Exhibit 99.4
Financial Statements and Supplemental Data
This exhibit does not reflect events occurring after the filing of AGL Resources Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013, other than to recast our segment information and to give effect to the classification of the business operations of our former cargo shipping segment (excluding Triton Container Investments, LLC) as discontinued operations, and does not modify or update the disclosures therein in any way, other than as described above.
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| Part III | |
| Item 15. Exhibits, Financial Statement Schedules | 52 |
| Schedule II | 53 |
| 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 and is capitalized in rate base for ratemaking purposes when the completed projects are placed in service |
| AGL Capital | AGL Capital Corporation |
| AGL Credit Facility | $1.3 billion credit agreement entered into by AGL Capital to support the AGL Capital commercial paper program |
| AGL Resources | AGL Resources Inc., together with its consolidated subsidiaries |
| Atlanta Gas Light | Atlanta Gas Light Company |
| Bcf | Billion cubic feet |
| Central Valley | Central Valley Gas Storage, LLC |
| Chattanooga Gas | Chattanooga Gas Company |
| Compass Energy | Compass Energy Services, Inc., which was sold in 2013 |
| 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 |
| EPA | U.S. Environmental Protection Agency |
| ERC | Environmental remediation costs associated with our distribution operations segment that are generally recoverable through rate mechanisms |
| FERC | Federal Energy Regulatory Commission |
| 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 |
| Georgia Natural Gas | The trade name under which SouthStar does business in Georgia |
| Golden Triangle | Golden Triangle Storage, Inc. |
| Heating Degree Days | A measure of the weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit |
| Heating Season | The period from November through March when natural gas usage and operating revenues are generally higher |
| Illinois Commission | Illinois Commerce Commission, the state regulatory agency for Nicor Gas |
| Jefferson Island | Jefferson Island Storage & Hub, LLC |
| 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 |
| Moody’s | Moody’s Investors Service |
| New Jersey BPU | New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas |
| Nicor | Nicor Inc. - an acquisition completed in December 2011 and former holding company of Nicor 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 |
| NUI | NUI Corporation |
| NYMEX | New York Mercantile Exchange, Inc. |
| 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 |
| OTC | Over-the-counter |
| Pad gas | Volumes of non-working natural gas used to maintain the operational integrity of the natural gas storage facility, also known as base gas |
| PBR | Performance-based rate, a regulatory plan at Nicor Gas that provided economic incentives based on natural gas cost performance. The plan terminated in 2003 |
| PGA | Purchased Gas Adjustment |
| Piedmont | Piedmont Natural Gas Company, Inc. |
| Pivotal Utility | Pivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas |
| PP&E | Property, plant and equipment |
| S&P | Standard & Poor’s Ratings Services |
| Sawgrass Storage | Sawgrass Storage, LLC |
| SEC | Securities and Exchange Commission |
| Sequent | Sequent Energy Management, L.P. |
| Seven Seas | Seven Seas Insurance Company, Inc. |
| SNG | Substitute natural gas, a synthetic form of gas manufactured from coal |
| SouthStar | SouthStar Energy Services LLC |
| STRIDE | Atlanta Gas Light’s Strategic Infrastructure Development and Enhancement program |
| Term Loan Facility | $300 million credit agreement entered into by AGL Capital to repay the $300 million senior notes that matured in 2011 |
| 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 now has been classified as discontinued operations and held for sale |
| U.S. | United States |
| Virginia Natural Gas | Virginia Natural Gas, Inc. |
| Virginia Commission | Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas |
| WACOG | Weighted average cost of gas |
| WNA | Weather normalization adjustment |
To the Board of Directors and Shareholders of AGL Resources Inc.:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of AGL Resources Inc. and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in the Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 1992). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Atlanta, GA
Fe | bruary 6, 2014, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of discontinued operations described in Note 15, as to which the date is September 2, 2014. |
3
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on our evaluation under the framework in the Internal Control - Integrated Framework (1992) issued by COSO, our management concluded that our internal control over financial reporting was effective as of December 31, 2013, in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
The effectiveness of our internal control over financial reporting has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report appearing herein.
February 6, 2014
/s/ John W. Somerhalder II
John W. Somerhalder II
Chairman, President and Chief Executive Officer
/s/ Andrew W. Evans
Andrew W. Evans
Executive Vice President and Chief Financial Officer
| As of December 31, | ||||||||
| In millions | 2013 | 2012 | ||||||
| Current assets | ||||||||
| $ | 81 | $ | 108 | |||||
| 49 | 56 | |||||||
| Receivables | ||||||||
| 786 | 677 | |||||||
| 385 | 362 | |||||||
| 268 | 235 | |||||||
| 83 | �� | 55 | ||||||
| 29 | 28 | |||||||
| 1,493 | 1,301 | |||||||
| Inventories | ||||||||
| 637 | 679 | |||||||
| 21 | 20 | |||||||
| 658 | 699 | |||||||
| Assets held for sale | 283 | 291 | ||||||
| Regulatory assets | 162 | 145 | ||||||
| Derivative instruments | 99 | 130 | ||||||
| Prepaid expenses | 63 | 132 | ||||||
| 57 | 21 | |||||||
| 2,945 | 2,883 | |||||||
| Long-term assets and other deferred debits | ||||||||
| 10,952 | 10,332 | |||||||
| 2,295 | 2,115 | |||||||
| 8,657 | 8,217 | |||||||
| 1,827 | 1,776 | |||||||
| Regulatory assets | 737 | 944 | ||||||
| Intangible assets | 154 | 76 | ||||||
| Long-term investments | 113 | 128 | ||||||
| Pension assets | 117 | 33 | ||||||
| 20 | 14 | |||||||
| 86 | 70 | |||||||
| 11,711 | 11,258 | |||||||
| $ | 14,656 | $ | 14,141 | |||||
See Notes to Consolidated Financial Statements.
AGL RESOURCES INC. AND SUBISIDIARIES
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - LIABILITIES AND EQUITY
See Notes to Consolidated Financial Statements.
AGL RESOURCES INC. AND SUBISIDIARIES
See Notes to Consolidated Financial Statements.
AGL RESOURCES INC. AND SUBSIDIARIES
| Years Ended December 31, | ||||||||||||
| In millions | 2013 | 2012 | 2011 | |||||||||
| Net income | $ | 331 | $ | 286 | $ | 186 | ||||||
| Other comprehensive income (loss), net of tax | ||||||||||||
Retirement benefit plans, net of tax | ||||||||||||
| Actuarial gain (loss) arising during the period (net of income tax of $46, $16 and $47) | 66 | (17 | ) | (71 | ) | |||||||
| Prior service costs arising during the period (net of income tax of $1) | - | 1 | - | |||||||||
| Reclassification of actuarial losses to net benefit cost (net of income tax of $10, $9 and $7) | 15 | 13 | 9 | |||||||||
| Reclassification of prior service costs to net benefit cost (net of income tax of $2, $2 and $3) | (3 | ) | (2 | ) | (3 | ) | ||||||
| Retirement benefit plans, net | 78 | (5 | ) | (65 | ) | |||||||
| Cash flow hedges, net of tax | ||||||||||||
| Net derivative instrument gains (losses) arising during the period (net of income tax of $1 and $2) | 1 | (2 | ) | (5 | ) | |||||||
| Reclassification of realized derivative losses to net income (net of income tax of $1, $3 and $1) | 3 | 6 | 3 | |||||||||
| Cash flow hedges, net | 4 | 4 | (2 | ) | ||||||||
| Other comprehensive income (loss), net of tax | 82 | (1 | ) | (67 | ) | |||||||
| Comprehensive income | 413 | 285 | 119 | |||||||||
| Less comprehensive income attributable to noncontrolling interest | 18 | 15 | 14 | |||||||||
| Comprehensive income attributable to AGL Resources Inc. | $ | 395 | $ | 270 | $ | 105 | ||||||
See Notes to Consolidated Financial Statements.
| See Notes to Consolidated Financial Statements. |
AGL RESOURCES INC. AND SUBSIDIARIES
See Notes to Consolidated Financial Statements.
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.
Basis of Presentation
Our consolidated financial statements as of and for the period ended December 31, 2013 are prepared in accordance with GAAP and under the rules of the SEC. Our consolidated financial statements include our accounts, the accounts of our wholly owned subsidiaries, the accounts of our majority-owned and other controlled subsidiaries and the accounts of our variable interest entity for which we are the primary beneficiary. For unconsolidated entities that we do not control, but exercise significant influence over, we primarily use the equity method of accounting and our proportionate share of income or loss is recorded on the Consolidated Statements of Income. See Note 10 for additional information. We have eliminated intercompany profits and transactions in consolidation except for intercompany profits where recovery of such amounts are probable under the affiliates’ rate regulation process.
Certain amounts from prior periods have been reclassified and revised to conform to the current-period presentation. The reclassifications and revisions had no material impact on our prior-period balances. During 2013, we recorded a $4 million ($2 million net of tax) reduction to our interest expense to correct the amortization period of credit fees related to the execution of the AGL Credit Facility in 2010 and its subsequent amendment in 2011.
On April 4, 2014 we entered into a definitive agreement to sell 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 Consolidated Statements of Financial Position and the financial results of these businesses are reflected as discontinued operations on the 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 is not a part of the sale and has been reclassified into our other segment. See Note 15 for additional information.
On December 9, 2011 we closed our merger with Nicor and created a combined company with increased scale and scope in the distribution, storage and transportation of natural gas. The businesses acquired in the merger are included in our consolidated financial statements for all of 2013 and 2012, and for 22 days of 2011.
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. As of December 31, 2013 and 2012, $24 million and $23 million, respectively, of cash and short and long-term investments in our Consolidated Statements of Financial Position held by Tropical Shipping are excluded from cash and cash equivalents as a result of the sale of that business and are included in assets held for sale. Prior to closing the sale, cash and short-term investments that were held in off-shore accounts were repatriated. See Note 12 and Note 15 for additional information on our income taxes on the cumulative foreign earnings for which no tax liability had previously been recorded.
Energy Marketing Receivables and Payables
Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements, which enable 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 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 December 31, 2013 and 2012, 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.
