form_10-qa.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q/A
 Amendment No. 1
   
QUARTERLY REPORT PURSUANT TO SECTION 13 OF
THE SECURITIES EXCHANGE ACT OF 1934
 
For the Quarterly Period Ended September 30, 2014
 
 
 
Commission File Number 1-14174
 
AGL RESOURCES INC.
Ten Peachtree Place NE, Atlanta, Georgia 30309
404-584-4000
 
Georgia
58-2210952
(State of incorporation)
(I.R.S. Employer Identification No.)
 
 
AGL Resources Inc. (1) has filed all reports required to be filed by Section 13 of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 
AGL Resources Inc. has submitted electronically and posted on its corporate website every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months.

AGL Resources Inc. is a large accelerated filer and is not a shell company.
 
The number of shares of AGL Resources Inc.’s common stock, $5.00 Par Value, outstanding as of October 31, 2014, was 119,572,999.
 


 
 

 

 
TABLE OF CONTENTS
       
Page
 
Explanatory Note      3  
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          33  
 

 
 
2

 
 
Unless the context requires otherwise, references to “we,” “us,” “our,” the “company” or “AGL Resources” mean consolidated AGL Resources Inc. and its subsidiaries.

Explanatory Note:

We are filing this Amendment No. 1 on Form 10-Q/A (this “Amended Filing”) to our Quarterly Report on Form 10-Q for the period ended September 30, 2014 (the “Original Filing”), for the item discussed below. Accordingly, we hereby amend and replace in their entirety Items 1 and 4 in the Original Filing.

As required by Rule 12b-15, our principal executive officer and principal financial officer are providing updated certifications. Accordingly, we hereby amend and replace in its entirety Item 6 in the Original Filing to reflect the filing of the new certifications.

In the third quarter of 2014, we revised our financial statements and other affected disclosures for items related to the recognition of revenues for certain of our regulatory infrastructure programs and the amortization of our intangible assets. On November 7, 2014, we filed an amended Form 10-K/A revising certain prior period information with respect to our Annual Report on Form 10-K for the year ended December 31, 2013, due to the revenue recognition and amortization of intangible asset issues referred to above. We previously disclosed in our Form 10-K/A that the revisions did not impact any incentive compensation that was based on our results for 2013, 2012 and 2011.  However, subsequent to the filing of our Form 10-K/A, we determined that for 2011, had the underlying accounting originally reflected the distinction between regulatory accounting principles and GAAP, certain long-term incentives that were based on our results for the performance period ended December 31, 2011, would not have been awarded.  Specifically, in February 2012, based upon results for the performance period ended December 31, 2011, we would not have awarded officers (as defined for purposes of Section 16 of the Securities Exchange Act of 1934, as amended) (1) performance cash unit awards with an aggregate value of approximately $1 million and (2) a total of 37,290 shares of restricted stock. Management has evaluated this item in relation to its previously filed Form 10-K/A and materiality conclusions under Staff Accounting Bulletin No. 99 and has concluded that it would not change its prior materiality conclusion. This impact on executive compensation will be reviewed by the Compensation Committee of our Board of Directors and by the full Board to determine appropriate actions.

Except as indicated above, this Amended Filing does not purport to reflect any information or events subsequent to the filing date of the Original Filing. As such, this Amended Filing speaks only as of the date the Original Filing was filed, and we have not undertaken herein to amend, supplement or update any information contained in the Original Filing to give effect to any subsequent events. Accordingly, this Amended Filing should be read in conjunction with the Original Filing and any documents filed by us with the Securities and Exchange Commission (SEC) subsequent to the Original Filing, including our amended Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2014, filed with the SEC on November 25, 2014 and our amended Quarterly Report on Form 10-Q/A for the quarter ended June 30, 2014, filed with the SEC on November 25, 2014.



GLOSSARY OF KEY TERMS

2013 Form 10-K
Our Annual Report on Form 10-K for the year ended December 31, 2013, filed with the SEC on February 6, 2014
2013 Form 10-K/A
Amendment No. 1 to our Annual Report on Form 10-K for the year ended December 31, 2013, filed with the SEC on November 7, 2014
AFUDC
Allowance for funds used during construction, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects, capitalized in PP&E and considered rate base for ratemaking purposes
AGL Capital
AGL Capital Corporation
AGL Credit Facility
$1.3 billion credit agreement entered into by AGL Capital to support its commercial paper program, which matures in November 2017
AGL Resources
AGL Resources Inc., together with its consolidated subsidiaries
Atlanta Gas Light
Atlanta Gas Light Company
Atlantic Coast Pipeline
Atlantic Coast Pipeline, LLC
Bcf
Billion cubic feet
Compass Energy
Compass Energy Services, Inc., which was sold in 2013
Dalton Pipeline
A 50% undivided ownership interest in a pipeline facility in Georgia
EBIT
Earnings before interest and taxes, the primary measure of our operating segments’ profit or loss, which includes operating income and other income and excludes financing costs, including interest on debt and income tax expense
ERC
Environmental remediation costs
FASB
Financial Accounting Standards Board
GAAP
Accounting principles generally accepted in the United States of America
Georgia Commission
Georgia Public Service Commission, the state regulatory agency for Atlanta Gas Light
Heating Season
The period from November through March when natural gas usage and operating revenues are generally higher
Horizon Pipeline
Horizon Pipeline Company, LLC
Illinois Commission
Illinois Commerce Commission, the state regulatory agency for Nicor Gas
LIFO
Last-in, first-out
LOCOM
Lower of weighted average cost or market price
Marketers
Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
MGP
Manufactured Gas Plant
New Jersey BPU
New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
Nicor Gas
Northern Illinois Gas Company, doing business as Nicor Gas Company
Nicor Gas Credit Facility
$700 million credit facility entered into by Nicor Gas to support its commercial paper program, which matures in December 2017
OCI
Other comprehensive income
Operating margin
A non-GAAP measure of income, calculated as operating revenues minus cost of goods sold and revenue tax expense
PBR
Performance-based rate
PennEast Pipeline
PennEast Pipeline Company, LLC
Piedmont
Piedmont Natural Gas Company, Inc.
PP&E
Property, plant and equipment
SEC
Securities and Exchange Commission
Sequent
Sequent Energy Management, L.P.
SouthStar
SouthStar Energy Services, LLC
Triton
Triton Container Investments, LLC
Tropical Shipping
Tropical Shipping and Construction Company Limited, and also the name used throughout this filing to describe the business operations of our former cargo shipping segment (excluding Triton), which has been classified as discontinued operations and held for sale
VIE
Variable interest entity
WACOG
Weighted average cost of gas


 
4


PART I – FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited)
 
 
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(UNAUDITED)

   
As of
 
   
September 30, 2014
   
December 31, 2013
   
September 30, 2013
 
In millions, except share amounts
       
Revised
   
Revised
 
Current assets
                 
Cash and cash equivalents
  $ 32     $ 81     $ 97  
Short-term investments
    8       49       41  
Receivables
                       
Energy marketing
    544       786       502  
Gas, unbilled and other
    409       736       308  
Less allowance for uncollectible accounts
    37       29       32  
Total receivables, net
    916       1,493       778  
                         
Inventories, net
    796       658       788  
Regulatory assets
    105       114       87  
Derivative instruments
    102       99       97  
Assets held for sale
    -       283       294  
Other
    134       118       70  
Total current assets
    2,093       2,895       2,252  
Long-term assets and other deferred debits
                       
Property, plant and equipment
    11,352       10,938       10,761  
Less accumulated depreciation
    2,427       2,295       2,281  
Property, plant and equipment, net
    8,925       8,643       8,480  
Goodwill
    1,827       1,827       1,822  
Regulatory assets
    637       705       845  
Intangible assets
    130       145       152  
Other
    341       335       259  
Total long-term assets and other deferred debits
    11,860       11,655       11,558  
Total assets
  $ 13,953     $ 14,550     $ 13,810  
Current liabilities
                       
Short-term debt
  $ 681     $ 1,171     $ 832  
Energy marketing trade payables
    612       671       539  
Other accounts payable - trade
    298       421       295  
Current portion of long-term debt
    200       -       -  
Accrued expenses
    173       203       149  
Customer deposits and credit balances
    122       136       140  
Regulatory liabilities
    118       183       174  
Accrued environmental remediation liabilities
    82       70       48  
Derivative instruments
    45       75       38  
Liabilities held for sale
    -       40       39  
Other
    131       148       153  
Total current liabilities
    2,462       3,118       2,407  
Long-term liabilities and other deferred credits
                       
Long-term debt
    3,605       3,813       3,816  
Accumulated deferred income taxes
    1,655       1,628       1,551  
Regulatory liabilities
    1,567       1,518       1,524  
Accrued pension and retiree welfare benefits
    406       404       511  
Accrued environmental remediation liabilities
    372       377       416  
Other
    84       79       79  
Total long-term liabilities and other deferred credits
    7,689       7,819       7,897  
Total liabilities and other deferred credits
    10,151       10,937       10,304  
Commitments, guarantees and contingencies (see Note 10)
                       
Equity
                       
Common stock, $5 par value; 750,000,000 shares authorized:
outstanding: 119,564,666 shares at September 30, 2014, 118,888,876 shares at December 31, 2013, and 118,778,298 shares at September 30, 2013
    599       595       595  
Additional paid-in capital
    2,080       2,054       2,047  
Retained earnings
    1,222       1,063       1,042  
Accumulated other comprehensive loss
    (133 )     (136 )     (208 )
Treasury shares, at cost: 216,523 shares at September 30, 2014, December 31, 2013, and September 30, 2013
    (8 )     (8 )     (8 )
Total common shareholders’ equity
    3,760       3,568       3,468  
Noncontrolling interest
    42       45       38  
Total equity
    3,802       3,613       3,506  
Total liabilities and equity
  $ 13,953     $ 14,550     $ 13,810  
See Notes to Condensed Consolidated Financial Statements (Unaudited).
 
5


AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)

   
Three months ended
   
Nine months ended
 
   
September 30,
   
September 30,
 
   
2014
   
2013
   
2014
   
2013
 
In millions, except per share amounts
       
Revised
         
Revised
 
Operating revenues (includes revenue taxes of $9 and $103 for the three and nine months in 2014 and $9 and $83 for the three and nine months in 2013)
  $ 589     $ 574     $ 3,940     $ 2,991  
Operating expenses
                               
Cost of goods sold
    198       174       2,000       1,447  
Operation and maintenance
    193       199       693       634  
Depreciation and amortization
    93       104       281       309  
Taxes other than income taxes
    30       27       160       139  
Total operating expenses
    514       504       3,134       2,529  
Gain on disposition of assets
    3       -       3       11  
Operating income
    78       70       809       473  
Other income
    3       7       8       18  
Interest expense, net
    (44 )     (37 )     (135 )     (126 )
Income before income taxes
    37       40       682       365  
Income tax expense
    14       16       254       137  
Income from continuing operations
    23       24       428       228  
(Loss) income from discontinued operations, net of tax
    (31 )     1       (80 )     1  
Net (loss) income
    (8 )     25       348       229  
Less net income attributable to the noncontrolling interest
    -       -       14       11  
Net (loss) income attributable to AGL Resources Inc.
  $ (8 )   $ 25     $ 334     $ 218  
Per common share information
                               
Basic earnings (loss) per common share
                               
Continuing operations
  $ 0.19     $ 0.20     $ 3.48     $ 1.85  
Discontinued operations
    (0.25 )     0.01       (0.67 )     0.01  
Basic (loss) earnings per common share attributable to AGL Resources Inc. common shareholders
  $ (0.06 )   $ 0.21     $ 2.81     $ 1.86  
Diluted earnings (loss) per common share
                               
Continuing operations
  $ 0.19     $ 0.20     $ 3.47     $ 1.84  
Discontinued operations
    (0.25 )     0.01       (0.67 )     0.01  
Diluted (loss) earnings per common share attributable to AGL Resources Inc. common shareholders
  $ (0.06 )   $ 0.21     $ 2.80     $ 1.85  
Cash dividends declared per common share
  $ 0.49     $ 0.47     $ 1.47     $ 1.41  
Weighted average number of common shares outstanding
                               
Basic
    119.0       118.2       118.8       117.8  
Diluted
    119.4       118.5       119.2       118.1  

See Notes to Condensed Consolidated Financial Statements (Unaudited).

