared to the prior year. The increase in operating cash flow is primarily related to a $64 million increase provided from changes in accounts payable and a $51 million change in inventories. These changes were partially offset by other changes in working capital of $15 million.
Cash Flow from Investing Activities
Net cash flow used for investing activities, which primarily consists of our PP&E expenditures, increased $5 million, or 4%, for the nine months ended September 30, 2012 compared to the prior year.
Cash Flow from Financing Activities
Information regarding our short-term debt for the nine months ended September 30, 2012 is summarized below.
In millions
|
|
Period end balance outstanding
(1)
|
|
|
Daily average balance outstanding
(2)
|
|
|
Minimum balance outstanding
(2)
|
|
|
Largest balance outstanding
(2)
|
|
Commercial paper
|
|
$
|
173
|
|
|
$
|
116
|
|
|
$
|
0
|
|
|
$
|
456
|
|
(1)
|
As of September 30, 2012.
|
(2)
|
For the nine months ended September 30, 2012.
|
The largest, minimum and daily average balances borrowed under our commercial paper program are important when assessing the intra-period fluctuations of our short-term borrowings and potential liquidity risk. These fluctuations are due to our
seasonal cash requirements.
As of September 30, 2012, $527 was available under the Nicor Gas Credit Facility.
Increasing natural gas commodity prices can have a significant impact on our commercial paper borrowings. Based on current natural gas prices and our expected injection plan, a $1 NYMEX price change could result in a $66 million change of working capital requirements for the remainder of the 2012 injection season. This range is sensitive to the timing of storage injections and withdrawals, collateral requirements and our portfolio position. Based on current natural gas prices and our expected purchases during the upcoming injection season, we believe that we have sufficient liquidity to cover our working capital needs for the upcoming Heating Season.
The lenders under our credit facility are major financial institutions with investment grade credit ratings as of September 30, 2012. 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.
Contractual Obligations and Commitments
We have incurred various contractual obligations and financial commitments in the normal course of business that are reasonably likely to have a material effect on liquidity or the availability of requirements for capital resources. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. Contingent financial commitments represent obligations that become payable only if certain predefined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor.
There were no significant changes to our contractual obligations described in Note 7 of our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K other than the revised ERC and termination of the SNG contract.
Substitute Natural Gas
In 2011, Illinois enacted laws that required us and other large utilities in Illinois to elect to either sign contracts to purchase SNG from coal gasification plants to be constructed in Illinois or instead file rate cases with the Illinois Commission in 2012, 2014 and 2016.
On September 30, 2011, we signed an agreement to purchase approximately 25 Bcf of SNG annually for a 10-year term beginning as early as 2015. The agreement required, among other things, the developer to begin construction of the SNG plant by July 1, 2012. The developer did not meet this deadline and, as a result, the agreement automatically terminated.
Additionally, on October 11, 2011, the Illinois Power Agency (IPA) approved the form of a draft 30-year contract for the purchase by us of approximately 20 Bcf per year of SNG from a second proposed plant beginning as early as 2018. The purchase price of the SNG that may be produced from this proposed coal gasification plant may significantly exceed market prices for natural gas and is expected to be dependent upon a variety of factors, including the developer’s financing, plant construction costs and volumes sold, which are currently not determinable. The Illinois law pertaining to this plant provides that the price paid for SNG purchased from the plant is to be considered prudent and not subject to review or disallowance by the Illinois Commission. As such, Illinois law effectively requires our customers to provide subordinated financial support to the developer.
In November 2011, we filed a lawsuit against the IPA and the developer of this second proposed plant contending that the draft contract approved by the IPA does not conform to certain requirements of the enabling legislation. The lawsuit is pending in circuit court in DuPage County, Illinois. In accordance with the enabling legislation, the draft contract approved by the IPA for the second proposed plant was submitted to the Illinois Commission for further approvals by that regulatory body. The Illinois Commission issued an order on January 10, 2012 approving a final form of the contract for the second plant. The final form of contract approved by the Illinois Commission modified the draft contract submitted by the IPA in various respects. Both we and the developer of the plant filed applications for a rehearing with the Illinois Commission seeking changes to the final form of the contract. The Illinois Commission agreed to grant a rehearing. On July 11, 2012, the Illinois Commission issued its order on rehearing in which it modified its earlier order to change certain of the terms of the approved form of SNG purchase contract. The Illinois state court denied our appeal of the Illinois Commission’s order, but that does not impact the pending DuPage County lawsuit challenging the IPA’s earlier order approving the draft form of contract. In May 2012, the Illinois legislature passed a bill that directed the Illinois Commission to approve a final form of contract that differed in certain respects from the form the Illinois Commission approved in its July 11, 2012 order and that purported to address issues raised in the our pending lawsuit against the IPA. This bill was vetoed by the Governor of Illinois on August 10, 2012
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As a result of pending litigation challenging aspects of the IPA and Illinois Commission decisions regarding the contract terms, we have not yet signed a contract with the developer to purchase SNG from the second proposed plant.