Wholesale services has a concentration of credit risk for services it provides to marketers and to utility and industrial counterparties. This credit risk is generally concentrated in 20 of its counterparties and is measured by 30-day receivable exposure plus forward exposure. We evaluate the credit risk of our counterparties using an S&P equivalent credit rating, which is determined by a process of converting the lower of the S&P or Moody’s rating to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody’s and 1 being equivalent to D/Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of its financial ratios. The following table provides additional information about wholesale services’ credit exposure at December 31, 2013, excluding $8 million of customer deposits.
| Dollars in millions | Total (1) | # of top counterparties | Concentration risk % | |||||||||
| Credit exposure | $ | 274 | 20 | 51 | % | |||||||
| (1) | Our counterparties or the counterparties’ guarantors had a weighted average S&P equivalent rating of A- at December 31, 2013. |
The weighted average credit rating is obtained by multiplying each counterparty’s assigned internal rating by its credit exposure and then summing the individual results for all counterparties. The sum is divided by the aggregate total exposure and this numeric value is then converted to an S&P equivalent.
We have established credit policies to determine and monitor the creditworthiness of counterparties, including requirements for posting of collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. When wholesale services is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty combined with a reasonable measure of our credit risk. Wholesale services also uses other netting agreements with certain counterparties with whom it conducts significant transactions.
Our other trade receivables consist primarily of natural gas sales and transportation services billed to residential, commercial, industrial and other customers. We bill customers monthly, and our accounts receivable are due within 30 days. For the majority of our receivables, we establish an allowance for doubtful accounts based on our collection experience and other factors. For our remaining receivables, if we are aware of a specific customer’s inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the receivable balance to the amount we reasonably expect to collect. If circumstances change, our estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect our estimates include, but are not limited to, customer credit issues, customer deposits and general economic conditions. Customers’ accounts are written off once we deem them to be uncollectible.
Nicor Gas Credit risk exposure at Nicor Gas is mitigated by a bad debt rider approved by the Illinois Commission. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas’ actual bad debt experience on an annual basis and the benchmark bad debt expense used to establish its base rates for the respective year. See Note 3 for additional information on the bad debt rider.
Atlanta Gas Light Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 12 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the nonpeak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include the purchase and sale of natural gas, customer service, billings and collections. We obtain credit security support in an amount equal to no less than two times a Marketer’s highest month’s estimated bill from Atlanta Gas Light.
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. 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 11 for information regarding a regulatory filing by Atlanta Gas Light related to gas inventory.
Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of goods sold at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. Since the cost of gas, including inventory costs, is charged to customers without markup, subject to Illinois Commission review, LIFO liquidations have no impact on net income. At December 31, 2013, the Nicor Gas LIFO inventory balance was $168 million. Based on the average cost of gas purchased in December 2013, the estimated replacement cost of Nicor Gas’ inventory at December 31, 2013 was $402 million, which exceeded the LIFO cost by $234 million.
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 periods presented, we recorded LOCOM adjustments to cost of goods sold in the following amounts to reduce the value of our inventories to market value.
| In millions | 2013 | 2012 | 2011 | |||||||||
| $ | 1 | $ | 3 | $ | 5 | |||||||
| 8 | 19 | 31 | ||||||||||
| Midstream operations | - | 1 | - | |||||||||
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. See Note 4 for additional fair value disclosures.
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. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows:
Level 1 Quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 items consist of exchange-traded derivatives, money market funds and certain retirement plan assets.
Level 2 Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Instruments in this category include shorter tenor exchange-traded and non-exchange-traded derivatives such as OTC forwards and options and certain retirement plan assets.
Level 3 Pricing inputs include significant unobservable inputs that may be used with internally developed methodologies to determine management’s best estimate of fair value from the perspective of market participants. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. Transfers into and out of Level 3 reflect the liquidity at the relevant natural gas trading locations and dates, which affects the significance of unobservable inputs used in the valuation applied to natural gas derivatives. Our Level 3 assets, liabilities and any applicable transfers are primarily related to our pension and other retirement benefit plan assets as described in Note 3, Note 4 and Note 6. Transfers for retirement plan assets are described further in Note 4. We determine both transfers into and out of Level 3 using values at the end of the interim period in which the transfer occurred.
The authoritative guidance related to fair value measurements and disclosures also includes a two-step process to determine whether the market for a financial asset is inactive or a transaction is distressed. Currently, this authoritative guidance does not affect us, as our derivative instruments are traded in active markets.
Our policy is to classify derivative cash flows and gains and losses within the same financial statement category as the hedged item, rather than by the nature of the instrument.
Fair Value Hierarchy Derivative assets and liabilities are classified in their entirety into the previously described fair value hierarchy levels based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors required under the guidance. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our own nonperformance risk on our liabilities. To mitigate the risk that a counterparty to a derivative instrument defaults on settlement or otherwise fails to perform under contractual terms, we have established procedures to monitor the creditworthiness of counterparties, seek guarantees or collateral backup in the form of cash or letters of credit and, in most instances, enter into netting arrangements. See Note 4 for additional fair value disclosures.
Netting of Cash Collateral and Derivative Assets and Liabilities under Master Netting Arrangements We maintain accounts with brokers to facilitate financial derivative transactions in support of our energy marketing and risk management activities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts.
We have elected to net derivative assets and liabilities under master netting arrangements on our Consolidated Statements of Financial Position. With that election, we are also required to offset cash collateral held in our broker accounts with the associated net fair value of the instruments in the accounts. See Note 4 for additional information about our cash collateral.
Natural Gas and Weather 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 5 for additional derivative disclosures.
Distribution Operations Nicor Gas, subject to review by the Illinois Commission, and Elizabethtown Gas, in accordance with a directive from the New Jersey BPU, enter into derivative instruments to hedge the impact of market fluctuations in natural gas prices. In accordance with regulatory requirements, any realized gains and losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. As previously noted, such derivative instruments are reported at fair value each reporting period in our Consolidated Statements of Financial Position. Hedge accounting is not elected and, in accordance with accounting guidance pertaining to rate-regulated entities, unrealized changes in the fair value of these derivative instruments are deferred or accrued as regulatory assets or liabilities until the related revenue is recognized.
For our Illinois weather risk associated with Nicor Gas, we implemented a corporate weather hedging program in the second quarter of 2013 that utilizes OTC weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather in Illinois. For January through April of 2014, we have purchased a put option that would partially offset lower operating margins resulting from lower customer usage in the event of warmer-than-normal weather, but would not be exercised in the event of colder-than-normal weather and, therefore, not offset higher margins if Heating Degree Days for the period are at normal or colder-than-normal levels. We will continue to use available methods to mitigate our exposure to weather in Illinois for future periods.
Retail Operations We have designated a portion of our derivative instruments, consisting of financial swaps to manage the risk associated with forecasted natural gas purchases and sales, as cash flow hedges. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period that the underlying hedged item is recognized in earnings.
We currently have minimal hedge ineffectiveness, which occurs when the gains or losses on the hedging instrument more than offset the losses or gains on the hedged item. Any cash flow hedge ineffectiveness is recorded in our Consolidated Statements of Income in the period in which it occurs. We have not designated the remainder of our derivative instruments as hedges for accounting purposes and, accordingly, we record changes in the fair values of such instruments within cost of goods sold in our Consolidated Statements of Income in the period of change.
We also enter into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-traded options are accounted for using the intrinsic value method and do not qualify for hedge accounting designation. Changes in the intrinsic value for non exchange-traded contracts are also reflected in operating revenues in our Consolidated Statements of Income.
Wholesale Services We purchase natural gas for storage when the current market price we pay to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price we can receive in the future, resulting in a positive net operating margin. We use NYMEX futures and OTC contracts to sell natural gas at that future price to substantially lock in the operating margin we will ultimately realize when the stored natural gas is sold. We also enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. We use NYMEX futures and OTC contracts to capture the price differential or spread between the locations served by the capacity in order to substantially lock in the operating margin we will ultimately realize when we physically flow natural gas between delivery points. These contracts generally meet the definition of derivatives and are carried at fair value in our Consolidated Statements of Financial Position, with changes in fair value recorded in operating revenues in our Consolidated Statements of Income in the period of change. These contracts are not designated as hedges for accounting purposes.
The purchase, transportation, storage and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis we utilize for the derivatives used to mitigate the natural gas price risk associated with our storage and transportation portfolio. We incur monthly demand charges for the contracted storage and transportation capacity, and payments associated with asset management agreements, and we recognize these demand charges and payments in our Consolidated Statements of Income in the period they are incurred. This difference in accounting methods can result in volatility in our reported earnings, even though the economic margin is essentially unchanged from the dates the transactions were consummated.
Debt We estimate the fair value of debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. In determining the market interest yield curve, we consider our currently assigned ratings for unsecured debt and the secured rating for the Nicor Gas first mortgage bonds.
Property, Plant and Equipment
A summary of our PP&E by classification as of December 31, 2013 and 2012 is provided in the following table.
Distribution Operations Our natural gas utilities’ PP&E consists of property and equipment that is currently in use, being held for future use and currently under construction. We report PP&E at its original cost, which includes:
· material and labor;
· contractor costs;
· construction overhead costs;
· AFUDC; and,
· Nicor Gas’ pad gas - the portion considered to be non-recoverable is recorded as depreciable PP&E, while the portion considered to be recoverable is recorded as non-depreciable PP&E.
We recognize no gains or losses on depreciable utility property that is retired or otherwise disposed, as required under the composite depreciation method. Such gains and losses are ultimately refunded to, or recovered from, customers through future rate adjustments. Our natural gas utilities also hold property, primarily land; this is not presently used and useful in utility operations and is not included in rate base. Upon sale, any gain or loss is recognized in other income.
Retail Operations, Wholesale Services, Midstream Operations and Other PP&E includes property that is in use and under construction, and we report it at cost. We record a gain or loss within operation and maintenance expense for retired or otherwise disposed-of property. Natural gas in salt-dome storage at Jefferson Island and Golden Triangle that is retained as pad gas is classified as non-depreciable PP&E and is carried at cost. Central Valley has two types of pad gas in its depleted reservoir storage facility. The first is non-depreciable PP&E, which is carried at cost, and the second is non-recoverable, over which we have no contractual ownership.
Depreciation Expense
We compute depreciation expense for distribution operations by applying composite, straight-line rates (approved by the state regulatory agencies) to the investment in depreciable property. More information on our rates used and the rate method is provided in the following table.
| (1) | Average composite straight-line depreciation rates for depreciable property, excluding transportation equipment, which may be depreciated in excess of useful life and recovered in rates. |
| (2) | Composite straight-line depreciation rates. |
| (3) | On October 23, 2013, the Illinois Commission approved a composite depreciation rate of 3.07%. The depreciation rate was effective as of August 30, 2013, the date the depreciation study was filed, and had the effect of reducing our 2013 depreciation expense by $19 million. |
For our non-regulated segments, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets.