 
6



AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)

   
Three months ended
   
Nine months ended
 
   
September 30,
   
September 30,
 
   
2014
   
2013
   
2014
   
2013
 
In millions
       
Revised
         
Revised
 
Net (loss) income
  $ (8 )   $ 25     $ 348     $ 229  
Other comprehensive income (loss), net of tax
                               
Retirement benefit plans
                               
Reclassification of actuarial losses to net benefit cost (net of income tax of $2 and $5 for the three and nine months ended September 30, 2014, and $3 and $8 for the three and nine months ended September 30, 2013)
    2       3       7       11  
Reclassification of prior service credits to net benefit cost (net of income tax of $(1) for the nine months ended September 30, 2013)
    -       (2 )     (1 )     (3 )
Retirement benefit plans
    2       1       6       8  
Cash flow hedges, net of tax
                               
Net derivative instrument (losses) gains arising during the period
    (2 )     -       2       -  
Reclassification of realized derivative instrument (gains) losses to net income (net of income tax of $(1) for the nine months ended September 30, 2014 and $1 for the nine months ended September 30, 2013)
    -       -       (5 )     2  
Cash flow hedges, net
    (2 )     -       (3 )     2  
Other comprehensive income, net of tax
    -       1       3       10  
Comprehensive (loss) income
    (8 )     26       351       239  
Less comprehensive income attributable to noncontrolling interest
    -       -       14       11  
Comprehensive (loss) income attributable to AGL Resources Inc.
  $ (8 )   $ 26     $ 337     $ 228  

See Notes to Condensed Consolidated Financial Statements (Unaudited).

 
7


AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(UNAUDITED)

   
AGL Resources Inc. Shareholders
             
   
Common stock
         
Retained
   
Accumulated other
   
 
             
   
 
   
 
   
Additional paid-in
   
earnings
   
comprehensive
   
Treasury
   
Noncontrolling
   
Total
 
In millions, except per share amounts
  Shares     Amount     capital    
Revised
    loss     shares     interest    
Revised
 
Balance as of December 31, 2012
    117.9     $ 590     $ 2,015     $ 990     $ (218 )   $ (8 )   $ 22     $ 3,391  
Net income
    -       -       -       218       -       -       11       229  
Other comprehensive income
    -       -       -       -       10       -       -       10  
Dividends on common stock ($1.41 per share)
    -       -       -       (166 )     -       -       -       (166 )
Contribution from noncontrolling interest
    -       -       -       -       -       -       22       22  
Distributions to noncontrolling interests
    -       -       -       -       -       -       (17 )     (17 )
Stock granted, share-based compensation, net of forfeitures
    -       -       (6 )     -       -       -       -       (6 )
Stock issued, dividend reinvestment plan
    0.2       1       7       -       -       -       -       8  
Stock issued, share-based compensation, net of forfeitures
    0.7       4       22       -       -       -       -       26  
Stock-based compensation expense, net of tax
    -       -       9       -       -       -       -       9  
Balance as of September 30, 2013
    118.8     $ 595     $ 2,047     $ 1,042     $ (208 )   $ (8 )   $ 38     $ 3,506  

   
AGL Resources Inc. Shareholders
             
   
Common stock
   
 
   
Retained
   
Accumulated other
   
 
   
 
       
               
Additional paid-in
   
earnings
    comprehensive    
Treasury
   
Noncontrolling
   
Total
 
In millions, except per share amounts
  Shares     Amount     capital    
Revised
    loss     shares     interest    
Revised
 
Balance as of December 31, 2013
    118.9     $ 595     $ 2,054     $ 1,063     $ (136 )   $ (8 )   $ 45     $ 3,613  
Net income
    -       -       -       334       -       -       14       348  
Other comprehensive income
    -       -       -       -       3       -       -       3  
Dividends on common stock ($1.47 per share)
    -       -       -       (175 )     -       -       -       (175 )
Distributions to noncontrolling interests
    -       -       -       -       -       -       (17 )     (17 )
Stock granted, share-based compensation, net of forfeitures
    -       -       (11 )     -       -       -       -       (11 )
Stock issued, dividend reinvestment plan
    0.1       1       8       -       -       -       -       9  
Stock issued, share-based compensation, net of forfeitures
    0.6       3       19       -       -       -       -       22  
Stock-based compensation expense, net of tax
    -       -       10       -       -       -       -       10  
Balance as of September 30, 2014
    119.6     $ 599     $ 2,080     $ 1,222     $ (133 )   $ (8 )   $ 42     $ 3,802  

See Notes to Condensed Consolidated Financial Statements (Unaudited).

 
8



AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

   
Nine months ended
 
   
September 30,
 
 
 
2014
   
2013
 
In millions        
Revised
 
Cash flows from operating activities
           
Net income
  $ 348     $ 229  
Adjustments to reconcile net income to net cash flow provided by operating activities
               
Depreciation and amortization
    281       309  
Loss (income) from discontinued operations, net of taxes
    80       (1 )
Deferred income taxes
    47       (32 )
Change in derivative instrument assets and liabilities
    (27 )     37  
Gain on disposition of assets
    (3 )     (11 )
Changes in certain assets and liabilities
               
Inventories
    (138 )     (89 )
Receivables, other than energy marketing
    335       359  
Energy marketing receivables and trade payables, net
    183       98  
Income and miscellaneous taxes
    (113 )     75  
Trade payables, other than energy marketing
    (81 )     (20 )
Accrued/deferred natural gas costs
    (65 )     14  
Other, net
    37       82  
Net cash flow (used in) provided by operating activities of discontinued operations
    (10 )     20  
Net cash flow provided by operating activities
    874       1,070  
Cash flows from investing activities
               
Expenditures for property, plant and equipment
    (543 )     (526 )
Acquisitions of assets
    -       (154 )
Disposition of assets
    225       12  
Other
    47       16  
Net cash flow used in investing activities of discontinued operations
    (13 )     (9 )
Net cash flow used in investing activities
    (284 )     (661 )
Cash flows from financing activities
               
Net repayments of commercial paper
    (490 )     (545 )
Dividends paid on common shares
    (175 )     (166 )
Distribution to noncontrolling interest
    (17 )     (17 )
Payment of senior notes
    -       (225 )
Issuance of senior notes
    -       494  
Contribution from noncontrolling interest
    -       22  
Other, net
    19       28  
Net cash flow used in financing activities
    (663 )     (409 )
Net decrease in cash and cash equivalents - continuing operations
    (50 )     (11 )
Net (decrease) increase in cash and cash equivalents - discontinued operations
    (23 )     11  
Cash and cash equivalents (including held for sale) at beginning of period
    105       131  
Cash and cash equivalents (including held for sale) at end of period
    32       131  
Less cash and cash equivalents held for sale at end of period
    -       34  
Cash and cash equivalents (excluding held for sale) at end of period
  $ 32     $ 97  
Cash paid during the period for
               
Interest
  $ 150     $ 138  
Income taxes
  $ 317     $ 90  
Non cash financing transaction
               
Refinancing of gas facility revenue bonds
  $ -     $ 200  

See Notes to Condensed Consolidated Financial Statements (Unaudited).

 
9


AGL RESOURCES INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Organization and Basis of Presentation

General

AGL Resources Inc. is an energy services holding company that conducts substantially all of its operations through its subsidiaries. Unless the context requires otherwise, references to “we,” “us,” “our,” the “company,” or “AGL Resources” mean consolidated AGL Resources Inc. and its subsidiaries.

The December 31, 2013, Condensed Consolidated Statement of Financial Position data was derived from our revised audited consolidated financial statements filed on November 7, 2014 but does not include all disclosures required by GAAP. We have prepared the accompanying unaudited Condensed Consolidated Financial Statements under the rules and regulations of the SEC. In accordance with such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with GAAP. Our unaudited Condensed Consolidated Financial Statements reflect all adjustments of a normal recurring nature that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods. These unaudited Condensed Consolidated Financial Statements should be read in conjunction with our Consolidated Financial Statements and related notes included in Item 8 of our 2013 Form 10-K/A filed on November 7, 2014.

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 or financial condition to be expected for or as of any other period.

Basis of Presentation

Our unaudited Condensed Consolidated Financial Statements include our accounts, the accounts of our wholly owned subsidiaries, the accounts of our majority owned or otherwise controlled subsidiaries and the accounts of our consolidated VIE for which we are the primary beneficiary. For unconsolidated entities that we do not control, but exercise significant influence over, we use the equity method of accounting and our proportionate share of income or loss is recorded on the unaudited Condensed Consolidated Statements of Income. See Note 9 for additional information. We have eliminated intercompany profits and transactions in consolidation except for intercompany profits where recovery of such amounts is probable under the affiliates’ rate regulation process.

On September 1, 2014, we closed on the sale of Tropical Shipping, which historically operated within our cargo shipping segment. The assets and liabilities of these businesses are classified as held for sale on the unaudited Condensed Consolidated Statements of Financial Position, and the financial results of these businesses are reflected as discontinued operations on the unaudited Condensed Consolidated Statements of Income. Amounts shown in the following notes, unless otherwise indicated, exclude assets held for sale and discontinued operations. Cargo shipping also included our investment in Triton, which was not part of the sale and has been reclassified into our “other” segment. See Note 12 for additional information.

In the third quarter of 2014, we revised our financial statements and other affected disclosures for items related to the recognition of revenues for certain of our regulatory infrastructure programs and the amortization of our intangible assets. On November 7, 2014, we filed an amended Form 10-K/A revising certain prior period information with respect to our Annual Report on Form 10-K for the year ended December 31, 2013. See Note 13 for additional information.
 
We previously disclosed in our Form 10-K/A that the revisions did not impact any incentive compensation that was based on our results for 2013, 2012 and 2011.  However, subsequent to the filing of our Form 10-K/A, we determined that for 2011, had the underlying accounting originally reflected the distinction between regulatory accounting principles and GAAP, certain long-term incentives that were based on our results for the performance period ended December 31, 2011, would not have been awarded.  Specifically, in February 2012, based upon results for the performance period ended December 31, 2011, we would not have awarded officers (as defined for purposes of Section 16 of the Securities Exchange Act of 1934, as amended) (1) performance cash unit awards with an aggregate value of approximately $1 million and (2) a total of 37,290 shares of restricted stock. Management has evaluated this item in relation to its previously filed Form 10-K/A and materiality conclusions under Staff Accounting Bulletin No. 99 and has concluded that it would not change its prior materiality conclusion. 

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 2013 Form 10-K/A. Other than as described in Note 13, there were no significant changes to our accounting policies during the nine months ended September 30, 2014.

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 rate-regulated subsidiaries, uncollectible accounts and other allowances for contingent losses, goodwill and other intangible assets, retirement plan benefit 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.


 
10



Cash and Cash Equivalents

Our cash and cash equivalents primarily consist of cash on deposit, money market accounts and certificates of deposit held by domestic subsidiaries with original maturities of three months or less. At December 31, 2013, and September 30, 2013, there were $24 million and $34 million, respectively, of cash and cash equivalents held by Tropical Shipping that were excluded from cash and cash equivalents within our unaudited Condensed Consolidated Statements of Financial Position and included in assets held for sale. For more information on the sale of Tropical Shipping, see Note 12.

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 that enable our wholesale services segment to net receivables and payables by counterparty upon settlement. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale services’ counterparties are settled net, they are recorded on a gross basis in our unaudited Condensed Consolidated Statements of Financial Position as energy marketing receivables and energy marketing payables.

Our wholesale services segment has trade and credit contracts that contain 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. To date, our credit ratings have exceeded the minimum requirements. As of September 30, 2014 and 2013, and December 31, 2013, 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. If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.

Inventories

For our regulated utilities, except Nicor Gas, our natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. Nicor Gas’ inventory is carried at cost on a LIFO basis. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory. Atlanta Gas Light also retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. See Note 10 for information regarding a regulatory filing by Atlanta Gas Light related to natural gas inventory.