The following contingencies are in various stages of investigation or disposition. Although in some cases we are unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require us to take charges against, or will result in reductions in, future earnings. It is the opinion of our management that the resolution of these contingencies, either individually or in aggregate, could be material to earnings in a particular period but is not expected to have a material adverse impact on our liquidity or financial condition.
PBR Proceeding
Our PBR plan for natural gas costs went into effect in 2000 and was terminated by us effective January 1, 2003. Under this plan, our total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. The PBR plan is currently under review by the Illinois Commission as there are allegations that we acted improperly in connection with the PBR plan. On June 27, 2002, the Citizens Utility Board (CUB) filed a motion to reopen the record in the Illinois Commission’s proceedings to review the PBR plan. As a result of the motion to reopen, we entered into a stipulation with the staff of the Illinois Commission and CUB providing for additional discovery. The Illinois Attorney General’s Office (IAGO) has also intervened in this matter. In addition, the IAGO issued Civil Investigation Demands (CIDs) to CUB and the Illinois Commission staff. The CIDs ordered that CUB and the Illinois Commission staff produce all documents relating to any claims that we may have presented, or caused to be presented, regarding false information related to our PBR plan. The staff of the Illinois Commission, IAGO and CUB submitted direct testimony to the Illinois Commission in April 2009 and rebuttal testimony in October 2011. In rebuttal testimony, the staff of the Illinois Commission, IAGO and CUB requested refunds of $85 million, $255 million and $305 million, respectively. We have committed to cooperate fully in the reviews of the PBR plan.
In February 2012, we committed to a stipulated resolution of issues with the staff of the Illinois Commission, which includes crediting our customers $64 million, which is not recoverable from our customers. The stipulated resolution does not constitute an admission of fault, and it is not final and is subject to review and approval by the Illinois Commission. CUB and IAGO are not parties to the stipulated resolution and continue to pursue their claims in this proceeding. Evidentiary hearings before the Administrative Law Judge were held during the first quarter of 2012 and post-trial legal briefs from the parties were submitted during the second quarter of 2012. Following the submission of legal briefs, the Administrative Law Judge will issue a proposed decision. There is no date scheduled for the issuance of that proposed decision.
We are unable to predict the outcome of the Illinois Commission’s review or our potential exposure. Since the PBR plan and historical gas costs are still under Illinois Commission review, the final outcome could be materially different than the amount reflected in our financial statements as of September 30, 2012. For additional information on our PBR proceedings, see Note 7 in our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K.
Environmental Remediation Costs
We have conducted environmental investigations and remedial activities at our former manufactured gas plant sites. Additional information about these sites is presented in Item 1 - Notes to the Condensed Consolidated Financial Statements - Note 7 - Commitments, Guarantees and Contingencies.
Critical
Accounting Policies and Estimates
The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts in our unaudited Condensed Consolidated Financial Statements and accompanying notes. Those judgments and estimates have a significant effect on our financial statements primarily due to the need to make estimates about the effects of matters that are inherently uncertain. Actual results could differ from those estimates. We frequently reevaluate our judgments and estimates that are based upon historical experience and various other assumptions that we believe to be reasonable under the circumstances.
Each of our critical accounting estimates involves complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. There have been no significant changes to our critical accounting estimates from those disclosed in our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2011 Form 10-K, except for the $109 million increase to our ERC liabilities in the second quarter of 2012.
Our critical accounting estimates used in the preparation of our unaudited Condensed Consolidated Financial Statements include the following:
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Environmental Remediation Costs
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Derivatives and Hedging Activities
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Contingencies
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Pension and Other Retirement Plans
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Credit Risk
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Unbilled Revenues
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Regulatory Assets and Liabilities
Accounting Developments
On December 16, 2011, the FASB issued authoritative guidance related to disclosures about offsetting assets and liabilities. The guidance requires disclosure about offsetting and related arrangements in order to help financial statement users to better understand the effect of those arrangements on our financial position. This guidance will be effective beginning January 1, 2013 and will not have a material impact on our consolidated financial statements.