AFUDC and Capitalized Interest
Atlanta Gas Light, Nicor Gas, Chattanooga Gas and Elizabethtown Gas are authorized by applicable state regulatory agencies or legislatures to capitalize the cost of debt and equity funds as part of the cost of PP&E construction projects in our Consolidated Statements of Financial Position. More information on our authorized or actual AFUDC rates is provided in the following table.
| 2013 | 2012 | 2011 | ||||||||||
| Atlanta Gas Light | 8.10 | % | 8.10 | % | 8.10 | % | ||||||
Nicor Gas (1) | 0.31 | % | 0.36 | % | 0.18 | % | ||||||
| Chattanooga Gas | 7.41 | % | 7.41 | % | 7.41 | % | ||||||
Elizabethtown Gas (1) | 0.41 | % | 0.51 | % | 0.53 | % | ||||||
AFUDC (in millions) (2) | $ | 19 | $ | 9 | $ | 6 | ||||||
| (1) | Variable rate is determined by FERC method of AFUDC accounting. |
| (2) | Amount recorded in the Consolidated Statements of Income. |
Asset Retirement Obligations
We record a liability at fair value for an asset retirement obligation (ARO) when a legal obligation to retire the asset has been incurred, with an offsetting increase to the carrying value of the related asset. Accretion of the ARO due to the passage of time is recorded as an operating expense. We have recorded an ARO of $3 million at December 31, 2013 and 2012 principally for our storage facilities. For our distribution PP&E, we cannot reasonably estimate the fair value of this obligation because we have determined that we have insufficient internal or industry information to reasonably estimate the potential settlement dates or costs.
Impairment of Assets
Our goodwill is not amortized, but is subject to an annual impairment test. Our other long-lived assets, including our finite-lived intangible assets, require an impairment review when events or circumstances indicate that the carrying amount may not be recoverable. We base our evaluation of the recoverability of other long-lived assets on the presence of impairment indicators such as the future economic benefit of the assets, any historical or future profitability measurements and other external market conditions or factors.
Goodwill We perform an annual goodwill impairment test on our reporting units that contain goodwill during the fourth quarter of each year, or more frequently if impairment indicators arise. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, the income approach and the market approach, using assumptions consistent with a market participant’s perspective.
Under the income approach, fair value is estimated based on the present value of estimated future cash flows discounted at an appropriate risk-free rate that takes into consideration the time value of money, inflation and the risks inherent in ownership of the business being valued. The cash flow estimates contain a degree of uncertainty, and changes in the projected cash flows could significantly increase or decrease the estimated fair value of a reporting unit. For the regulated reporting units, a fair recovery of, and return on, costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair value of these reporting units to decrease. Key assumptions used in the income approach include the return on equity for the regulated reporting units, long-term growth rates used to determine terminal values at the end of the discrete forecast period, current and future rates charged for contracted capacity and a discount rate. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The terminal growth rate is based on a combination of historical and forecasted statistics for real gross domestic product and personal income for each utility service area. The estimated rates we will charge to customers for capacity in the storage caverns were based on internal and external rate forecasts.
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Under the market approach, fair value is estimated by applying multiples to forecasted cash flows. This method uses metrics from similar publicly-traded companies in the same industry, when available, to determine how much a knowledgeable investor in the marketplace would be willing to pay for an investment in a similar company.
We weight the results of the two valuation approaches to estimate the fair value of each reporting unit. Our goodwill impairment testing also develops a baseline test and performs a sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived by altering those assumptions that are subjective in nature and inherent to a discounted cash flows calculation.
The significant assumptions that drive the estimated values of our reporting units are projected cash flows, discount rates, growth rates, weighted average cost of capital (WACC) and market multiples. Due to the subjectivity of these assumptions, we cannot provide assurance that future analyses will not result in impairment, as a future impairment depends on market and economic factors affecting fair value. Our annual goodwill impairment analysis in the fourth quarter of 2013 indicated that the estimated fair values of all but one of our reporting units with goodwill were in excess of the carrying values by approximately 20% to almost 500%, and were not at risk of failing step one of the impairment test.
Within our midstream operations segment, the estimated fair value of our storage and fuels reporting unit with $14 million of goodwill, exceeded its carrying value by less than 5% and is at risk of failing the step one test. The discounted cash flow model used in the goodwill impairment test for this reporting unit assumed discrete period revenue growth through fiscal 2021 to reflect the recovery of subscription rates, stabilization of earnings and establishment of a reasonable base year off of which we estimated the terminal value. In the terminal year we assumed a long-term earnings growth rate of 2.5% that we believe is appropriate given the current economic and industry specific expectations. As of the valuation date, we utilized a WACC of 7.0%, which we believe is appropriate as it reflects the relative risk, the time value of money, and is consistent with the peer group of this reporting unit as well as the discount rate that was utilized in our 2012 annual goodwill impairment test.
The cash flow forecast for the storage and fuels reporting unit assumed earnings growth over the next eight years. Should this growth not occur, this reporting unit may fail step one of a goodwill impairment test in a future period. Along with any reductions to our cash flow forecast, changes in other key assumptions used in our 2013 annual impairment analysis may result in the requirement to proceed to step two of the goodwill impairment test in future periods.
We will continue to monitor this reporting unit for impairment and note that continued declines in capacity or subscription rates, declines for a sustained period at the current market rates or other changes to the key assumptions and factors used in this analysis may result in a future impairment of goodwill. The risk of impairment of the underlying long-lived assets is not estimated to be significant because the assets have long remaining useful lives and authoritative accounting guidance requires such assets to be tested for impairment on the basis of undiscounted cash flows over their remaining useful lives.
Changes in the amount of goodwill for the twelve months ended December 31, 2013 and 2012 are provided below.
| (1) | Excludes goodwill at Tropical Shipping now classified as held for sale. See Note 15 for additional information. |
Long-Lived Assets We depreciate or amortize our long-lived assets and other intangible assets over their useful lives. Currently, we have no significant indefinite-lived intangible assets. These long-lived assets and other intangible assets are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through expected future cash flows. An impairment is indicated if the carrying amount of the long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If an impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset. We determined that there were no long-lived asset impairments in 2013, with the exception of Sawgrass Storage, for which we recorded an $8 million loss.
Intangible Assets Our intangible assets are presented in the following table and represent the estimated fair value at the date of acquisition of the acquired intangible assets in our businesses. As indicated previously, we perform an impairment review when impairment indicators are present. If present, we first determine whether the carrying amount of the asset is recoverable through the undiscounted future cash flows expected from the asset. If the carrying amount is not recoverable, we measure the impairment loss, if any, as the amount by which the carrying amount of the asset exceeds its fair value. The increase in our intangible assets of $91 million as of December 31, 2013 compared to the prior year was the result of two acquisitions within the retail operations segment. For more information, see “Acquisitions” in Note 2.
| Weighted average | December 31, 2013 | December 31, 2012 | ||||||||||||||||||||||||||
In millions | amortization period (in years) | Gross | Accumulated amortization | Net | Gross | Accumulated amortization | Net | |||||||||||||||||||||
| Customer relationships | ||||||||||||||||||||||||||||
| Retail operations | 13 | $ | 130 | $ | (15 | ) | $ | 115 | $ | 53 | $ | (6 | ) | $ | 47 | |||||||||||||
| Trade names | ||||||||||||||||||||||||||||
| Retail operations | 13 | 45 | (6 | ) | 39 | 30 | (2 | ) | 28 | |||||||||||||||||||
| Wholesale services | - | - | - | - | 1 | - | 1 | |||||||||||||||||||||
| Total | $ | 175 | $ | (21 | ) | $ | 154 | $ | 84 | $ | (8 | ) | $ | 76 | ||||||||||||||
Amortization expense was $13 million in 2013, $7 million in 2012 and $0 in 2011. Amortization expense for the next five years is estimated to be as follows:
| In millions | ||||
| 2014 | $ | 14 | ||
| 2015 | 14 | |||
| 2016 | 14 | |||
| 2017 | 14 | |||
| 2018 | 14 | |||
Accounting for Retirement Benefit Plans
We recognize the funded status of our plans as an asset or a liability on our Consolidated Statements of Financial Position, measuring the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. We recognize, as a component of OCI, the changes in funded status that occurred during the year that are not yet recognized as part of net periodic benefit cost. Because substantially all of its retirement costs are recoverable through base rates, Nicor Gas generally defers any charge or credit to comprehensive income to a regulatory asset or liability until the period in which the costs are included in base rates, in accordance with the authoritative guidance for rate-regulated entities. The assets of our retirement plans are measured at fair value within the funded status and are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement.
In determining net periodic benefit cost, the expected return on plan assets component is determined by applying our expected return on assets to a calculated asset value, rather than to the fair value of the assets as of the end of the previous fiscal year. For more information, see Note 6. In addition, we have elected to amortize gains and losses caused by actual experience that differs from our assumptions into subsequent periods. The amount to be amortized is the amount of the cumulative gain or loss as of the beginning of the year, excluding those gains and losses not yet reflected in the calculated value, that exceeds 10 percent of the greater of the benefit obligation or the calculated asset value; and the amortization period is the average remaining service period of active employees.
Taxes
Income Taxes The reporting of our assets and liabilities for financial accounting purposes differs from the reporting for income tax purposes. The principal difference between net income and taxable income relates to the timing of deductions, primarily due to the benefits of tax depreciation since we generally depreciate assets for tax purposes over a shorter period of time than for book purposes. The determination of our provision for income taxes requires significant judgment, the use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. We report the tax effects of depreciation and other temporary differences as deferred income tax assets or liabilities in our Consolidated Statements of Financial Position.
We have current and deferred income taxes in our Consolidated Statements of Income. Current income tax expense consists of federal and state income tax less applicable tax credits related to the current year. Deferred income tax expense is generally equal to the changes in the deferred income tax liability and regulatory tax liability during the year. We have recorded current deferred income taxes of $43 million (net of a valuation allowance of $8 million) as of December 31, 2013 and $4 million as of December 31, 2012 within other current assets in our Consolidated Statements of Financial Position.
Accumulated Deferred Income Tax Assets and Liabilities As noted above, we report some of our assets and liabilities differently for financial accounting purposes than we do for income tax purposes. We report the tax effects of the differences in those items as deferred income tax assets or liabilities in our Consolidated Statements of Financial Position. We measure these deferred income tax assets and liabilities using enacted income tax rates.