Our natural gas inventories at our retail operations, wholesale services and midstream operations segments carry inventory at the lower of cost or market value, where cost is determined on a WACOG basis. For these segments, we 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 value. For the three and nine months ended September 30, 2014, we recorded $5 million and $11 million, respectively, total LOCOM adjustment to reduce the value of our inventories to market value and $1 million and $9 million, respectively, for the three and nine months ended September 30, 2013. Additionally, we have $19 million of inventory at wholesale services that is currently inaccessible due to operational issues at a third party storage facility. The owner of the storage facility is working to resolve these issues. While we expect this inventory to be fully recovered, the timing of withdrawal of this gas may be impacted by the operational issues.

At midstream operations, mechanical integrity tests and engineering studies are periodically performed on the storage facilities in accordance with certain state regulatory requirements. However, such tests may be performed in advance of such state requirements for operational purposes. During 2014, an engineering study and mechanical integrity tests were performed at one of our storage facilities, identifying a lower amount of working gas capacity that is the result of naturally occurring shrinkage of the storage caverns. Further, based on the lower capacity and an analysis of the volume of natural gas stored in the facility, we recorded natural gas costs to true-up the amount of retained fuel at this facility in the amount of $10 million for the nine months ended September 30, 2014. Our other storage facilities at midstream operations were not impacted.


 
11

 
Fair Value Measurements

We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents, and derivative assets and liabilities. The carrying values of receivables, short- and long-term investments, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate fair value. Our nonfinancial assets and liabilities include pension and other retirement benefits, which are presented in Note 4 to our Consolidated Financial Statements and in related notes included in Item 8 of our 2013 Form 10-K/A.
 
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 observance of those inputs in accordance with the fair value hierarchy.
 
Derivative Instruments

The fair value of the natural gas and weather derivative instruments that we use to manage exposures arising from changing natural gas prices and weather risk reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 4 and Note 5 for additional derivative disclosures.

Property, Plant and Equipment

On April 11, 2014, we entered into two arrangements associated with the Dalton Pipeline. The first was a construction and ownership agreement through which we will have a 50% undivided ownership interest in the 106 mile Dalton Pipeline that will be constructed in Georgia and serve as an extension of the Transco natural gas pipeline system into northwest Georgia. We also entered into an agreement to lease our 50% undivided ownership in the Dalton Pipeline once it is placed in-service. The lease payments to be received are $26 million annually for an initial term of 25 years. The lessee will be responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC regulated tariff. Engineering design work has commenced and construction is expected to begin in the second quarter of 2016 with a targeted completion date in the second quarter of 2017. The capacity from this pipeline will further enhance system reliability as well as provide access to a more diverse supply of natural gas.

Goodwill

In 2014, we completed an engineering study at our midstream operations storage facilities that indicated a reduced forecast of working gas capacity from what was projected when our 2013 annual goodwill impairment analysis was performed during the fourth quarter of 2013. Given that the 2013 annual goodwill impairment test indicated that the estimated fair value of this reporting unit exceeded its carrying amount by less than 5%, we considered this reduced storage capacity as an indicator of potential impairment and accordingly conducted an interim goodwill impairment analysis during the first quarter of 2014.

The estimated fair value of this reporting unit was determined utilizing the income approach, which estimated the fair value based upon the present value of estimated future cash flows. The forecasts used in the income approach, which were updated during the first quarter of 2014 to reflect the contracting activity that occurred during the quarter, assume discrete period revenue growth through fiscal 2022 to reflect the recovery of subscription rates, stabilization of earnings and establishment of a reasonable base year that was used to estimate the terminal value in the valuation model. Consistent with our 2013 annual goodwill impairment testing, we assumed a long-term earnings growth rate in the terminal year of 2.5%, which we believe is appropriate given the current economic and industry-specific expectations. As of the valuation date, we utilized a discount rate of 7.0%, which we believe is appropriate as it reflects the relative risk and the time value of money, and is consistent with the peer group of this reporting unit as well as the discount rates that were utilized in our 2013 annual goodwill impairment tests.

Our interim goodwill impairment test assumed a cash flow forecast providing for growth over the next eight years. This forecast indicated that the estimated fair value of this reporting unit continues to exceed its carrying amount with a cushion of less than 10%. However, continued declines in capacity or subscription rates, reductions to our cash flow forecasts, a sustained period at the current subscription rates or other changes to the assumptions and factors used in this analysis may result in a future failure of step one of the goodwill impairment test and require us to proceed to step two of the goodwill impairment test in a future period.

 
 
12

 
The risk of impairment of the underlying long-lived assets is not estimated to be significant as the assets have long remaining useful lives, and authoritative guidance requires such assets to be tested for impairment on the basis of undiscounted cash flows over their remaining useful lives. We will continue to monitor this reporting unit for potential impairment. Our goodwill balances by segment as of September 30, 2014, and December 31, 2013, and changes in the amount of goodwill for the nine months ended September 30, 2013, are provided in the following table.

In millions
 
Distribution Operations
   
Retail Operations
   
Midstream Operations
   
Consolidated
 
December 31, 2012
  $ 1,640     $ 122     $ 14     $ 1,776  
2013 acquisitions
    -       46       -       46  
September 30, 2013 (1)
  $ 1,640     $ 168     $ 14     $ 1,822  
                                 
December 31, 2013 (1)
  $ 1,640     $ 173     $ 14     $ 1,827  
September 30, 2014
  $ 1,640     $ 173     $ 14     $ 1,827  
(1)
Excludes goodwill at Tropical Shipping which is classified as held for sale. See Note 12 for additional information.

Other Income

Our other income is detailed in the following table.

   
Three months ended September 30,
   
Nine months ended September 30,
 
In millions
 
2014
   
2013
   
2014
   
2013
 
Equity method investment income (1)
  $ 2     $ 3     $ 6     $ 8  
AFUDC - equity
    1       3       2       8  
Other, net
    -       1       -       2  
Total other income
  $ 3     $ 7     $ 8     $ 18  
(1)
For more information on our equity method investment income, see Note 9.

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 occurs when potentially dilutive common shares are added to common shares outstanding.

We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options award programs. The vesting of certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance and/or time-based criteria. The future issuance of shares underlying the outstanding stock options depends on whether the market price of the common shares underlying the options exceeds the respective exercise prices of the stock options. The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. common shareholders for the periods presented, as if performance units currently earned under the plan ultimately vest and as if stock options currently exercisable at prices below the average market prices are exercised.

   
Three months ended September 30,
   
Nine months ended September 30,
 
In millions (except per share amounts)
 
2014
   
2013 (1)
   
2014 (1)
   
2013 (1)
 
Income from continuing operations (2)
  $ 23     $ 24     $ 414     $ 217  
(Loss) income from discontinued operations, net of tax (3)
    (31 )     1       (80 )     1  
Net (loss) income attributable to AGL Resources Inc.
  $ (8 )   $ 25     $ 334     $ 218  
Denominator:
                               
Basic weighted average number of common shares outstanding (4)
    119.0       118.2       118.8       117.8  
Effect of dilutive securities
    0.4       0.3       0.4       0.3  
Diluted weighted average number of common shares outstanding
    119.4       118.5       119.2       118.1  
                                 
Basic earnings (loss) per common share
                               
From continuing operations
  $ 0.19     $ 0.20     $ 3.48     $ 1.85  
From discontinued operations
    (0.25 )     0.01       (0.67 )     0.01  
Basic (loss) earnings per common share attributable to AGL Resources Inc. common shareholders
  $ (0.06 )   $ 0.21     $ 2.81     $ 1.86  
Diluted earnings (loss) per common share
                               
From continuing operations
  $ 0.19     $ 0.20     $ 3.47     $ 1.84  
From discontinued operations
    (0.25 )     0.01       (0.67 )     0.01  
Diluted (loss) earnings per common share attributable to AGL Resources Inc. common shareholders
  $ (0.06 )   $ 0.21     $ 2.80     $ 1.85  
(1)
Amounts revised and or include prior period adjustments. See Note 13 for additional information.
(2)
Excludes net income attributable to the noncontrolling interest.
(3)
For additional information on our discontinued operations, see Note 12.
(4)
Daily weighted average shares outstanding.
 

 
 
13

 
Sale of Compass Energy

On May 1, 2013, we sold Compass Energy, a non-regulated retail natural gas business supplying commercial and industrial customers, which was part of our wholesale services segment. We received an initial cash payment of $12 million, which resulted in an $11 million pre-tax gain ($5 million net of tax) for the nine months ended September 30, 2013. Under the terms of the purchase and sale agreement, we were eligible to receive contingent cash consideration up to $8 million with a guaranteed minimum receipt of $3 million that was recognized during 2013. The remaining $5 million of contingent cash consideration was to be received from the buyer annually over a five-year earn-out period based upon the financial performance of Compass Energy. In the third quarter of 2014, we negotiated with the buyer to settle the future earn-out payments and we received $4 million, resulting in the recognition of a $3 million gain. We have a five year agreement to supply natural gas to our former customers. Accordingly, as a result of our continued involvement, the sale of Compass Energy did not meet the criteria for treatment as a discontinued operation.

Accounting Developments

On April 10, 2014, the FASB issued authoritative guidance related to reporting discontinued operations. The guidance generally raises the threshold for disposals to qualify as discontinued operations and requires new disclosures of both discontinued operations and certain other material disposals that do not meet the definition of a discontinued operation. The guidance will be effective for us prospectively beginning January 1, 2015. It is not expected to have a material impact on our consolidated financial statements, and it will have no impact on our accounting for the sale of Tropical Shipping.

On May 28, 2014, the FASB issued an update to authoritative guidance related to revenue from contracts with customers. The update replaces most of the existing guidance with a single set of principles for recognizing revenue from contracts with customers. The guidance will be effective for us beginning January 1, 2017. Early adoption is not permitted. The new guidance must be applied retrospectively to each prior period presented or via a cumulative effect upon the date of initial application. We have not yet determined the impact of this new guidance, nor have we selected a transition method.

On June 19, 2014, the FASB issued an update to authoritative guidance related to accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period. The guidance will be effective for us beginning January 1, 2016, and will have no material impact on our consolidated financial statements for our existing share-based plans.


 
14



Note 3 - Regulated Operations

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 rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for estimated expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense, and regulatory liabilities are amortized into income over the period authorized by the regulatory commissions. The following table summarizes our regulatory assets and liabilities as of the dates presented.

In millions
 
September 30, 2014
   
December 31, 2013 (1)
   
September 30, 2013 (1)
 
Regulatory assets
                 
Recoverable ERC
  $ 41     $ 45     $ 30  
Recoverable pension and retiree welfare benefit costs
    9       9       19  
Recoverable seasonal rates
    9       10       9  
Deferred natural gas costs
    3       1       -  
Other
    43       49       29  
Total regulatory assets - current
    105       114       87  
Recoverable ERC
    363       433       456  
Recoverable pension and retiree welfare benefit costs
    91       99       183  
Long-term debt fair value adjustment
    76       82       84  
Recoverable regulatory infrastructure program costs (1)
    62       55       78  
Other
    45       36       44  
Total regulatory assets - long-term
    637       705       845  
Total regulatory assets
  $ 742     $ 819     $ 932  
Regulatory liabilities
                       
Bad debt over collection
  $ 31     $ 41     $ 37  
Accrued natural gas costs
    29       92       104  
Accumulated removal costs
    27       27       17  
Other
    31       23       16  
Total regulatory liabilities - current
    118       183       174  
Accumulated removal costs
    1,499       1,445       1,448  
Regulatory income tax liability
    26       27       26  
Unamortized investment tax credit
    23       26       26  
Bad debt over collection
    7       17       20  
Other
    12       3       4  
Total regulatory liabilities - long-term
    1,567       1,518       1,524  
Total regulatory liabilities
  $ 1,685     $ 1,701     $ 1,698  
(1)
Amounts revised for prior period adjustments. See Note 13 for additional information.

Base rates are designed to provide the opportunity for both a recovery of cost and a return on investment during the period rates are in effect. As such, all of our regulatory assets recoverable through base rates are subject to review by the respective state regulatory commission during future rate proceedings. We believe that we will be able to recover such costs consistent with our historical recoveries.

Unrecognized Ratemaking Amounts We have authorized unrecognized ratemaking amounts that are not reflected within our unaudited Condensed Consolidated Statements of Financial Position as indicated in the following table. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain of our regulatory infrastructure programs. These amounts will be recognized as revenues in our financial statements in the periods they are collected in rates from our customers. For additional information, see Note 13.

In millions
     
September 30, 2014
  $ 118  
December 31, 2013
  $ 93  
September 30, 2013
  $ 86  

Natural Gas Costs We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms established by the state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. We defer or accrue the difference between the actual cost of gas and the amount of commodity revenue earned in a given period, such that no operating margin is recognized related to these costs. The deferred or accrued amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. The following table illustrates the change in net position of these costs from September 30, 2013 to September 30, 2014.

In millions
 
September 30, 2014
   
September 30, 2013
   
Change
 
Deferred natural gas costs
  $ 3     $ -     $ 3  
Accrued natural gas costs
    (29 )     (104 )     75  
Total (1)
  $ (26 )   $ (104 )   $ 78  
(1)
The $78 million change resulted from increased natural gas prices during the first nine months of 2014 compared to the first nine months of 2013, primarily driven by colder weather experienced in 2014.
 
15

 
Environmental Remediation Costs We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that 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, substantially all of which is related to our MGP sites. The ERC assets and liabilities are associated with our distribution operations segment and remediation costs are generally recoverable from customers through rate mechanisms approved by regulators. Accordingly, both costs incurred to remediate the former MGP sites, plus the future estimated cost recorded as liabilities, net of amounts previously collected, are recognized as a regulatory asset until recovered from customers.

Our ERC liabilities are estimates of future remediation costs for investigation and cleanup of our current and former operating sites that are contaminated. These estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, on an undiscounted basis. As cleanup options and plans mature and cleanup contracts are entered into, 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. These liabilities do not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, legal expenses or other costs for which we may be held liable but for which we cannot reasonably estimate an amount. The following table provides additional information on the costs related to remediation of our current and former operating sites as of September 30, 2014 and reflects changes in estimates since December 31, 2013.

In millions
 
Probabilistic model
cost estimates
   
Engineering estimates
   
Amount recorded
   
Expected costs over next 12 months
 
Illinois
    $205 - $462     $ 46     $ 244     $ 41  
New Jersey
    107 - 174       16       122       16  
Georgia and Florida
    66 - 106       9       77       17  
North Carolina (1)
    n/a       11       11       8  
Total
    $378 - $742     $ 82     $ 454 (2)   $ 82  
(1)
We have no regulatory recovery mechanisms for the site in North Carolina. Therefore, there is no amount included within our regulatory assets and changes in estimated costs are recognized in income in the period of change.
(2)
Increase of $7 million from December 31, 2013, primarily relates to a scope increase required by the Georgia Environmental Protection Division for a site in Georgia and an adjustment for a site in Florida. This was partially offset by a decrease for a site in New Jersey where remediation is almost complete.

In July 2014, we reached a $77 million settlement with an insurance company for environmental claims relating to potential contamination at several of our MGP sites in New Jersey and North Carolina. The terms of the settlement required the $77 million to be paid in two installments. We received the first $45 million installment in the third quarter of 2014 and this payment was primarily recorded as a reduction to our recoverable ERC regulatory asset. The remaining $32 million is due in the third quarter of 2015. We will file for approval with the New Jersey BPU to utilize the insurance proceeds related to the New Jersey sites to reduce the ERC expenditures that otherwise would have been recovered from our customers in future periods. As such, the settlement, once approved, is expected to reduce our recoverable ERC regulatory asset and have a favorable impact on the rates for our Elizabethtown Gas customers.


 
16



Note 4 - Fair Value Measurements

The methods used to determine the fair values of our assets and liabilities are described within Note 2.

Derivative Instruments

The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were carried at fair value on a recurring basis in our unaudited Condensed Consolidated Statements of Financial Position as of the dates presented. See Note 5 for additional derivative instrument information.

   
September 30, 2014
   
December 31, 2013
   
September 30, 2013
 
In millions
 
Assets (1)
   
Liabilities
   
Assets (1)
   
Liabilities
   
Assets (1)
   
Liabilities
 
Natural gas derivatives
                                   
Quoted prices in active markets (Level 1)
  $ 4     $ (72 )   $ 6     $ (79 )   $ 4     $ (52 )
Significant other observable inputs (Level 2)
    57       (51 )     67       (79 )     60       (41 )
Netting of cash collateral
    49       76       43       78       45       49  
Total carrying value (2) (3)
  $ 110     $ (47 )   $ 116     $ (80 )   $ 109     $ (44 )
(1)
Balances of $3 million at September 30, 2014, December 31, 2013 and September 30, 2013, associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value.
(2)
There were no significant unobservable inputs (Level 3) for any of the dates presented.
(3)
There were no significant transfers between Level 1, Level 2 or Level 3 for any of the dates presented.

Debt

Our long-term debt is recorded at amortized cost, with the exception of Nicor Gas’ first mortgage bonds, which are recorded at their acquisition date fair value. The fair value adjustment of Nicor Gas’ first mortgage bonds is being amortized over the lives of the bonds. The following table lists the carrying amount and fair value of our long-term debt as of the dates presented.

In millions
 
September 30, 2014
   
December 31, 2013
   
September 30, 2013
 
Long-term debt carrying amount
  $ 3,805     $ 3,813     $ 3,816  
Long-term debt fair value (1)
    4,165       3,956       4,024  
(1)
Fair value determined using Level 2 inputs.

Note 5 - Derivative Instruments

A description of our objectives and strategies for using derivative instruments, related accounting policies and methods used to determine their fair values are described in Note 2 to our Consolidated Financial Statements and related notes included in Item 8 of our 2013 Form 10-K/A. See Note 4 for additional fair value disclosures.

Certain of our derivative instruments contain credit risk-related or other contingent features that could require us to post collateral in the normal course of business when our financial instruments are in net liability positions. As of September 30, 2014, for agreements with such features, derivative instruments with liability fair values for which we had posted no collateral to our counterparties totaled $47 million. The maximum collateral that could be required with these features is $10 million. For more information, see “Energy Marketing Receivables and Payables” in Note 2, which also have credit risk-related or other contingent features. Our derivative instrument activities are included within operating cash flows as an increase (decrease) to net income of $(27) million and $37 million for the nine months ended September 30, 2014 and 2013, respectively. See Note 4 for additional derivative instrument information. The following table summarizes the various ways in which we account for our derivative instruments and the impact on our unaudited Condensed Consolidated Financial Statements.
 
Accounting Treatment
Recognition and Measurement
Statements of Financial Position
Statements of Income
Cash flow hedge
 
Derivative carried 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 OCI (loss)
Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated OCI (loss) and into earnings when the hedged transaction affects earnings
Fair value hedge
 
Derivative carried at fair value
 
Gains or losses on the derivative instrument and the hedged item are recognized in earnings. As a result, to the extent the hedge is effective, the gains or losses will offset and there is no impact on earnings. Any hedge ineffectiveness will impact earnings
Changes in fair value of the hedged item are recorded as adjustments to the carrying amount of the hedged item
Not designated as hedges
 
Derivative carried at fair value
 
Realized and unrealized gains or losses on the derivative instrument are recognized in earnings
Distribution operations’ gains and losses on derivative instruments are deferred as regulatory assets or liabilities until included
in cost of goods sold
Gains or losses on these derivative instruments are ultimately included in billings to customers and are recognized in cost of goods sold in the same period as the related revenues

 
 
Quantitative Disclosures Related to Derivative Instruments

As of the dates presented, our derivative 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 a net long natural gas contracts position outstanding in the following quantities:

In Bcf (1)
 
September 30, 2014 (2)
   
December 31, 2013
   
September 30, 2013
 
Cash flow hedges
    7       6       3  
Not designated as hedges
    97       183       40  
Total volumes
    104       189       43  
Short position
    (2,756 )     (2,622 )     (2,788 )
Long position
    2,860       2,811       2,831  
Net long position
    104       189       43  
(1)
Volumes related to Nicor Gas exclude variable-priced contracts, which are carried at fair value, but whose fair values are not directly impacted by changes in commodity prices.
(2)
Approximately 98% of these contracts have durations of 2 years or less and the remaining 2% expire between 2 and 5 years.

Derivative Instruments in our Unaudited Condensed Consolidated Statements of Financial Position

In accordance with regulatory requirements, gains and losses on derivative instruments used to hedge natural gas purchases for customer use at distribution operations are reflected in accrued natural gas costs within our Consolidated Statements of Financial Position until billed to customers. The following amounts deferred as a regulatory asset or liability on our unaudited Condensed Consolidated Statements of Financial Position represent the net realized gains (losses) related to these natural gas cost hedges for the periods presented.

   
Three months ended September 30,
   
Nine months ended September 30,
 
In millions
 
2014
   
2013
   
2014
   
2013
 
Nicor Gas
  $ (4 )   $ (6 )   $ 8     $ 2  
Elizabethtown Gas
    (1 )     (1 )     4       (5 )

The following table presents the fair values and unaudited Condensed Consolidated Statements of Financial Position classifications of our derivative instruments as of the dates presented.

     
September 30, 2014
   
December 31, 2013
   
September 30, 2013
 
In millions
Classification
 
Assets
   
Liabilities
   
Assets
   
Liabilities
   
Assets
   
Liabilities
 
Designated as cash flow or fair value hedges
                                   
Natural gas contracts
Current
  $ 2     $ (2 )   $ 3     $ (1 )   $ 6     $ (5 )
                                                   
Not designated as hedges
                                               
Natural gas contracts
Current
    834       (891 )     691       (761 )     445       (462 )
Natural gas contracts
Long-term
    78       (80 )     206       (220 )     143       (153 )
Total
      912       (971 )     897       (981 )     588       (615 )
Gross amount of recognized assets and liabilities (1) (2)
    914       (973 )     900       (982 )     594       (620 )
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)
    (801 )     926       (781 )     902       (482 )     576  
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)
  $ 113     $ (47 )   $ 119     $ (80 )   $ 112     $ (44 )
(1)
The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Statements of Financial Position to the extent that we have netting arrangements with the counterparties.
(2)
As required by the authoritative guidance related to derivatives and hedging, the gross amounts of recognized assets and liabilities above do not include cash collateral held on deposit in broker margin accounts of $125 million as of September 30, 2014, $121 million as of December 31, 2013, and $94 million as of September 30, 2013. Cash collateral is included in the “Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position” line of this table.
(3)
At September 30, 2014, December 31, 2013, and September 30, 2013, we held letters of credit from counterparties that would offset, under master netting arrangements, an insignificant portion of these assets.


 
18



Derivative Instruments in the Unaudited Condensed Consolidated Statements of Income

The following table presents the impacts of our derivative instruments in our unaudited Condensed Consolidated Statements of Income for the periods presented.

   
Three months ended September 30,
   
Nine months ended September 30,
 
In millions
 
2014
   
2013
   
2014
   
2013
 
Designated as cash flow or fair value hedges
                       
Natural gas contracts - net gain reclassified from OCI into cost of goods sold
  $ (1 )   $ (1 )   $ 4     $ -  
Natural gas contracts - net gain reclassified from OCI into operation and maintenance expense
    1       -       2       -  
Interest rate swaps - net loss reclassified from OCI into interest expense
    -       1       -       (2 )
Income tax benefit
    -       -       (1 )     1  
Net of tax
    -       -       5       (1 )
Not designated as hedges (1)
                               
Natural gas contracts - net fair value adjustments recorded in operating revenues
    (6 )     (14 )     (6 )     (16 )
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2)
    (1 )     -       -       (1 )
Income tax benefit
    2       5       2       7  
Net of tax
    (5 )     (9 )     (4 )     (10 )
Total (losses) gains on derivative instruments
  $ (5 )   $ (9 )   $ 1     $ (11 )
(1)
Associated with the fair value of derivative instruments held at September 30, 2014 and 2013.
(2)
Excludes losses recorded in cost of goods sold associated with weather derivatives of $6 million and $3 million for the nine months ended September 30, 2014 and 2013, respectively.