A deferred income tax liability is not recorded on undistributed foreign earnings that are expected to be indefinitely reinvested offshore. We consider, among other factors, actual cash investments offshore as well as projected cash requirements in making this determination. Changes in our investment or repatriation plans or circumstances could result in a different deferred income tax liability. We had $80 million of such cash and short-term investments on our Consolidated Statements of Financial Position as of December 31, 2013 and 2012. As of December 31, 2013, we would be required to record a deferred tax liability of $31 million if we no longer asserted indefinite reinvestment of undistributed foreign earnings.
Income Tax Benefits The authoritative guidance related to income taxes requires us to determine whether tax benefits claimed or expected to be claimed on our tax return should be recorded in our consolidated financial statements. Under this guidance, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.
Uncertain Tax Positions We recognize accrued interest related to uncertain tax positions in interest expense and penalties in operating expense in our Consolidated Statements of Income.
Tax Collections We do not collect income taxes from our customers on behalf of governmental authorities. However, we do collect and remit various other taxes on behalf of various governmental authorities. We record these amounts in our Consolidated Statements of Financial Position. In other instances, we are allowed to recover from customers other taxes that are imposed upon us. We record such taxes as operating expenses and record the corresponding customer charges as operating revenues.
Revenues
Distribution operations We record revenues when goods or services are provided to customers. Those revenues are based on rates approved by the state regulatory commissions of our utilities.
As required by the Georgia Commission, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial and industrial end-use customer’s distribution costs. Additionally, as required by the Georgia Commission, Atlanta Gas Light bills Marketers for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer’s annual straight-fixed-variable (SFV) charge, which reflects the historic volumetric usage pattern for the entire residential class. Generally, this seasonal rate design results in billing the Marketers a higher capacity charge in the winter months and a lower charge in the summer months, which impacts our operating cash flows. However, this seasonal billing requirement does not impact our revenues, which are recognized on a straight-line basis because the associated rate mechanism ensures that we ultimately collect the full annual amount of the SFV charges.
All of our utilities, with the exception of Atlanta Gas Light, have rate structures that include volumetric rate designs which allow recovery of certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. These are included in the Consolidated Statements of Financial Position as unbilled revenue. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries to the end of the period.
The tariffs for Virginia Natural Gas, Elizabethtown Gas and Chattanooga Gas contain WNAs that partially mitigate the impact of unusually cold or warm weather on customer billings and operating margin. The purpose of a WNA is to mitigate the effect of weather on customer bills by reducing bills when winter weather is colder-than-normal and increasing bills when weather is warmer-than-normal. In addition, the tariffs for Virginia Natural Gas, Chattanooga Gas and Elkton Gas contain revenue normalization mechanisms that mitigate the impact of conservation and declining customer usage.
Revenue Taxes We charge customers for gas revenue and gas use taxes imposed on us and remit amounts owed to various governmental authorities. Our policy for gas revenue taxes is to record the amounts charged to customers, which for some taxes includes a small administrative fee, as operating revenues, and to record the related taxes incurred as operating expenses in our Consolidated Statements of Income. Our policy for gas use taxes is to exclude these taxes from revenue and expense, aside from a small administrative fee that is included in operating revenues. As a result, the amount recorded in operating revenues will exceed the amount recorded in operating expenses by the amount of administrative fees that are retained by the Company. Revenue taxes included in operating expenses were $110 million in 2013, $85 million in 2012 and $9 million in 2011.
Retail operations Revenues from natural gas sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Sales revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. In addition, revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the most recent meter reading date to the end of the accounting period. The related receivables are included in the Consolidated Statements of Financial Position as unbilled revenue. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period.
We recognize revenues on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts. We recognize revenues for warranty and repair contracts on a straight-line basis over the contract term. Revenues for maintenance services are recognized at the time such services are performed.
Wholesale services We record wholesale services’ revenues when services are provided to customers. Profits from sales between segments are eliminated in the other segment and are recognized as goods or services sold to end-use customers. Transactions that qualify as derivatives under authoritative guidance related to derivatives and hedging are recorded at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are required to be presented net in revenue.
Midstream operations We record operating revenues for storage and transportation services in the period in which volumes are transported and storage services are provided. The majority of our storage services are covered under medium to long-term contracts at fixed market-based rates. We recognize our park and loan revenues ratably over the life of the contract.
Distribution operations Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, we charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms set 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. In accordance with the authoritative guidance for rate-regulated entities, we defer or accrue (that is, include as an asset or liability in the Consolidated Statements of Financial Position and exclude from, or include in, the Consolidated Statements of Income, respectively) the difference between the actual cost of goods sold 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. For more information, see Note 3.
Retail operations Our retail operations customers are charged for actual or estimated natural gas consumed. Within our cost of goods sold, we also include costs of fuel and lost and unaccounted for gas, adjustments to reduce the value of our inventories to market value and gains and losses associated with certain derivatives. Costs to service our warranty and repair contract claims and costs associated with the installation of heating and cooling equipment are recorded to cost of goods sold.
We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with authoritative guidance related to leases. This accounting treatment does not affect the future annual operating lease cash obligations. For more information, see Note 11.
Other income
Our other income is detailed in the following table. For more information on our equity investment income, see Note 10.
| In millions | 2013 | 2012 | 2011 | |||||||||
| AFUDC - equity | $ | 13 | $ | 6 | $ | 4 | ||||||
| Equity investment income | 3 | 13 | 1 | |||||||||
| Other, net | 1 | 5 | 2 | |||||||||
| Total other income | $ | 17 | $ | 24 | $ | 7 | ||||||
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. The increase in weighted average shares in 2012 compared to 2011 is primarily due to the issuance of 38.2 million shares in connection with the Nicor merger on December 9, 2011.
We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options. The vesting of certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance criteria. The future issuance of shares underlying the outstanding stock options depends on whether the 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, if performance units currently earned under the plan ultimately vest and if stock options currently exercisable at prices below the average market prices are exercised.
Acquisitions
On January 31, 2013, our retail operations segment acquired approximately 500,000 service contracts and certain other assets from NiSource Inc. for $122 million. These service contracts provide home warranty protection solutions and energy efficiency leasing solutions to residential and small business utility customers and complement the retail business acquired in the Nicor merger. Intangible assets related to this acquisition are primarily customer relationships of $46 million and trade names of $16 million. The amortization periods are estimated to be 14 years for customer relationships and 10 years for trade names. The final allocation of the purchase price to the fair value of assets acquired and liabilities assumed is presented in the following table:
| In millions | ||||
| Current assets | $ | 3 | ||
| PP&E | 12 | |||
| Goodwill | 51 | |||
| Intangible assets | 62 | |||
| Current liabilities | (6 | ) | ||
| Total purchase price | $ | 122 | ||
On June 30, 2013, our retail operations segment acquired approximately 33,000 residential and commercial energy customer relationships in Illinois for $32 million. These customer relationships have been recorded as an intangible asset and are expected to be amortized on a straight-line basis over an estimated period of 14 to 16 years.
On December 9, 2011, we completed our $2.5 billion merger with Nicor that created a combined company with increased scale and scope in the distribution, storage and transportation of natural gas. The effects of Nicor’s results of operations and financial condition are reflected for the twelve months ended December 31, 2013 and 2012, while our 2011 results include activity from December 10, 2011 through December 31, 2011. This merger resulted in:
· The issuance of 38.2 million shares of AGL Resources common stock
· Increased revenues in 2012 of $2,063 million
· Increased net income in 2012 of $70 million
· An increase to PP&E of $3,192 million
· An increase to goodwill and other intangible assets of $1,423 million and $103 million, respectively
Sale of Compass Energy
On May 1, 2013 we sold Compass Energy, a non-regulated retail natural gas business supplying commercial and industrial customers, within 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). Under the terms of the purchase and sale agreement, we are 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 will be determined and would be received from the buyer annually over a five-year earn out period based upon the financial performance of Compass Energy.
Non-Wholly Owned Entities
We hold ownership interests in a number of business ventures with varying ownership structures. We evaluate all of our partnership interests and other variable interests to determine if each entity is a variable interest entity (VIE), as defined in the authoritative accounting guidance. If a venture is a VIE for which we are the primary beneficiary, we consolidate the assets, liabilities and results of operations of the entity. We reassess our conclusion as to whether an entity is a VIE upon certain occurrences, which are deemed reconsideration events under the guidance. We have concluded that the only venture that we are required to consolidate as a VIE, as we are the primary beneficiary, is SouthStar. On our Consolidated Statements of Financial Position, we recognize Piedmont’s share of the non-wholly owned entity as a separate component of equity entitled “noncontrolling interest.” Piedmont’s share of current operations is reflected in “net income attributable to the noncontrolling interest” on our Consolidated Statements of Income. The consolidation of SouthStar has no effect on our calculation of basic or diluted earnings per common share amounts, which are based upon net income attributable to AGL Resources Inc.
For entities that are not determined to be VIEs, we evaluate whether we have control or significant influence over the investee to determine the appropriate consolidation and presentation. Generally, entities under our control are consolidated, and entities over which we can exert significant influence, but do not control, are accounted for under the equity method of accounting. However, we also invest in partnerships and limited liability companies that maintain separate ownership accounts. All such investments are required to be accounted for under the equity method unless our interest is so minor that there is virtually no influence over operating and financial policies, as are all investments in joint ventures.
Investments accounted for under the equity method are included in long-term investments on our Consolidated Statements of Financial Position, and the equity income is recorded within other income on our Consolidated Statements of Income and was immaterial for all periods presented. For additional information, see Note 10.
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, regulatory infrastructure program accruals, uncollectible accounts and other allowances for contingent losses, goodwill and 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.
Accounting Developments
On January 1, 2013, we adopted ASU 2011-11, Disclosures about Offsetting Assets and Liabilities and ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which require disclosures about offsetting and related arrangements in order to help financial statement users better understand the effect of those arrangements on our financial position. This guidance had no impact on our consolidated financial statements. See Note 4 for additional disclosures about our offsetting of derivative assets and liabilities.
On January 1, 2013, we adopted ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which requires enhanced disclosures of amounts reclassified out of accumulated other comprehensive income by component. This guidance had no impact on our consolidated financial statements. See Note 9 for additional disclosures relating to accumulated other comprehensive income.
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. Our regulatory assets and liabilities as of December 31, are summarized in the following table.
Our regulatory assets are probable of recovery. Base rates are designed to provide 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 are not aware of evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs consistent with our historical recoveries.
In the event that the provisions of authoritative guidance related to regulated operations were no longer applicable, we would recognize a write-off of regulatory assets that would result in a charge to net income and be classified as an extraordinary item. Additionally, while some regulatory liabilities would be written off, others would continue to be recorded as liabilities, but not as regulatory liabilities.