Any amounts recognized in operating income related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur were immaterial for the three and nine months ended September 30, 2014 and 2013. Our expected gains to be reclassified from OCI into cost of goods sold, operation and maintenance expense, interest expense and operating revenues and recognized in our unaudited Condensed Consolidated Statements of Income over the next 12 months are less than $1 million. These deferred gains and losses are related to natural gas derivative contracts associated with retail operations and Nicor Gas’ system use. The expected gains are based upon the fair values of these financial instruments at September 30, 2014. The effective portion of gains and losses on derivative instruments qualifying as cash flow hedges that were recognized in OCI during the periods is presented on our unaudited Condensed Consolidated Statements of Income. See Note 8 for these amounts.

There have been no other significant changes to our derivative instruments, as described in Note 2, Note 4 and Note 5 to our Consolidated Financial Statements and related notes included in Item 8 of our 2013 Form 10-K/A.

Note 6 - Employee Benefit Plans

Pension Benefits

We sponsor the AGL Resources Inc. Retirement Plan, a tax-qualified defined benefit retirement plan for our eligible employees, which is described in Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2013 Form 10-K/A. Following are the components of our pension costs for the periods indicated.

   
Three months ended September 30,
   
Nine months ended September 30,
 
In millions
 
2014
   
2013
   
2014
   
2013
 
Service cost
  $ 6     $ 7     $ 18     $ 22  
Interest cost
    12       11       35       32  
Expected return on plan assets
    (16 )     (16 )     (48 )     (47 )
Net amortization of prior service cost
    (1 )     -       (2 )     (1 )
Recognized actuarial loss
    5       9       16       26  
Net periodic pension benefit cost
  $ 6     $ 11     $ 19     $ 32  

Welfare Benefits

The benefits of our Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Welfare Plan) are described in Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2013 Form 10-K/A. Following are the components of our welfare costs for the periods indicated.

   
Three months ended September 30,
   
Nine months ended September 30,
 
In millions
 
2014
   
2013
   
2014
   
2013
 
Service cost
  $ 1     $ 1     $ 2     $ 2  
Interest cost
    4       3       11       10  
Expected return on plan assets
    (2 )     (1 )     (5 )     (4 )
Net amortization of prior service cost
    (1 )     (1 )     (2 )     (3 )
Recognized actuarial loss
    1       2       4       6  
Net periodic welfare benefit cost
  $ 3     $ 4     $ 10     $ 11  

 
19

 
Note 7 - Debt and Credit Facilities

The following table provides maturity dates, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities for the periods presented. We fully and unconditionally guarantee all debt issued by AGL Capital. For additional information on our debt, see Note 8 in our Consolidated Financial Statements and related notes in Item 8 of our 2013 Form 10-K/A.

         
September 30, 2014
         
September 30, 2013
 
Dollars in millions
 
Year(s) due
   
Weighted average interest rate (1)
   
Outstanding
   
Outstanding at
December 31, 2013
   
Weighted average interest rate (1)
   
Outstanding
 
Short-term debt
                                   
Commercial paper - AGL Capital (2)
 
2014
      0.3 %   $ 292     $ 857       0.4 %   $ 680  
Commercial paper - Nicor Gas (2)
 
2014
      0.2       389       314       0.3       152  
Total short-term debt
          0.3 %   $ 681     $ 1,171       0.4 %   $ 832  
Current portion of long-term debt
 
2015
      5.0 %   $ 200     $ -       -     $ -  
Long-term debt - excluding current portion
                                         
Senior notes
  2016-2043       5.0 %   $ 2,625     $ 2,825       5.1 %   $ 2,825  
First mortgage bonds
  2016-2038       5.6       500       500       5.6       500  
Gas facility revenue bonds
  2022-2033       0.9       200       200       0.8       200  
Medium-term notes
  2017-2027       7.8       181       181       7.8       181  
Total principal long-term debt
          4.9 %     3,506       3,706       4.9 %     3,706  
Fair value adjustment of long-term debt (3)
  n/a       n/a       83       91       n/a       94  
Unamortized debt premium, net
  n/a       n/a       16       16       n/a       16  
Total non-principal long-term debt
          n/a       99       107       n/a       110  
Total long-term debt
                $ 3,605     $ 3,813             $ 3,816  
Total debt
                $ 4,486     $ 4,984             $ 4,648  
(1)
Interest rates are calculated based on the daily weighted average balance outstanding for the nine months ended September 30.
(2)
As of September 30, 2014, the effective interest rates on our commercial paper borrowings were 0.3% for AGL Capital and 0.2% for Nicor Gas.
(3)
See Note 4 for additional information on our fair value measurements.

Commercial Paper Programs

We maintain commercial paper programs at AGL Capital and Nicor Gas that consist of short-term, unsecured promissory notes used in conjunction with cash from operations to fund our seasonal working capital requirements. Working capital needs fluctuate during the year and are highest during the injection period in advance of the Heating Season. The Nicor Gas commercial paper program supports working capital needs at Nicor Gas, while all of our other subsidiaries and SouthStar participate in the AGL Capital commercial paper program. During the first nine months of 2014, our commercial paper maturities ranged from 1 to 108 days, and at September 30, 2014, remaining terms to maturity ranged from 1 to 24 days. Total borrowings and repayments netted to a payment of $490 million during the first nine months of 2014. For commercial paper issuances with original maturities over three months, borrowings and repayments were $50 million and $145 million, respectively, during the first nine months of 2014. During the three months ended September 30, 2014, we utilized a portion of the $225 million in proceeds from the sale of Tropical Shipping to reduce our commercial paper borrowings.

Financial and Non-Financial Covenants

The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month. These ratios, as calculated in accordance with the debt covenants, include standby letters of credit and surety bonds and exclude accumulated OCI items related to non-cash pension adjustments, welfare benefits liability adjustments and accounting adjustments for cash flow hedges. Adjusting for these items, the following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed.

   
September 30, 2014
   
December 31, 2013
   
September 30, 2013
 
AGL Credit Facility
    53 %     57 %     56 %
Nicor Gas Credit Facility
    57 %     55 %     50 %

The credit facilities contain certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations and other matters customarily restricted in such agreements.


 
20



Default Provisions

Our credit facilities and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. The most important default events include the following:

·
a maximum leverage ratio
·
insolvency events and or nonpayment of scheduled principal or interest payments
·
acceleration of other financial obligations
·
change of control provisions

We have no triggering events in our debt instruments that are tied to changes in our specified credit ratings or our stock price, and have not entered into any transaction that requires us to issue equity based on credit ratings or other triggering events. We were in compliance with all existing debt provisions and covenants, both financial and non-financial, for all periods presented.

Note 8 - Equity

Our OCI amounts are aggregated within our accumulated other comprehensive loss. The following table provides changes in the components of our accumulated other comprehensive loss balance, net of the related income tax effects.

   
2014
   
2013
 
In millions (1)
 
Cash flow hedges
   
Retirement benefit plans
   
Total
   
Cash flow hedges
   
Retirement benefit plans
   
Total
 
For the three months ended September 30
                                   
As of beginning of period
  $ -     $ (133 )   $ (133 )   $ (1 )   $ (208 )   $ (209 )
OCI, before reclassifications
    (2 )     -       (2 )     -       -       -  
Amounts reclassified from accumulated OCI
    -       2       2       -       1       1  
Net current-period other comprehensive (loss) income
    (2 )     2       -       -       1       1  
As of end of period
  $ (2 )   $ (131 )   $ (133 )   $ (1 )   $ (207 )   $ (208 )
                                                 
For the nine months ended September 30
                                               
As of beginning of period
  $ 1     $ (137 )   $ (136 )   $ (3 )   $ (215 )   $ (218 )
OCI, before reclassifications
    2       -       2       -       -       -  
Amounts reclassified from accumulated OCI
    (5 )     6       1       2       8       10  
Net current-period other comprehensive (loss) income
    (3 )     6       3       2       8       10  
As of end of period
  $ (2 )   $ (131 )   $ (133 )   $ (1 )   $ (207 )   $ (208 )
(1)
All amounts are net of income taxes. Amounts in parentheses indicate increases to our accumulated other comprehensive loss.

The following table provides details of the reclassifications out of accumulated other comprehensive loss and the impact on net income.

   
Three months ended September 30,
   
Nine months ended September 30,
 
In millions (1)
 
2014
   
2013
   
2014
   
2013
 
Cash flow hedges
                       
Cost of goods sold (natural gas contracts)
  $ (1 )   $ (1 )   $ 4     $ -  
Operation and maintenance expense (natural gas contracts)
    1       -       2       -  
Interest expense (interest rate contracts)
    -       1       -       (3 )
Total before income tax
    -       -       6       (3 )
Income tax benefit
    -       -       (1 )     1  
Total cash flow hedges
    -       -       5       (2 )
Retirement benefit plans
                               
Operation and maintenance expense (actuarial losses)(2)
    (4 )     (6 )     (12 )     (19 )
Operation and maintenance expense (prior service credits) (2)
    -       2       1       4  
Total before income tax
    (4 )     (4 )     (11 )     (15 )
Income tax benefit
    2       3       5       7  
Total retirement benefit plans
    (2 )     (1 )     (6 )     (8 )
Total reclassification for the period
  $ (2 )   $ (1 )   $ (1 )   $ (10 )
(1)
Amounts in parentheses indicate reductions to our net income and accumulated other comprehensive loss. Except for retirement benefit plan amounts, the net income impacts are immediate.
(2)
Amortization of these accumulated other comprehensive loss components is included in the computation of net periodic benefit cost. See Note 6 for additional details about net periodic benefit cost.


 
21



Note 9 - Non-Wholly Owned Entities

SouthStar, a joint venture owned by us and Piedmont, is our only significant VIE for which we are the primary beneficiary. This requires us to consolidate its assets, liabilities and statements of income. For additional information on SouthStar, see Note 10 to our Consolidated Financial Statements and related notes included in Item 8 of our 2013 Form 10-K/A. Earnings from SouthStar in 2014 and 2013 were allocated entirely in accordance with the ownership interests.

Cash flows used in our investing activities include capital expenditures for SouthStar of $6 million for the nine months ended September 30, 2014, and $2 million for the nine months ended September 30, 2013. Cash flows used in our financing activities include SouthStar’s distribution to Piedmont for its portion of SouthStar’s annual earnings from the previous year. Generally, this distribution occurs in the first quarter of each fiscal year. For each of the nine months ended September 30, 2014 and 2013, SouthStar distributed $17 million to Piedmont. SouthStar’s creditors have no recourse to our general credit beyond our corporate guarantees that we have provided to SouthStar’s counterparties and natural gas suppliers. The following table provides additional information about SouthStar’s assets and liabilities as of the dates presented, which are consolidated within our unaudited Condensed Consolidated Statements of Financial Position.

   
September 30, 2014 (1)
   
December 31, 2013 (1)
   
September 30, 2013 (1)
 
In millions
 
Consolidated
   
SouthStar (2)
      % (3)    
Consolidated
   
SouthStar (2)
      % (3)    
Consolidated
   
SouthStar (2)
      % (3)  
Current assets
  $ 2,093     $ 188       9 %   $ 2,895     $ 264       9 %   $ 2,252     $ 192       9 %
Goodwill and intangible assets
    1,957       127       6       1,972       133       7       1,974       136       7  
Long-term assets and other deferred debits
    9,903       17       -       9,683       13       -       9,584       13       -  
Total assets
  $ 13,953     $ 332       2 %   $ 14,550     $ 410       3 %   $ 13,810     $ 341       2 %
Current liabilities
  $ 2,462     $ 47       2 %   $ 3,118     $ 95       3 %   $ 2,407     $ 73       3 %
Long-term liabilities and other deferred credits
    7,689       -       -       7,819       -       -       7,897       -       -  
Total Liabilities
    10,151       47       1       10,937       95       1       10,304       73       1  
Equity
    3,802       285       7       3,613       315       9       3,506       268       8  
Total liabilities and equity
  $ 13,953     $ 332       2 %   $ 14,550     $ 410       3 %   $ 13,810     $ 341       2 %
(1)
Amounts revised and include prior period adjustments. See Note 13 for additional information.
(2)
These amounts reflect information for SouthStar and exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.
(3)
SouthStar’s percentage of the amount on our unaudited Condensed Consolidated Statements of Financial Position.