Although the natural gas distribution industry is competing with alternative fuels, primarily electricity, our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under the guidance remains appropriate. It is also our opinion that all regulatory assets are recoverable in future rate proceedings, and therefore we have not recorded any regulatory assets that are recoverable but are not yet included in base rates or contemplated in a rate rider or proceeding. The regulatory liabilities that do not represent revenue collected from customers for expenditures that have not yet been incurred are refunded to ratepayers through a rate rider or base rates. If the regulatory liability is included in base rates, the amount is reflected as a reduction to the rate base used to periodically set base rates.
The majority of our regulatory assets and liabilities listed in the preceding table are included in base rates except for the regulatory infrastructure program costs, ERC, bad debt, natural gas and energy efficiency costs, which are recovered through specific rate riders on a dollar-for-dollar basis. The rate riders that authorize the recovery of regulatory infrastructure program costs and natural gas costs include both a recovery of cost and a return on investment during the recovery period. Nicor Gas’ rate riders for environmental costs and energy efficiency costs provide a return of investment and expense including short-term interest on reconciliation balances. However, there is no interest associated with the under or over collections of bad debt expense.
Nicor Gas’ pension and retiree welfare benefit costs have historically been considered in rate proceedings in the same period they are accrued under GAAP. As a regulated utility, Nicor Gas expects to continue rate recovery of the eligible costs of these defined benefit retirement plans and, accordingly, associated changes in the funded status of Nicor Gas’ plans have been deferred as a regulatory asset or liability until recognized in net income, instead of being recognized in OCI. The Illinois Commission presently does not allow Nicor Gas the opportunity to earn a return on its recoverable retirement benefit costs. Such costs are expected to be recovered over a period of 11 years. The regulatory assets related to debt are also not included in rate base, but the costs are recovered over the term of the debt through the authorized rate of return component of base rates.
Environmental Remediation Costs We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. Our ERC liabilities are estimates of future remediation costs for investigation and cleanup of our former operating sites that are contaminated. Our estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, 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.
Our accrued ERC costs are not regulatory liabilities; however they are deferred as a corresponding regulatory asset until the costs are recovered from customers. These recoverable ERC assets are a combination of accrued ERC liabilities and recoverable cash expenditures for investigation and cleanup costs. We primarily recover these deferred costs through three rate riders that authorize dollar-for-dollar recovery. We expect to collect $45 million in revenues over the next 12 months, which is reflected as a current regulatory asset. We recovered $24 million in 2013, $13 million in 2012 and $5 million in 2011 from our ERC rate riders. The following table provides more information on the costs related to remediation of our former operating sites.
| In millions | # of sites | Probabilistic model cost estimates (2) | Engineering estimates (2) | Amount recorded | Expected costs over next 12 months | Cost recovery period | |||||||||||||||
Illinois (1) | 24 | $ | 209 - $458 | $ | 42 | $ | 251 | $ | 38 | As incurred (3) | |||||||||||
| New Jersey | 6 | 139 - 233 | 6 | 145 | 18 | 7 years (3) | |||||||||||||||
| Georgia and Florida | 13 | 28 - 112 | 8 | 40 | 7 | 5 years | |||||||||||||||
| North Carolina | 1 | n/a | 11 | 11 | 7 | No recovery | |||||||||||||||
| Total | 44 | $ | 376 - $803 | $ | 67 | $ | 447 | $ | 70 | ||||||||||||
| (1) | Nicor Gas and Commonwealth Edison Company are parties to an agreement to cooperate equally in cleaning up residue at 23 sites. |
| (2) | Material cleanups have not been completed for 26 sites. Therefore precise estimates are not available for future cleanup costs and considerable variability remains in future cost estimates. |
| (3) | Includes recovery of carrying costs on unrecovered expenditures. |
Bad Debt Rider Nicor Gas’ bad debt rider provides for the recovery from, or refund to, customers of the difference between Nicor Gas’ actual bad debt experience on an annual basis and a benchmark bad debt expense of $63 million, as determined by the Illinois Commission in February 2010. The over recovery is recorded as an increase to operating expenses on our Consolidated Statements of Income and a regulatory liability on our Consolidated Statements of Financial Position until refunded to customers. In the period refunded, operating expenses are reduced and the regulatory liability is reversed. The actual bad debt experience and resulting refunds are shown in the following table.
| Bad debt | Total | Amount refunded in | Amount to be refunded in | |||||||||||||||||||||
| In millions | experience | refund | 2012 | 2013 | 2014 | 2015 | ||||||||||||||||||
| 2013 | $ | 21 | $ | 42 | $ | - | $ | - | $ | 25 | $ | 17 | ||||||||||||
| 2012 | 23 | 40 | - | 24 | 16 | - | ||||||||||||||||||
| 2011 | 31 | 32 | 19 | 13 | - | - | ||||||||||||||||||
Accumulated Removal Costs In accordance with regulatory treatment, our depreciation rates are comprised of two cost components - historical cost and the estimated cost of removal, net of estimated salvage, of certain regulated properties. We collect these costs in base rates through straight-line depreciation expense, with a corresponding credit to accumulated depreciation. Because the accumulated estimated removal costs are not a generally accepted component of depreciation, but meet the requirements of authoritative guidance related to regulated operations, we have reclassified them from accumulated depreciation to the accumulated removal cost regulatory liability in our Consolidated Statements of Financial Position. In the rate setting process, the liability for these accumulated removal costs is treated as a reduction to the net rate base upon which our regulated utilities have the opportunity to earn their allowed rate of return.
Regulatory Infrastructure Programs We have infrastructure improvement programs at several of our utilities. Descriptions of these are as follows.
Atlanta Gas Light By order of the Georgia Commission (through a joint stipulation and a subsequent settlement agreement between Atlanta Gas Light and the Georgia Commission), Atlanta Gas Light began a pipeline replacement program to replace all bare steel and cast iron pipe in its system by December 2013.
The order provides for recovery of all prudent costs incurred in the performance of the program, which Atlanta Gas Light has recorded as a regulatory asset. Atlanta Gas Light will recover from end-use customers, through billings to Marketers, the costs related to the program net of any cost savings from the program. All such amounts will be recovered through a combination of straight-fixed-variable rates and a pipeline replacement revenue rider. The regulatory asset has two components: (i) the revenues recognized to date that have not yet been recovered from customers through the rate riders, and (ii) the future expected costs to be recovered through the base rates.
Atlanta Gas Light has recorded a current regulatory asset of $48 million, which represents the amount of recognized revenues expected to be collected from customers over the next 12 months. Atlanta Gas Light has also recorded a non-current asset of $87 million, which represents the expected future collection of revenues already recognized. The amounts recovered from the pipeline replacement revenue rider during the last three years were:
Atlanta Gas Light capitalizes and depreciates the capital expenditure costs incurred from the pipeline replacement program over the life of the assets. Operation and maintenance costs are expensed as incurred. Recoveries, which are recorded as revenue, are based on a formula that allows Atlanta Gas Light to recover operation and maintenance costs in excess of those included in its current base rates, depreciation expense and an allowed rate of return on capital expenditures. In the near term, the primary financial impact to Atlanta Gas Light from the pipeline replacement program is reduced cash flow from operating and investing activities, as the timing related to cost recovery does not match the timing of when costs are incurred. However, Atlanta Gas Light is allowed the recovery of carrying costs on the under-recovered balance resulting from the timing difference.
Our STRIDE program is comprised of the Integrated System Reinforcement Program (i-SRP), the Integrated Customer Growth Program (i-CGP), the pipeline replacement program that ended in 2013, and a new component, the Integrated Vintage Plastic Replacement Program (i-VPR). The purpose of the i-SRP is to upgrade our distribution system and liquefied natural gas facilities in Georgia, improve our peak-day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Our i-CGP authorizes Atlanta Gas Light to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. All related costs will be recovered through a surcharge. The STRIDE program requires us to file an updated ten-year forecast of infrastructure requirements under i-SRP along with a new construction plan every three years for review and approval by the Georgia Commission.
The purpose of the i-VPR program is to replace aging plastic pipe that was installed primarily in the mid-1960’s to the early 1980’s. We have identified approximately 3,300 miles of vintage plastic mains in our system that potentially should be considered for replacement over the next 15 - 20 years as it reaches the end of its useful life. On August 6, 2013, the Georgia Commission approved the replacement of 756 miles of vintage plastic pipe over four years at an estimated cost of $275 million. Additional reporting requirements and monitoring by the staff of the Georgia Commission were also included in the stipulation, which authorized a phased-in approach to funding the program through a monthly rider surcharge of $0.48 per customer through December 2014. This will be increased to $0.96 beginning in January 2015 and to $1.45 beginning in January 2016 and will continue through 2025.
Elizabethtown Gas In 2009, the New Jersey BPU approved the enhanced infrastructure program for Elizabethtown Gas, which was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. In May 2011, the New Jersey BPU approved Elizabethtown Gas’ request to spend an additional $40 million under this program before the end of 2012. Costs associated with the investment in this program are recovered through periodic adjustments to base rates that are approved by the New Jersey BPU. In August 2013, the New Jersey BPU approved the recovery of investments under this program through a permanent adjustment to base rates.
Additionally, in August 2013, we received approval from the New Jersey BPU for an extension of the accelerated infrastructure replacement program that we filed in July 2012. The approval allows for infrastructure investment of $115 million over four years, effective as of September 1, 2013. Carrying charges on the additional capital expenditures will be deferred at a weighted average cost for capital of 6.65%. Unlike the previous program, there will be no adjustment to base rates for the investments under the extended program until Elizabethtown Gas files its next rate case. We agreed to file a general rate case by September 2016.
On September 3, 2013, Elizabethtown Gas filed for a Natural Gas Distribution Utility Reinforcement Effort (ENDURE), a program that will improve our distribution system’s resiliency against coastal storms and floods. Under the proposed plan, Elizabethtown Gas will invest $15 million in infrastructure and related facilities and communication planning over a one year period beginning January 2014. Elizabethtown Gas is proposing to accrue and defer carrying charges on the investment until its next rate case proceeding.
Virginia Natural Gas On June 25, 2012, the Virginia Commission approved SAVE, an accelerated infrastructure replacement program, which is expected to be completed over a five-year period. The program permits a maximum capital expenditure of $25 million per year, not to exceed $105 million in total. SAVE is subject to annual review by the Virginia Commission. We began recovering program costs through a rate rider that was effective August 1, 2012. On May 1, 2013, we filed our annual SAVE rate update detailing the first-year performance and our expected future budget, which is subject to review and approval by the Virginia Commission. The rate update was approved with minor modifications by the Virginia Commission on July 23, 2013 and became effective as of August 1, 2013. On May 1, 2013, the Virginia Commission approved our CARE plan, which includes a limited set of conservation programs and measures at a cost of $2 million over a three-year period. The CARE plan became effective June 1, 2013.
Investment Tax Credits Deferred investment tax credits associated with distribution operations are included as a regulatory liability in our Consolidated Statements of Financial Position. These investment tax credits are being amortized over the estimated lives of the related properties as credits to income tax expense.
Regulatory Income Tax Liability For our regulated utilities, we also measure deferred income tax assets and liabilities using enacted income tax rates. Thus, when the statutory income tax rate declines before a temporary difference has fully reversed, the deferred income tax liability must be reduced to reflect the newly enacted income tax rates. However, the amount of the reduction is transferred to our regulatory income tax liability, which we are amortizing over the lives of the related properties as the temporary differences reverse over approximately 30 years.
Other Regulatory Assets and Liabilities Our recoverable pension and retiree welfare benefit plan costs for our utilities other than Nicor Gas are expected to be recovered through base rates over the next 2 to 21 years, based on the remaining recovery periods as designated by the applicable state regulatory commissions. This category also includes recoverable seasonal rates, which reflect the difference between the recognition of a portion of Atlanta Gas Light’s residential base rates revenues on a straight-line basis as compared to the collection of the revenues over a seasonal pattern. These amounts are fully recoverable through base rates within one year.
In September 2013, Nicor Gas filed its second Energy Efficiency Plan, which outlines program offerings and therm reduction goals with spending of $93 million over the three-year period June 2014 through May 2017. Nicor Gas’ first Energy Efficiency Program is currently in its third year and will end in May 2014. Although there is no statutory deadline for approval of gas utility plans, Nicor Gas requested approval in the same five-month timeframe, or by March 1, 2014, as established by statute for electric utilities. The new plan must be implemented by June 1, 2014.
Retirement benefit plans
The allocations of the AGL Resources Inc. Retirement Plan (AGL Plan), the Employees’ Retirement Plan of NUI Corporation (NUI Plan), and the Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Welfare Plan) were approximately 74% equity and 26% fixed income at December 31, 2013. The plans’ investment policies provide for some variation in these targets. The actual asset allocations of our retirement plans are presented in the following table by Level within the fair value hierarchy.
| December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||
Pension plans (1) | Welfare plans | |||||||||||||||||||||||||||||||||||||||
| In millions | Level 1 | Level 2 | Level 3 | Total | % of total | Level 1 | Level 2 | Level 3 | Total | % of total | ||||||||||||||||||||||||||||||
| Cash | $ | 3 | $ | 1 | $ | - | $ | 4 | - | % | $ | 1 | $ | - | $ | - | $ | 1 | 1 | % | ||||||||||||||||||||
| Equity securities: | ||||||||||||||||||||||||||||||||||||||||
U.S. large cap (2) | 93 | 205 | - | 298 | 33 | % | - | 52 | - | 52 | 62 | % | ||||||||||||||||||||||||||||
U.S. small cap (2) | 72 | 29 | - | 101 | 11 | % | - | - | - | - | - | % | ||||||||||||||||||||||||||||
International companies (3) | - | 139 | - | 139 | 15 | % | - | 14 | - | 14 | 17 | % | ||||||||||||||||||||||||||||
Emerging markets (4) | - | 34 | - | 34 | 4 | % | - | - | - | - | - | % | ||||||||||||||||||||||||||||
| Fixed income securities: | ||||||||||||||||||||||||||||||||||||||||
Corporate bonds (5) | - | 207 | - | 207 | 23 | % | - | 17 | - | 17 | 20 | % | ||||||||||||||||||||||||||||
| Other (or gov’t/muni bonds) | - | 29 | - | 29 | 3 | % | - | - | - | - | - | % | ||||||||||||||||||||||||||||
| Other types of investments: | ||||||||||||||||||||||||||||||||||||||||
Global hedged equity (6) | - | - | 43 | 43 | 5 | % | - | - | - | - | - | % | ||||||||||||||||||||||||||||
Absolute return (7) | - | - | 39 | 39 | 4 | % | - | - | - | - | - | % | ||||||||||||||||||||||||||||
Private capital (8) | - | - | 22 | 22 | 2 | % | - | - | - | - | - | % | ||||||||||||||||||||||||||||
| Total assets at fair value | $ | 168 | $ | 644 | $ | 104 | $ | 916 | 100 | % | $ | 1 | $ | 83 | $ | - | $ | 84 | 100 | % | ||||||||||||||||||||
| % of fair value hierarchy | 19 | % | 70 | % | 11 | % | 100 | % | 1 | % | 99 | % | - | % | 100 | % | ||||||||||||||||||||||||
| December 31, 2012 | ||||||||||||||||||||||||||||||||||||||||
Pension plans (1) | Welfare plans | |||||||||||||||||||||||||||||||||||||||
| In millions | Level 1 | Level 2 | Level 3 | Total | % of total | Level 1 | Level 2 | Level 3 | Total | % of total | ||||||||||||||||||||||||||||||
| Cash | $ | 14 | $ | 2 | $ | - | $ | 16 | 2 | % | $ | 1 | $ | - | $ | - | $ | 1 | 1 | % | ||||||||||||||||||||
| Equity securities: | ||||||||||||||||||||||||||||||||||||||||
U.S. large cap (2) | 69 | 181 | - | 250 | 30 | % | - | 38 | - | 38 | 55 | % | ||||||||||||||||||||||||||||
U.S. small cap (2) | 60 | 22 | - | 82 | 10 | % | - | - | - | - | - | % | ||||||||||||||||||||||||||||
International companies (3) | - | 120 | - | 120 | 14 | % | - | 12 | - | 12 | 18 | % | ||||||||||||||||||||||||||||
Emerging markets (4) | - | 34 | - | 34 | 4 | % | - | - | - | - | - | % | ||||||||||||||||||||||||||||
| Fixed income securities: | ||||||||||||||||||||||||||||||||||||||||
Corporate bonds (5) | - | 216 | - | 216 | 26 | % | - | 18 | - | 18 | 26 | % | ||||||||||||||||||||||||||||
| Other (or gov’t/muni bonds) | - | 30 | - | 30 | 3 | % | - | - | - | - | - | % | ||||||||||||||||||||||||||||
| Other types of investments: | ||||||||||||||||||||||||||||||||||||||||
Global hedged equity (6) | - | - | 38 | 38 | 4 | % | - | - | - | - | - | % | ||||||||||||||||||||||||||||
Absolute return (7) | - | - | 36 | 36 | 4 | % | - | - | - | - | - | % | ||||||||||||||||||||||||||||
Private capital (8) | - | - | 23 | 23 | 3 | % | - | - | - | - | - | % | ||||||||||||||||||||||||||||
| Total assets at fair value | $ | 143 | $ | 605 | $ | 97 | $ | 845 | 100 | % | $ | 1 | $ | 68 | $ | - | $ | 69 | 100 | % | ||||||||||||||||||||
| % of fair value hierarchy | 17 | % | 72 | % | 11 | % | 100 | % | 1 | % | 99 | % | - | % | 100 | % | ||||||||||||||||||||||||
| (1) | Includes $9 million at December 31, 2013 and $8 million at December 31, 2012 of medical benefit (health and welfare) component for 401h accounts to fund a portion of the other retirement benefits. |
| (2) | Includes funds that invest primarily in U.S. common stocks. |
| (3) | Includes funds that invest primarily in foreign equity and equity-related securities. |
| (4) | Includes funds that invest primarily in common stocks of emerging markets. |
| (5) | Includes funds that invest primarily in investment grade debt and fixed income securities. |
| (6) | Includes funds that invest in limited / general partnerships, managed accounts, and other investment entities issued by non-traditional firms or “hedge funds.” |
| (7) | Includes funds that invest primarily in investment vehicles and commodity pools as a “fund of funds.” |
| (8) | Includes funds that invest in private equity and small buyout funds, partnership investments, direct investments, secondary investments, directly / indirectly in real estate and may invest in equity securities of real estate related companies, real estate mortgage loans, and real-estate mezzanine loans. |
The following is a reconciliation of our retirement plan assets in Level 3 of the fair value hierarchy.
Fair value measurements using significant unobservable inputs - Level 3 (1) | ||||||||||||||||
| In millions | Global hedged equity | Absolute return | Private capital | Total | ||||||||||||
| Balance at December 31, 2011 | $ | 30 | $ | 34 | $ | 25 | $ | 89 | ||||||||
| Gains included in changes in net assets | 3 | 2 | 3 | 8 | ||||||||||||
| Purchases | 15 | - | - | 15 | ||||||||||||
| Sales | (10 | ) | - | (5 | ) | (15 | ) | |||||||||
| Balance at December 31, 2012 | $ | 38 | $ | 36 | $ | 23 | $ | 97 | ||||||||
| Gains included in changes in net assets | 5 | 3 | 4 | 12 | ||||||||||||
| Purchases | - | - | - | - | ||||||||||||
| Sales | - | - | (5 | ) | (5 | ) | ||||||||||
| Balance at December 31, 2013 | $ | 43 | $ | 39 | $ | 22 | $ | 104 | ||||||||
(1) There were no transfers out of Level 3, or between Level 1 and Level 2 for any of the periods presented. | ||||||||||||||||
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 Consolidated Statements of Financial Position as of the dates presented.
| (1) |
(2) | There were no significant unobservable inputs (Level 3) for any of the periods presented. |
(3) | There were no significant transfers between Level 1, Level 2, or Level 3 for any of the periods presented. |
Debt
Our long-term debt is recorded at amortized cost, with the exception of Nicor Gas’ first mortgage bonds, which were 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 presents the carrying amount and fair value of our long-term debt as of the following dates.
| (1) | Fair value determined using Level 2 inputs. |
Derivative Instruments
Our risk management activities are monitored by our Risk Management Committee, which consists of members of senior management and is charged with reviewing and enforcing our risk management activities and policies. Our use of derivative instruments, including physical transactions, is limited to predefined risk tolerances associated with pre-existing or anticipated physical natural gas sales and purchases and system use and storage. We use the following types of derivative instruments and energy-related contracts to manage natural gas price, interest rate, weather, automobile fuel price and foreign currency risks:
| · | forward, futures and options contracts; |
· | financial swaps; |
· | treasury locks; |
· | weather derivative contracts; |
· | storage and transportation capacity contracts; and |
· | foreign currency forward contracts |
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 December 31, 2013 and 2012 for agreements with such features, derivative instruments with liability fair values totaled $80 million and $39 million, respectively, for which we had posted no collateral to our counterparties. The maximum collateral that could be required with these features is $9 million. For more information, see “Energy Marketing Receivables and Payables” in Note 2. In addition, our energy marketing receivables and payables, which also have credit-risk-related or other contingent features, are discussed in Note 2. Our derivative instrument activities are included within operating cash flows as an adjustment to net income of $66 million, $72 million and $(17) million for the periods ended December 31, 2013, 2012 and 2011, respectively.