The following table provides information on SouthStar’s operating revenues and operating expenses for the periods presented, which are consolidated within our unaudited Condensed Consolidated Statements of Income.

   
Three months ended September 30,
   
Nine months ended September 30,
 
In millions
 
2014
   
2013
   
2014
   
2013
 
Operating revenues
  $ 113     $ 98     $ 633     $ 464  
Operating expenses
                               
Cost of goods sold
    89       81       470       340  
Operation and maintenance
    19       16       62       49  
Depreciation and amortization
    3       2       8       3  
Taxes other than income taxes
    -       -       1       1  
Total operating expenses
    111       99       541       393  
Operating income (loss)
  $ 2     $ (1 )   $ 92     $ 71  

Equity Method Investments

For more information about our equity method investments, see Note 10 to our Consolidated Financial Statements and related notes in Item 8 of our 2013 Form 10-K/A. The carrying amounts of our equity method investments within our unaudited Condensed Consolidated Statements of Financial Position were as follows:

   
September 30,
   
December 31,
   
September 30,
 
In millions
 
2014
   
2013
   
2013
 
Triton
  $ 64     $ 70     $ 71  
Horizon Pipeline
    14       15       15  
Other
    2       1       9  
Total
  $ 80     $ 86     $ 95  

 
22



Income from our equity method investments is classified as other income in our unaudited Condensed Consolidated Statements of Income. The following table provides the income from our equity method investments for the periods presented.

   
Three months ended September 30,
   
Nine months ended September 30,
 
In millions
 
2014
   
2013
   
2014
   
2013
 
Triton (1)
  $ 2     $ 3     $ 5     $ 7  
Other
    -       -       1       1  
(1)
Reported within our “other” segment. For more information, see Note 11.

In the third quarter of 2014, we entered into two interstate pipeline joint ventures within our midstream operations segment as described below. The capacity from these joint ventures will further enhance system reliability as well as provide access to a more diverse supply of natural gas. We have concluded that, at present, both are VIEs. We are not considered the primary beneficiary and we have not consolidated the financial statements for these joint ventures in our unaudited Condensed Consolidated Financial Statements, because we share in the ability to direct the activities that most significantly impact their economic performance with their other member companies. We have accounted for our investment in these joint ventures using the equity method of accounting, and have classified the investment in other noncurrent assets in our unaudited Condensed Consolidated Statements of Financial Position.

PennEast Pipeline On August 11, 2014, we entered into a joint venture to develop and operate a 108-mile natural gas pipeline between New Jersey and Pennsylvania with initial transportation capacity of 800,000 dekatherms per day, which may be expanded to 1.2 Bcf per day. Our current investment in PennEast Pipeline is less than $1 million and represents a 20% ownership interest, and is the maximum extent of our current exposure to loss. Construction is expected to begin in the first quarter of 2017 with a targeted completion date in the fourth quarter of 2017.

Atlantic Coast Pipeline On September 2, 2014, we entered into a joint venture to develop and operate a 550-mile natural gas pipeline in North Carolina, Virginia, and West Virginia with initial transportation capacity of 1.5 Bcf per day, which may be expanded to 2.0 Bcf per day. Our current investment in Atlantic Coast Pipeline is less than $1 million and represents a 5% ownership interest, and is the maximum extent of our current exposure to loss. Construction is expected to begin in the second half of 2016 with a targeted completion date in the second half of 2018.

Note 10 - Commitments, Guarantees and Contingencies

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.

In 2014, we entered into several unconditional purchase obligations in the ordinary course of business. These include capacity and supply agreements related to the Dalton Pipeline, PennEast Pipeline, Atlantic Coast Pipeline and wholesale services, which are reflected in the table below. In addition, other contracts in the ordinary course of business have expired or ended. The following table illustrates our expected future contractual payments under our obligations and other commitments as of September 30, 2014.

                                       
2019 &
 
In millions
 
Total
   
2014
   
2015
   
2016
   
2017
   
2018
   
thereafter
 
Recorded contractual obligations:
                                         
Long-term debt (1)
  $ 3,706     $ -     $ 200     $ 545     $ 22     $ 155     $ 2,784  
Short-term debt
    681       681       -       -       -       -       -  
Environmental remediation liabilities (2)
    454       16       83       104       50       38       163  
Pipeline replacement program costs (2)
    1       1       -       -       -       -       -  
Total
  $ 4,842     $ 698     $ 283     $ 649     $ 72     $ 193     $ 2,947  
Unrecorded contractual obligations and commitments (3) (8):
                                         
Pipeline charges, storage capacity and gas supply (4)
  $ 3,837     $ 304     $ 564     $ 292     $ 185     $ 174     $ 2,318  
Interest charges (5)
    2,798       36       179       171       147       146       2,119  
Operating leases (6)
    207       11       35       31       24       18       88  
Asset management agreements (7)
    31       2       9       8       6       4       2  
Standby letters of credit, performance/surety bonds (8)
    27       9       17       1       -       -       -  
Other
    9       1       3       3       1       1       -  
Total
  $ 6,909     $ 363     $ 807     $ 506     $ 363     $ 343     $ 4,527  
(1)
Excludes the $77 million step up to fair value of first mortgage bonds, $16 million unamortized debt premium and $6 million interest rate swaps fair value adjustment. Includes current portion of long-term debt of $200 million, which matures in January 2015.
(2)
Includes charges recoverable through base rates or rate rider mechanisms.
(3)
In accordance with GAAP, these items are not reflected in our unaudited Condensed Consolidated Statements of Financial Position.
(4)
Includes charges recoverable through a natural gas cost recovery mechanism or alternatively billed to Marketers and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 66 Bcf at floating gas prices calculated using forward natural gas prices as of September 30, 2014, and is valued at $271 million. As we do for other subsidiaries, we provide guarantees to certain gas suppliers for SouthStar in support of payment obligations.
(5)
Floating rate interest charges are calculated based on the interest rate as of September 30, 2014, and the maturity date of the underlying debt instrument. As of September 30, 2014, we have $42 million of accrued interest on our unaudited Condensed Consolidated Statements of Financial Position that will be paid in the next 12 months.
(6)
We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with GAAP. However, this lease accounting treatment does not affect the future annual operating lease cash obligations as shown herein. Our operating leases are primarily for real estate.
(7)
Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements.
(8)
We provide guarantees to certain municipalities and other agencies and certain gas suppliers of SouthStar in support of payment obligations.

 
23

 
We also are involved in legal or administrative proceedings before various courts and agencies with respect to general claims, taxes, environmental, gas cost prudence reviews and other matters. Although we are unable to determine the ultimate outcomes of these other contingencies, we believe that our financial statements appropriately reflect these amounts, including the recording of liabilities when a loss is probable and reasonably estimable. For more information on these matters, see Note 11 in our Consolidated Financial Statements and related notes in Item 8 of our 2013 Form 10-K/A.

Contingencies and Guarantees

Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur. We have certain subsidiaries that enter into various financial and performance guarantees and indemnities providing assurance to third parties. We believe the likelihood of payment under our guarantees is remote. No liability has been recorded for such guarantees and indemnifications as the fair value was inconsequential at inception.

Regulatory Matters

On December 21, 2012, Atlanta Gas Light filed a petition with the Georgia Commission for approval to resolve a volumetric imbalance of natural gas related to Atlanta Gas Light’s use of retained storage assets to operationally balance the system for the benefit of the natural gas market. On September 11, 2014, we filed a stipulation that was entered between us, staff of the Georgia Commission and several marketers that include a resolution of the 4.6 Bcf imbalance over a five-year period from January 1, 2015 through December 31, 2019. Over the five-year period, discretionary funds available from the Universal Service Fund, which is controlled by the Georgia Commission, would be used to resolve 25% of the imbalance, or 1.15 Bcf of natural gas. Atlanta Gas Light would be obligated for 25% as well and we have recorded a reserve in our unaudited Condensed Consolidated Statements of Financial Position representing the future estimated cost to purchase the 1.15 Bcf of natural gas. Marketers would be obligated to resolve the remaining 50% of the imbalance, or 2.3 Bcf of natural gas. The Georgia Commission is expected to vote on the petition in December 2014. We are currently unable to predict the ultimate outcome.

On August 7, 2014, staff of the Illinois Commission and the Citizens Utility Board (CUB) filed testimony in the 2003 gas cost prudence review disputing certain gas loan transactions offered by Nicor Gas under its Chicago Hub services requesting refunds of $18 million and $22 million, respectively. We have filed testimony in this proceeding disputing that any refund is due. Similar gas loan transactions were provided in other open review years. The resolution will ultimately be decided by the Illinois Commission. We are currently unable to predict the ultimate outcome and have recorded no liability for this matter.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that 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. See Note 3 for additional information.

Litigation

We are involved in litigation arising in the normal course of business. Although in some cases the company is unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require us to take charges against, or will result in reductions in, future earnings. Management believes that while the resolution of these contingencies, whether individually or in aggregate, could be material to earnings in a particular period, they will not have a material adverse effect on our consolidated financial position or cash flows. For additional litigation information, see Note 11 in our Consolidated Financial Statements and related notes in Item 8 of our 2013 Form 10-K/A.

PBR Proceeding Nicor Gas’ PBR plan was a regulatory plan that provided economic incentives based on natural gas cost performance. The PBR plan went into effect in 2000 and was terminated effective January 1, 2003, following allegations that Nicor Gas acted improperly in connection with the plan. Under this plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. Since 2002, the amount of the savings and losses required to be shared has been disputed by the CUB and others, with the Illinois Attorney General (IAG) intervening, and subject to extensive contested discovery and other regulatory proceedings before administrative law judges and the Illinois Commission. In 2009, the staff of the Illinois Commission, IAG and CUB requested refunds of $85 million, $255 million and $305 million, respectively.

 
24

 
In February 2012, we committed to a stipulation with the staff of the Illinois Commission for a resolution of the dispute through credits to Nicor Gas customers of $64 million. On November 5, 2012, the Administrative Law Judges issued a proposed order for a refund of $72 million to ratepayers. In the fourth quarter of 2012, we increased our accrual for this dispute by $8 million for a total of $72 million as a result of these developments and their effect on the estimated liability.

On June 7, 2013, the Illinois Commission issued an order requiring us to refund $72 million to current Nicor Gas customers through our purchased gas adjustment mechanism based upon natural gas throughput over 12 months beginning on July 1, 2013. Approximately $43 million was refunded during the first half of 2014, which resulted in the completion of all refunds. On February 28, 2014, the CUB appealed the Illinois Commission’s order requesting refunds consistent with its 2009 request to the appellate court in Illinois and Nicor Gas filed its response brief on July 25, 2014. The CUB filed its reply brief on October 17, 2014. There is no set time frame for a final ruling by the appellate court.

Note 11 - Segment Information

Our operating segments comprise revenue-generating components of our company for which we produce separate financial information internally that regularly is used 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 operations, wholesale services and midstream operations - and other, a non-operating segment.

Effective September 1, 2014, we closed on the sale of Tropical Shipping, which historically operated within our cargo shipping segment. The assets and liabilities of these businesses are classified as held for sale on the unaudited Condensed Consolidated Statements of Financial Position, and the financial results of these businesses are reflected as discontinued operations on the unaudited Condensed Consolidated Statements of Income. Amounts shown in this note, unless otherwise indicated, exclude assets held for sale and discontinued operations. Cargo shipping also included our investment in Triton, which was not part of the sale and has been reclassified into our “other” segment. See Note 12 for additional information.

Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities in seven states. 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 all regulated utilities, with rates determined by individual state regulatory commissions. These natural gas distribution utilities have similar economic and risk characteristics.