On April 4, 2013 we entered into two ten-year, $50 million fixed-rate forward-starting interest rate swaps to partially hedge any potential interest rate volatility prior to our issuance of the senior notes in the second quarter of 2013. The average interest rate on these swaps was 1.98%. Including existing $200 million of ten-year, 1.78% fixed-rate forward-starting interest rate swap hedges, which were executed on December 6, 2012, we had fixed-rate swaps totaling $300 million in notional value at an average interest rate of 1.85%. We designated the forward-starting interest rate swaps as cash flow hedges of our second quarter 2013 senior note issuance. The interest rate swaps were settled on May 16, 2013, the senior note issuance date, at which time we received $6 million in proceeds. The $6 million will be amortized to reduce interest expense over the first 10 years of the 30-year senior notes.
In May 2011, we entered into interest rate swaps related to the $300 million of outstanding 6.4% senior notes due in July 2016 that effectively converted $250 million from a fixed rate to a variable rate obligation. On September 6, 2012 we settled this $250 million fixed-rate to floating-rate interest rate swap.
The fair values of our interest rate swaps were reflected as a long-term derivative asset of $3 million at December 31, 2012. For more information on our debt, see Note 8.
The following table summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:
| Accounting Treatment | Recognition and Measurement | |||
| Statements of Financial Position | Income Statement | |||
| 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 Changes in fair value of the hedged item are recorded as adjustments to the carrying amount of the hedged item | 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 | ||
| 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:
| (1) |
(2) |
In accordance with regulatory requirements, gains and losses on derivative instruments used at Nicor Gas and Elizabethtown Gas in our distribution operations segment to hedge natural gas purchases for customer use are reflected in accrued natural gas costs within our Consolidated Statements of Financial Position until billed to customers. The following amounts represent the net realized gains (losses) related to these natural gas cost hedges for the years ended December 31.
The following table presents the fair values and Consolidated Statements of Financial Position classifications of our derivative instruments:
December 31, 2013 | December 31, 2012 | ||||||||||||||||
| In millions | Classification | Assets | Liabilities | Assets | Liabilities | ||||||||||||
| Designated as cash flow hedges and fair value hedges | |||||||||||||||||
| Natural gas contracts | Current | $ | 3 | $ | (1 | ) | $ | 1 | $ | (2 | ) | ||||||
| Interest rate swap agreements | Current | - | - | 3 | - | ||||||||||||
| Total | 3 | (1 | ) | 4 | (2 | ) | |||||||||||
| Not designated as cash flow hedges | |||||||||||||||||
| Natural gas contracts | Current | 691 | (761 | ) | 394 | (355 | ) | ||||||||||
| Natural gas contracts | Long-term | 206 | (220 | ) | 45 | (50 | ) | ||||||||||
| Total | 897 | (981 | ) | 439 | (405 | ) | |||||||||||
Gross amount of recognized assets and liabilities (1) | 900 | (982 | ) | 443 | (407 | ) | |||||||||||
Gross amounts offset in our Consolidated Statements of Financial Position (2) | (781 | ) | 902 | (299 | ) | 368 | |||||||||||
Net amounts of assets and liabilities presented in our Consolidated Statements of Financial Position (3) | $ | 119 | $ | (80 | ) | $ | 144 | $ | (39 | ) | |||||||
| (1) | The gross amounts of recognized assets and liabilities are netted within our 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 $121 million as of December 31, 2013 and $69 million as of December 31, 2012. Cash collateral is included in the “Gross amounts offset in our Consolidated Statements of Financial Position” line of this table. |
| (3) | At December 31, 2013 and 2012 we held letters of credit from counterparties that would offset, under master netting arrangements, an insignificant portion of these assets. |
Derivative Instruments on the Consolidated Statements of Income
The following table presents the impacts of our derivative instruments in our Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011.
| (1) | Associated with the fair value of existing derivative instruments at December 31, 2013, 2012 and 2011. |
| (2) |
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 years ended December 31, 2013, 2012 and 2011.
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 Consolidated Statements of Income over the next 12 months is $2 million. These deferred gains are related to natural gas derivative contracts associated with retail operations’ and with Nicor Gas’ system use. The expected gains are based upon the fair values of these financial instruments at December 31, 2013.
Oversight of Plans
The Retirement Plan Investment Committee (the Committee) appointed by our Board of Directors is responsible for overseeing the investments of our defined benefit retirement plans. Further, we have an Investment Policy (the Policy) for our pension and other retirement benefit plans whose goal is to preserve these plans’ capital and maximize investment earnings in excess of inflation within acceptable levels of capital market volatility. To accomplish this goal, the plans’ assets are managed to optimize long-term return while maintaining a high standard of portfolio quality and diversification.
We will continue to diversify retirement plan investments to minimize the risk of large losses in a single asset class. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund. The Policy’s permissible investments include domestic and international equities (including convertible securities and mutual funds), domestic and international fixed income securities (corporate and government obligations), cash and cash equivalents and other suitable investments.
Equity market performance and corporate bond rates have a significant effect on our reported funded status. Changes in the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO) are mainly driven by the assumed discount rate. Additionally, equity market performance has a significant effect on our market-related value of plan assets (MRVPA), which is used by the AGL Plan, to determine the expected return on the plan assets component of net annual pension cost. The MRVPA is a calculated value. Gains and losses on plan assets are spread through the MRVPA based on the five-year smoothing weighted average methodology.
Pension Benefits
We sponsor the AGL Plan, which is a tax-qualified defined benefit retirement plan for our eligible employees. A defined benefit plan specifies the amount of benefits an eligible participant eventually will receive using information about the participant, including information related to the participant’s earnings history, years of service and age. In 2012, we also sponsored two other tax-qualified defined benefit retirement plans for our eligible employees, a Nicor plan and a NUI plan. Effective as of December 31, 2012, the NUI plan and the Nicor plan were merged into the AGL Plan. The participants of the former Nicor and NUI plans are now being offered their benefits, as described below, through the AGL Plan.
We generally calculate the benefits under the AGL Plan based on age, years of service and pay. The benefit formula for the AGL Plan is currently a career average earnings formula. Participants who were employees as of July 1, 2000 and who were at least 50 years of age as of that date earned benefits until December 31, 2010 under a final average pay formula. Participants who were employed as of July 1, 2000, but did not satisfy the age requirement to continue under the final average earnings formula, transitioned to the career average earnings formula on July 1, 2000.
31
Effective January 1, 2012, the AGL Plan was frozen with respect to participation for non-union employees hired on or after that date. Such employees are entitled to employer provided benefits under their defined contribution plan that exceed defined contribution benefits for employees who participate in the defined benefit plan.
Participants in the former Nicor plan receive noncontributory defined pension benefits. These benefits cover substantially all employees of Nicor Gas and its affiliates that adopted the Nicor plan, hired prior to 1998. Pension benefits are based on years of service and the highest average annual salary for management employees and job level for collectively bargained employees (referred to as pension bands). The benefit obligation related to collectively bargained benefits considers the past practice of regular benefit increases.
Participants in the former NUI plan included substantially all of NUI Corporation’s employees who were employed on or before December 31, 2005. Florida City Gas union employees, who until February 2008 participated in a union-sponsored multiemployer plan became eligible to participate in the AGL Plan in February 2008. The AGL Plan provides pension benefits to these participants based on years of credited service and final average compensation as of the plan freeze date. Effective December 31, 2005, participation and benefit accrual under the NUI Plan were frozen. As of January 1, 2006, former participants in that plan became eligible to participate in the AGL Plan.
Welfare Benefits
Until December 31, 2012, we sponsored two defined benefit retiree health care plans for our eligible employees, AGL Welfare Plan and the Nicor Welfare Benefit Plan (Nicor Welfare Plan). Eligibility for these benefits is based on age and years of service. Effective December 31, 2012, the Nicor Welfare Plan was terminated and as of January 1, 2013, all participants under that plan became eligible to participate in the AGL Welfare Plan. This change in plan participation eligibility did not affect the benefit terms. The Nicor Welfare Plan benefits described below are now being offered to such participants under the AGL Welfare Plan.
The AGL Welfare Plan includes medical coverage for all eligible AGL Resources employees who were employed as of June 30, 2002, if they reach the plan’s retirement age while working for us. In addition, the AGL Welfare Plan provides life insurance for all employees if they have ten years of service at retirement. The state regulatory commissions have approved phase-in plans that defer a portion of the related benefits expense for future recovery. The AGL Welfare Plan terms include a limit on the employer share of costs at limits based on the coverage tier, plan elected and salary level of the employee at retirement.
Medicare eligible retirees covered by the AGL Welfare Plan, including all of those at least age 65, receive benefits through our contribution to a retiree health reimbursement arrangement account. Additionally, on the pre-65 medical coverage of the AGL Welfare Plan our expected cost is determined by a retiree premium schedule based on salary level and years of service. Due to the cap, there is no impact on the periodic benefit cost or on our accumulated projected benefit obligation for a change in the assumed healthcare cost trend rate for this portion of the plan.
The plan provisions that are applicable to prior participants in the Nicor Welfare Plan include health care and life insurance benefits to eligible retired employees and include a limit on the employer share of cost for employees hired after 1982.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 provides for a prescription drug benefit under Medicare Part D as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Prescription drug coverage for the Nicor Gas Medicare-eligible population changed, effective January 1, 2013, from an employer-sponsored prescription drug plan with the Retiree Drug Subsidy to an Employer Group Waiver Plan (EGWP). The EGWP replaces the employer sponsored prescription drug plan. The expected savings is estimated to be approximately 12% of total Medicare eligible liability.
We also have a separate unfunded supplemental retirement health care plan that provides health care and life insurance benefits to employees of discontinued businesses. This plan is noncontributory with defined benefits. Net plan expenses were immaterial in 2013 and 2012. The APBO associated with this plan was $2 million at December 31, 2013, and $3 million at December 31, 2012.