We are also involved in several related and complementary businesses. Our retail operations segment includes retail natural gas marketing to end-use customers primarily in Georgia and Illinois. Additionally, retail operations provide home protection products and services. Our wholesale services segment engages in natural gas storage and gas pipeline arbitrage and related activities. Additionally, they provide natural gas asset management and/or related logistics services for each of our utilities except Nicor Gas, as well as for nonaffiliated companies. Our midstream operations segment includes our non-utility storage and pipeline operations, including the operation of high-deliverability natural gas storage assets. Our “other” segment includes aggregated subsidiaries that individually are not significant on a stand-alone basis and that do not fit into one of our operating segments.

 
25

 
The chief operating decision maker of the company is the Chairman, President and Chief Executive Officer, who utilizes EBIT as the primary measure of profit and loss in assessing the results of each segment’s operations. EBIT includes operating income and other income and expenses. Items we do not include in EBIT are income taxes and financing costs, including interest expense, each of which we evaluate on a consolidated basis. 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 September 30, 2014

In millions
 
Distribution operations
   
Retail operations
   
Wholesale services (1)
   
Midstream operations
   
Other (3)
   
Intercompany eliminations
   
Consolidated
 
Operating revenues from external parties
  $ 439     $ 146     $ 5     $ 4     $ 1     $ (6 )   $ 589  
Intercompany revenues
    35       -       -       -       -       (35 )     -  
Total operating revenues
    474       146       5       4       1       (41 )     589  
Operating expenses
                                                       
Cost of goods sold
    138       99       3       (3 )     -       (39 )     198  
Operation and maintenance
    145       34       10       5       1       (2 )     193  
Depreciation and amortization
    79       7       -       5       2       -       93  
Taxes other than income taxes
    24       1       1       1       3       -       30  
Total operating expenses
    386       141       14       8       6       (41 )     514  
Gain on disposition of assets
    -       -       3       -       -       -       3  
Operating income (loss)
    88       5       (6 )     (4 )     (5 )     -       78  
Other income (expense)
    1       -       (1 )     -       3       -       3  
EBIT
  $ 89     $ 5     $ (7 )   $ (4 )   $ (2 )   $ -     $ 81  
Capital expenditures
  $ 196     $ 3     $ -     $ 3     $ 9     $ -     $ 211  
 
Three months ended September 30, 2013

In millions
 
Distribution
operations (4)
   
Retail operations (4)
   
Wholesale services (1)
   
Midstream operations
   
Other (3)
   
Intercompany eliminations
   
Consolidated (4)
 
Operating revenues from external parties
  $ 409     $ 138     $ 13     $ 19     $ 1     $ (6 )   $ 574  
Intercompany revenues
    36       -       -       -       -       (36 )     -  
Total operating revenues
    445       138       13       19       1       (42 )     574  
Operating expenses
                                                       
Cost of goods sold
    111       92       1       9       -       (39 )     174  
Operation and maintenance
    150       31       13       5       3       (3 )     199  
Depreciation and amortization
    89       8       -       5       2       -       104  
Taxes other than income taxes
    22       1       1       1       2       -       27  
Total operating expenses
    372       132       15       20       7       (42 )     504  
Operating income (loss)
    73       6       (2 )     (1 )     (6 )     -       70  
Other income
    4       -       -       -       3       -       7  
EBIT
  $ 77     $ 6     $ (2 )   $ (1 )   $ (3 )   $ -     $ 77  
Capital expenditures
  $ 200     $ 3     $ -     $ 3     $ 5     $ -     $ 211  

Nine months ended September 30, 2014

In millions
 
Distribution
operations (4)
   
Retail operations (4)
   
Wholesale services (1)
   
Midstream operations
   
Other (3)
   
Intercompany eliminations
   
Consolidated (4)
 
Operating revenues from external parties
  $ 2,821     $ 728     $ 383     $ 65     $ 5     $ (62 )   $ 3,940  
Intercompany revenues
    153       1       -       -       -       (154 )     -  
Total operating revenues
    2,974       729       383       65       5       (216 )     3,940  
Operating expenses
                                                       
Cost of goods sold
    1,655       498       13       44       -       (210 )     2,000  
Operation and maintenance
    515       105       59       18       2       (6 )     693  
Depreciation and amortization
    235       21       1       14       10       -       281  
Taxes other than income taxes
    146       3       2       4       5       -       160  
Total operating expenses
    2,551       627       75       80       17       (216 )     3,134  
Gain on disposition of assets
    -       -       3       -       -       -       3  
Operating income (loss)
    423       102       311       (15 )     (12 )     -       809  
Other income (expense)
    5       -       (3 )     1       5       -       8  
EBIT
  $ 428     $ 102     $ 308     $ (14 )   $ (7 )   $ -     $ 817  
Identifiable and total assets (2)
  $ 11,628     $ 663     $ 1,056     $ 692     $ 9,167     $ (9,253 )   $ 13,953  
Capital expenditures
  $ 504     $ 9     $ 1     $ 8     $ 21     $ -     $ 543  

 
26

 
Nine months ended September 30, 2013

In millions
 
Distribution
operations (4)
   
Retail operations (4)
   
Wholesale services (1)
   
Midstream operations
   
Other (3)
   
Intercompany eliminations
   
Consolidated (4)
 
Operating revenues from external parties
  $ 2,266     $ 605     $ 73     $ 58     $ 5     $ (16 )   $ 2,991  
Intercompany revenues
    134       -       -       -       -       (134 )     -  
Total operating revenues
    2,400       605       73       58       5       (150 )     2,991  
Operating expenses
                                                       
Cost of goods sold
    1,142       402       21       25       -       (143 )     1,447  
Operation and maintenance
    493       94       36       17       1       (7 )     634  
Depreciation and amortization
    265       20       1       13       10       -       309  
Taxes other than income taxes
    124       3       2       4       6       -       139  
Total operating expenses
    2,024       519       60       59       17       (150 )     2,529  
Gain on disposition of assets
    -       -       11       -       -       -       11  
Operating income (loss)
    376       86       24       (1 )     (12 )     -       473  
Other income
    11       -       -       2       5       -       18  
EBIT
  $ 387     $ 86     $ 24     $ 1     $ (7 )   $ -     $ 491  
Identifiable and total assets (2)
  $ 11,215     $ 644     $ 930     $ 726     $ 9,784     $ (9,783 )   $ 13,516  
Capital expenditures
  $ 495     $ 7     $ -     $ 11     $ 13     $ -     $ 526  
(1)
The revenues for wholesale services are netted with costs associated with its energy and risk management activities. A reconciliation of our operating revenues and our intercompany revenues is shown in the following table.

In millions
 
Third party gross revenues (4)
   
Intercompany revenues
   
Total gross revenues (4)
   
Less gross gas costs
   
Operating revenues (4)
 
Three months ended September 30, 2014
  $ 1,885     $ 126     $ 2,011     $ 2,006     $ 5  
Three months ended September 30, 2013
    1,716       69       1,785       1,772       13  
Nine months ended September 30, 2014
    8,313       584       8,897       8,514       383  
Nine months ended September 30, 2013
    5,792       312       6,104       6,031       73  
(2)
Identifiable assets are those used in each segment’s operations and exclude assets held for sale.
(3)
Our other segment now also includes our investment in Triton, which was part of our cargo shipping segment that has been classified as discontinued operations. For more information, see Note 12.
(4)
Amounts revised and include prior period adjustments. See Note 13 for additional information.

Information by segment on our Statements of Financial Position as of December 31, 2013, is as follows:

In millions
 
Identifiable and total assets
 
Distribution operations (1)
  $ 11,634  
Retail operations (1)
    685  
Wholesale services (1)
    1,163  
Midstream operations
    713  
Other
    10,160  
Intercompany elimination
    (10,088 )
Consolidated (1)
  $ 14,267  
(1)
Amounts revised for prior period adjustments. See Note 13 for additional information.



 
27


Note 12 - Discontinued Operations

On September 1, 2014, we closed on the sale of Tropical Shipping to an unrelated third party. The after-tax cash proceeds and distributions from the transaction were $225 million. We determined that the cumulative foreign earnings of Tropical Shipping would no longer be indefinitely reinvested offshore. Accordingly, we recognized income tax expense of $60 million, of which $31 million was recorded in the first quarter of 2014, and the remaining $29 million was recorded in the third quarter of 2014 related to the cumulative foreign earnings for which no tax liabilities had been previously recorded, resulting in our repatriation of $86 million in cash.

During the first quarter of 2014, based upon the negotiated sales price, we also recorded a goodwill impairment charge of $19 million, for which there is no income tax benefit. Additionally, we recognized a total of $7 million charge in the second and third quarters of 2014 related to the suspension of depreciation and amortization for assets that we were not compensated for by the buyer. The assets and liabilities of Tropical Shipping classified as held for sale on the unaudited Condensed Consolidated Statements of Financial Position are as follows:

   
December 31,
   
September 30,
 
In millions
 
2013
   
2013
 
Current assets
           
Cash and cash equivalents
  $ 24     $ 34  
Short-term investments
    1       1  
Receivables
    36       33  
Inventories
    9       9  
Other
    1       3  
Total current assets
    71       80  
Long-term assets and other deferred debits
               
Property, plant and equipment, net
    124       126  
Goodwill
    61       61  
Intangible assets
    19       19  
Other
    8       8  
Total long-term assets and other deferred debits
    212       214  
Total assets held for sale
  $ 283     $ 294  
Current liabilities
               
Other accounts payable - trade
  $ 11     $ 9  
Accrued expenses
    7       7  
Other
    22       23  
Total liabilities held for sale
  $ 40     $ 39  

The financial results of these businesses are reflected as discontinued operations, and all prior periods presented have been recast to reflect the discontinued operations. The components of discontinued operations recorded on the unaudited Condensed Consolidated Statements of Income are as follows:

   
Three months ended
September 30,
   
Nine months ended
September 30,
 
In millions
 
2014
   
2013
   
2014
   
2013
 
Operating revenues
  $ 62     $ 89     $ 243     $ 264  
Operating expenses
                               
Cost of goods sold
    38       55       149       162  
Operation and maintenance (1)
    20       27       75       82  
Depreciation and amortization (2)
    -       4       5       14  
Taxes other than income taxes
    1       2       5       5  
Loss on sale and goodwill impairment (3)
    5       -       28       -  
Total operating expenses
    64       88       262       263  
Operating (loss) income
    (2 )     1       (19 )     1  
(Loss) income before income taxes
    (2 )     1       (19 )     1  
Income tax expense (4)
    (29 )     -       (61 )     -  
(Loss) Income from discontinued operations, net of tax
  $ (31 )   $ 1     $ (80 )   $ 1  
(1)
Includes $1 million for the three and nine months ended September 30, 2014, for another business not related to Tropical Shipping that we discontinued in the third quarter of 2014 and was included in our “other” segment.
(2)
We ceased depreciating and amortizing Tropical Shipping’s assets on April 4, 2014, as a result of entering into an agreement to sell this business and the assets were classified as held for sale.
(3)
Primarily relates to the suspension of depreciation and amortization for the nine months ended September 30, 2014 of $7 million and $19 million of goodwill attributable to Tropical Shipping that was impaired as of March 31, 2014, based on the negotiated sales price.
(4)
Includes $31 million and $29 million that were recorded in the first and third quarters of 2014, respectively, related to the cumulative foreign earnings for which no tax liabilities had been previously recorded.

 
28



Note 13 - Revision to Prior Period Financial Statements

In October 2014, we identified an accounting issue in our revenue recognition related to certain of our regulatory infrastructure programs. Historically, our regulatory accounting models used to record revenues under these programs did not differentiate between allowable costs based on what the regulator has approved compared to an incurred cost that would otherwise be charged to expense under the accounting literature. Specifically, Accounting Standards Codification (ASC) 980 - Regulated Operations prohibits capitalizing allowed, but not incurred, costs such as shareholder return, even if allowed by a respective state regulatory body. Shareholder returns and other allowed, but not incurred, costs can generally only be recognized in earnings when they are collected through rates. This change is only applicable to our distribution operations segment and primarily affects our operating revenues, operation and maintenance expense, depreciation and amortization, interest expense and income tax expense amounts.

The adjustments impacted each year since 1998. The cumulative decrease to January 1, 2013 retained earnings as a result of the adjustments was $45 million. This adjustment resulted in a decrease to net income of $4 million and $13 million for the three and nine months ended September 30, 2013, respectively. These amounts will be recognized in future periods, when collected through rates from customers.

Additionally, we recorded other adjustments that we identified for prior periods that were included for completeness. The most significant of these include the intangible asset amortization. We have determined that our use of the straight-line method of amortizing our customer relationships and trade names was not applied consistent with the requirements of ASC 350 Intangibles-Goodwill and Other (ASC 350). ASC 350 requires that an intangible asset be amortized over its useful life in a manner to reflect the pattern in which the economic benefits of the intangible assets are consumed. The impact for this adjustment was an increase in depreciation and amortization expense of $1 million and $3 million for the three and nine months ended September 30, 2013, respectively. These amounts were generally offset within our unaudited Condensed Consolidated Statements of Income by the previously discussed adjustments related to our regulatory infrastructure programs for the deferral of depreciation expenses. Additionally, these adjustments resulted in a decrease to intangible assets, net of $8 million as of September 30, 2013. We have determined that we should be utilizing the undiscounted cash flows as a basis to amortize these assets. Other previously identified immaterial uncorrected amounts are reflected in the revised amounts.

We assessed the materiality of these issues on our prior period financial statements and concluded they were not material to any prior annual or interim periods; however, the cumulative impact would have been material to the interim period ended September 30, 2014, if adjusted in 2014. As a result, in accordance with accounting standards, we revised our prior period financial statements as described below to correct for these adjustments. The revision had no effect on reported cash flows. The following tables present the effects of the revisions to our unaudited Condensed Consolidated Statements of Income, unaudited Condensed Consolidated Statements of Financial Position and unaudited Condensed Consolidated Statements of Cash Flows for the following interim periods:
 
   
For the three months ended
   
For the nine months ended
 
   
September 30, 2013
   
September 30, 2013
 
In millions, except per share amounts
 
As filed (1)
   
Adjustment
   
Revised
   
As filed (1)
   
Adjustment
   
Revised
 
Operating revenues
  $ 586     $ (12 )   $ 574     $ 3,024     $ (33 )   $ 2,991  
Operating expenses
                                               
Cost of goods sold
    174       -       174       1,447       -       1,447  
Operation and maintenance
    199       -       199       636       (2 )     634  
Depreciation and amortization
    105       (1 )     104       311       (2 )     309  
Taxes other than income taxes
    27       -       27       139       -       139  
Total operating expenses
    505       (1 )     504       2,533       (4 )     2,529  
Gain on disposition of assets
    -       -       -       11       -       11  
Operating income
    81       (11 )     70       502       (29 )     473  
Other income
    7       -       7       19       (1 )     18  
Interest expense, net
    (43 )     6       (37 )     (135 )     9       (126 )
Income before income taxes
    45       (5 )     40       386       (21 )     365  
Income tax expense
    18       (2 )     16       145       (8 )     137  
Income from continuing operations
    27       (3 )     24       241       (13 )     228  
Income from discontinued operations
    1       -       1       1       -       1  
Net income
    28       (3 )     25       242       (13 )     229  
Less net income attributable to the noncontrolling interest
    -       -       -       11       -       11  
Net income attributable to AGL Resources Inc.
  $ 28     $ (3 )   $ 25     $ 231     $ (13 )   $ 218  
Per common share information
                                               
Basic earnings per common share (2)
                                               
Continuing operations
  $ 0.23     $ (0.03 )   $ 0.20     $ 1.95     $ (0.10 )   $ 1.85  
Discontinued operations
    0.01       -       0.01       0.01       -       0.01  
Basic earnings per common share attributable to AGL Resources Inc. common shareholders
  $ 0.24     $ (0.03 )   $ 0.21     $ 1.96     $ (0.10 )   $ 1.86  
Diluted earnings per common share (2)
                                               
Continuing operations
  $ 0.23     $ (0.03 )   $ 0.20     $ 1.95     $ (0.11 )   $ 1.84  
Discontinued operations
    0.01       -       0.01       0.01       -       0.01  
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders
  $ 0.24     $ (0.03 )   $ 0.21     $ 1.96     $ (0.11 )   $ 1.85  
(1)  
Reflects the reclassification of the Tropical Shipping amounts as discontinued operations.
(2)  
Excludes net income attributable to the noncontrolling interest.

 

   
As of September 30, 2013
 
In millions
 
As filed (1)
   
Revised
 
Current assets
           
Regulatory assets
  $ 133     $ 87  
Total current assets
    2,091       2,252  
Long-term assets and other deferred debits
               
Property, plant and equipment
    10,920       10,761  
Less accumulated depreciation
    2,307       2,281  
Property, plant and equipment, net
    8,613       8,480  
Regulatory assets
    871       845  
Intangible assets
    160       152  
Other
    251       259  
Total long-term assets and other deferred debits
    11,813       11,558  
Total assets
  $ 13,904     $ 13,810  
                 
Current liabilities
               
Accrued expenses
  $ 157     $ 149  
Total current liabilities
    2,407       2,407  
Long-term liabilities and other deferred credits
               
Accumulated deferred income taxes
    1,587       1,551  
Total long-term liabilities and other deferred credits
    7,934       7,897  
Total liabilities and other deferred credits
  $ 10,341     $ 10,304  
                 
Equity
               
Additional paid-in capital
  $ 2,046     $ 2,047  
Retained earnings
    1,100       1,042  
Total equity
    3,563       3,506  
Total liabilities and equity
  $ 13,904     $ 13,810  
(1)  
Reflects the reclassification of the Tropical Shipping amounts as held for sale.


   
For the nine months ended
September 30, 2013
 
In millions
 
As filed (1)
   
Adjustment
   
Revised
 
Cash flows from operating activities
                 
Net income
  $ 242     $ (13 )   $ 229  
Adjustments to reconcile net income to net cash flow provided by operating activities
                       
Depreciation and amortization
    311       (2 )     309  
Deferred income taxes
    (28 )     (4 )     (32 )
Changes to certain assets and liabilities
                       
Other, net
    63       19       82  
Net cash flow provided by operating activities
  $ 1,070       -     $ 1,070  
(1)  
Reflects the reclassification of the Tropical Shipping amounts as discontinued operations.

Revision to Previously Reported Intangible Assets Disclosures As discussed above, the adjustment of our intangible asset amortization affects our customer relationships and trade names. The revisions to our previously reported intangible assets and accumulated amortization in our Original Filing within the unaudited Condensed Consolidated Statements of Financial Position are presented in the following table.

   
September 30, 2013
 
 
In millions
 
Gross
   
Accumulated amortization
   
Net
 
Customer relationships
                 
Retail operations as reported
  $ 131     $ (12 )   $ 119  
Adjustments
    -       (9 )     (9 )
Revised total
  $ 131     $ (21 )   $ 110  
Trade names
                       
Retail operations as reported
  $ 46     $ (5 )   $ 41  
Adjustments
    -       1       1  
Revised total
  $ 46     $ (4 )   $ 42  


 
ITEM 4. CONTROLS AND PROCEDURES.

(a) Evaluation of disclosure controls and procedures. Under the supervision of and with the participation of our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of September 30, 2014, the end of the period covered by this report. Based on their evaluation, our principal executive officer and our principal financial officer have concluded that our disclosure controls and procedures were not effective as of September 30, 2014 because of the material weakness in our internal control over financial reporting described below.

Material Weakness in Internal Control Over Financial Reporting

In connection with the preparation of our condensed consolidated financial statements included in this Quarterly Report on Form 10-Q/A, we concluded that there was a material weakness in our internal control over financial reporting. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.

We did not maintain effective controls to appropriately apply the accounting guidance related to the recognition of allowed versus incurred costs. Specifically, the Company did not have controls to address the recognition of allowed versus incurred costs, primarily related to an allowed equity return, applied to the accounting for our regulated infrastructure programs and related disclosures that operated at a level of precision to prevent or detect potential material misstatements to the Company’s consolidated financial statements. This control deficiency could result in misstatements of the aforementioned accounts and disclosures that would result in a material misstatement of the consolidated financial statements that would not be prevented or detected. Accordingly, our management has concluded that the deficiency constitutes a material weakness.

As a result of the material weakness described above, the Company has revised its consolidated financial statements for the years ended December 31, 2013, 2012 and 2011, for each of the quarterly periods during the year ended December 31, 2013, and for the quarters ended March 31, 2014 and June 30, 2014.
 
Remediation Plan

We are committed to remediating the material weakness by implementing changes to our internal control over financial reporting. We have already implemented additional procedures to address the underlying causes of the material weakness prior to filing this quarterly report on Form 10-Q, and we will continue to implement changes and improvements in the internal control over financial reporting to remediate the control deficiency that caused the material weakness. The following actions have been, are being, or are planned to be implemented:

·
Reviewed all existing regulatory programs to ensure the proper evaluation of deferral components and proper treatment of allowed versus incurred costs pursuant to the accounting guidance. This review was completed prior to the issuance of revised consolidated financial statements.
·
Complete training for all appropriate personnel regarding the applicable accounting guidance and requirements through meetings concurrent with the process to evaluate all infrastructure and other regulated programs.
·
Create a process and design controls to capture and calculate allowed versus incurred costs and to record appropriate amounts in the consolidated financial statements. The Company will identify appropriate processes, reviews and other controls to ensure accurate amounts are appropriately reflected in the Company’s consolidated financial statements.
·
The Company is also considering other improvements and enhancements, including a review of organization structure, reporting relationships and adequacy of staffing levels, among others.

Management is committed to a strong internal control environment and believes that, when fully implemented and tested, the actions described above will remediate the material weakness in our internal control over financial reporting. We will continue to assess the effectiveness of our remediation efforts with our future assessments of the effectiveness of internal control over financial reporting. As we continue to evaluate and work to improve our internal control over financial reporting, management may determine to take additional measures to address the material weakness or determine to modify the remediation plan described above. Until the remediation steps set forth above are fully implemented, the material weakness described above will continue to exist.

(b) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2014, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 
31


PART II - OTHER INFORMATION

Item 6. Exhibits.

Exhibit Number
Description of Exhibit
Filer
The Filings Referenced for Incorporation by Reference
2
Stock Purchase Agreement by and among Aqua Acquisition Corp., Ottawa Acquisition LLC and Birdsall, Inc.(1)
AGL Resources
November 25, 2014, Form 10-Q/A, Exhibit 2
12
Statement of Computation of Ratio of Earnings to Fixed Charges
AGL Resources
November 7, 2014, Form 10-Q, Exhibit 12
31.1
Certification of John W. Somerhalder II
AGL Resources
Filed herewith
31.2
Certification of Andrew W. Evans
AGL Resources
Filed herewith
32.1
Certification of John W. Somerhalder II
AGL Resources
Filed herewith
32.2
Certification of Andrew W. Evans
AGL Resources
Filed herewith
101.INS
XBRL Instance Document
AGL Resources
Filed herewith
101.SCH
XBRL Taxonomy Extension Schema
AGL Resources
Filed herewith
101.CAL
XBRL Taxonomy Extension Calculation Linkbase
AGL Resources
Filed herewith
101.DEF
XBRL Taxonomy Definition Linkbase
AGL Resources
Filed herewith
101.LAB
XBRL Taxonomy Extension Labels Linkbase
AGL Resources
Filed herewith
101.PRE
XBRL Taxonomy Extension Presentation Linkbase
AGL Resources
Filed herewith

(1)
Portions of this exhibit have been omitted pursuant to a request for confidential treatment with the SEC. The omitted portions have been separately filed with the SEC. This exhibit replaces and supercedes in its entirety the Stock Purchase Agreement filed on July 30, 2014 with our Form 10-Q for the quarter ended June 30, 2014.

 
32


SIGNATURE
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

AGL RESOURCES INC.
(Registrant)


Date: November 25, 2014             /s/ Andrew W. Evans
Executive Vice President and Chief Financial Officer

 
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