Assumptions
We considered a variety of factors in determining and selecting our assumptions for the discount rate at December 31. We based our discount rates separately for each plan on an above-mean yield curve provided by our actuaries that is derived from a portfolio of high quality (rated AA or better) corporate bonds with a yield higher than the regression mean curve and the equivalent annuity cash flows.
The components of our pension and welfare costs are set forth in the following table.
| Pension plans | Welfare plans | |||||||||||||||||||||||
| Dollars in millions | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||
| Service cost | $ | 29 | $ | 28 | $ | 14 | $ | 3 | $ | 4 | $ | 1 | ||||||||||||
| Interest cost | 43 | 44 | 29 | 14 | 16 | 6 | ||||||||||||||||||
| Expected return on plan assets | (62 | ) | (64 | ) | (33 | ) | (6 | ) | (5 | ) | (5 | ) | ||||||||||||
| Net amortization of prior service credit | (2 | ) | (2 | ) | (2 | ) | (5 | ) | (3 | ) | (4 | ) | ||||||||||||
| Recognized actuarial loss | 35 | 34 | 14 | 8 | 9 | 2 | ||||||||||||||||||
| Net periodic benefit cost | $ | 43 | $ | 40 | $ | 22 | $ | 14 | $ | 21 | $ | - | ||||||||||||
| Assumptions used to determine benefit costs | ||||||||||||||||||||||||
Discount rate (1) | 4.2 | % | 4.6 | % | 5.4 | % | 4.0 | % | 4.5 | % | 5.2 | % | ||||||||||||
Expected return on plan assets (1) | 7.8 | % | 8.4 | % | 8.5 | % | 7.8 | % | 8.5 | % | 8.2 | % | ||||||||||||
Rate of compensation increase (1) | 3.7 | % | 3.7 | % | 3.7 | % | 3.8 | % | 3.8 | % | 3.7 | % | ||||||||||||
Pension band increase (2) | 2.0 | % | 2.0 | % | 2.0 | % | n/a | n/a | n/a | |||||||||||||||
| (1) | Rates are presented on a weighted average basis. |
| (2) | Only applicable to the Nicor Gas union employees. |
The following tables present details about our pension and welfare plans.
| (1) | APBO differs from the projected benefit obligation in that the APBO excludes the effect of salary and wage increases. |
| (2) | Only applicable to the Nicor Gas union employees. |
A portion of the net benefit cost or credit related to these plans has been capitalized as a cost of constructing gas distribution facilities and the remainder is included in operation and maintenance expense.
Assumptions used to determine the health care benefit cost for the AGL Welfare Plan were as follows:
| 2013 | 2012 | |||||||
| Health care cost trend rate assumed for next year | 8.4 | % | 8.4 | % | ||||
| Ultimate rate to which the cost trend rate is assumed to decline | 4.5 | % | 4.5 | % | ||||
| Year that reaches ultimate trend rate | 2030 | 2030 | ||||||
Assumed health care cost trend rates can have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in the assumed health care cost trend rates for the AGL Welfare Plan would have the following effects:
| In millions | Effect on service and interest cost | Effect on benefit obligation | ||||||
| 1% Health care cost trend rate increase | $ | - | $ | 15 | ||||
| 1% Health care cost trend rate decrease | - | (13 | ) | |||||
As a result of a cap on expected cost for the AGL Welfare Plan, a one-percentage-point increase or decrease in the assumed health care trend does not materially affect periodic benefit cost or accumulated benefit obligation of the Plan.
The following table presents the amounts not yet reflected in net periodic benefit cost and included in net regulatory assets and accumulated OCI as of December 31, 2013 and 2012:
| Net regulatory assets | Accumulated OCI | Total | ||||||||||||||||||||||
| In millions | Pension plans | Welfare plans | Pension plans | Welfare plans | Pension plans | Welfare plans | ||||||||||||||||||
| December 31, 2013: | ||||||||||||||||||||||||
| Prior service credit | $ | - | $ | (20 | ) | $ | (9 | ) | $ | - | $ | (9 | ) | $ | (20 | ) | ||||||||
| Net loss | 61 | 60 | 210 | 30 | 271 | 90 | ||||||||||||||||||
| Total | $ | 61 | $ | 40 | $ | 201 | $ | 30 | $ | 262 | $ | 70 | ||||||||||||
| December 31, 2012: | ||||||||||||||||||||||||
| Prior service cost (credit) | $ | - | $ | (24 | ) | $ | (11 | ) | $ | (2 | ) | $ | (11 | ) | $ | (26 | ) | |||||||
| Net loss | 146 | 83 | 324 | 52 | 470 | 135 | ||||||||||||||||||
| Total | $ | 146 | $ | 59 | $ | 313 | $ | 50 | $ | 459 | $ | 109 | ||||||||||||
The 2014 estimated amortization out of regulatory assets or accumulated OCI for these plans are set forth in the following table.
| Net Regulatory Asset | Accumulated OCI | Total | ||||||||||||||||||||||
| In millions | Pension plans | Welfare plans | Pension plans | Welfare plans | Pension plans | Welfare plans | ||||||||||||||||||
| Amortization of prior service credit | $ | - | $ | (3 | ) | $ | (2 | ) | $ | - | $ | (2 | ) | $ | (3 | ) | ||||||||
| Amortization of net loss | 7 | 4 | 13 | 2 | 20 | 6 | ||||||||||||||||||
We recorded a regulatory asset for anticipated future cost recoveries of $108 million as of December 31, 2013 and $215 million as of December 31, 2012.
The following table presents the gross benefit payments expected for the years ended December 31, 2014 through 2023 for our pension and other retirement plans. There will be benefit payments under these plans beyond 2023.
| In millions | Pension plans | Welfare plans | ||||||
| 2014 | $ | 56 | $ | 20 | ||||
| 2015 | 60 | 20 | ||||||
| 2016 | 63 | 21 | ||||||
| 2017 | 66 | 22 | ||||||
| 2018 | 68 | 23 | ||||||
| 2019-2023 | 366 | 123 | ||||||
Contributions
Our employees generally do not contribute to our pension and other retirement plans; however, Nicor Gas and pre-65 AGL retirees make nominal contributions to their health care plan. We fund the qualified pension plans by contributing at least the minimum amount required by applicable regulations and as recommended by our actuary. However, we may also contribute in excess of the minimum required amount. As required by The Pension Protection Act of 2006 (the Act), we calculate the minimum amount of funding using the traditional unit credit cost method.
The Act contained new funding requirements for single-employer defined benefit pension plans and established a 100% funding target (over a 7-year amortization period) for plan years beginning after December 31, 2007. In 2013 we had no required contributions to the merged AGL Plan. In 2012 we contributed a combined $40 million to the AGL Plan and the NUI Plan. No contributions were made to the Nicor Plan in 2012.
Employee Savings Plan Benefits
We sponsor defined contribution retirement benefit plans that allow eligible participants to make contributions to their accounts up to specified limits. Under these plans, our matching contributions to participant accounts were $14 million in 2013, $12 million in 2012 and $7 million in 2011.
General
The AGL Resources Inc. Omnibus Performance Incentive Plan, as amended and restated, and the Long-Term Incentive Plan (1999) provide for the grant of incentive and nonqualified stock options, stock appreciation rights, shares of restricted stock, restricted stock units, performance cash awards and other stock-based awards to officers and key employees. Under the Omnibus Performance Incentive Plan, as of December 31, 2013, the number of shares issuable upon exercise of outstanding stock options, warrants and rights is 641,371 shares. Under the Long-Term Incentive Plan (1999) as of December 31, 2013, the number of shares issuable upon exercise of outstanding stock options, warrants and rights is 640,082 shares. The maximum number of shares available for future issuance under the Omnibus Performance Incentive Plan is 4,288,563 shares, which includes 1,697,363 shares previously available under the Nicor Inc. 2006 Long-Term Incentive Plan, as amended, pursuant to NYSE rules. No further grants will be made from the Long-Term Incentive Plan (1999) except for reload options that may be granted pursuant to the terms of certain outstanding options.
Accounting Treatment and Compensation Expense
We measure and recognize stock-based compensation expense for our stock-based awards over the requisite service period in our financial statements based on the estimated fair value at the date of grant for our stock-based awards using the modified prospective method. These stock awards include:
| · | stock options; |
| · | stock and restricted stock awards; and |
| · | performance units (restricted stock units, performance share units and performance cash units). |
Performance-based stock awards and performance units contain market conditions. Stock options, restricted stock awards and performance units also contain a service condition.
We estimate forfeitures over the requisite service period when recognizing compensation expense. These estimates are adjusted to the extent that actual forfeitures differ, or are expected to materially differ, from such estimates. The authoritative guidance requires excess tax benefits to be reported as a financing cash inflow. The difference between the proceeds from the exercise of our stock-based awards and the par value of the stock is recorded within additional paid-in capital.
We have granted incentive and nonqualified stock options with a strike price equal to the fair market value on the date of the grant. Fair market value is defined under the terms of the applicable plans as the closing price per share of AGL Resources common stock for the trading day immediately preceding the grant date, as reported in The Wall Street Journal. Stock options generally have a three-year vesting period.
The following table provides additional information related to our cash and stock-based compensation awards.
| In millions | 2013 | 2012 | 2011 | |||||||||
Compensation costs (1) | $ | 22 | $ | 9 | $ | 14 | ||||||
Income tax benefits (1) | 1 | 1 | 1 | |||||||||
Excess tax benefits (2) | - | 1 | 1 | |||||||||
| (1) | Recorded in our Consolidated Statements of Income. |
| (2) | Recorded in our Consolidated Statements of Financial Position. |
Incentive and Nonqualified Stock Options
The stock options we granted generally expire 10 years after the date of grant. Participants realize value from option grants only to the extent that the fair market value of our common stock on the date of exercise of the option exceeds the fair market value of the common stock on the date of the grant.
As of December 31, 2013 and 2012, we had no unrecognized compensation costs related to stock options. Cash received from stock option exercises for 2013 was $21 million, and the income tax benefits from stock option exercises were immaterial. Cash received from stock option exercises for 2012 was $7 million, and the income tax benefit from stock option exercises was $1 million. The following tables summarize activity related to stock options for key employees and non-employee directors. As used in the table, intrinsic value for options means the difference between the current market value and the grant price.
| Stock Options | ||||||||||||||||
| Number of options | Weighted average exercise price | Weighted average remaining life (in years) | Aggregate intrinsic value (in millions) | |||||||||||||
| Outstanding - December 31, 2010 | 2,229,112 | $ | 34.85 | |||||||||||||
| Granted | 1,685 | 42.19 | ||||||||||||||
| Exercised | (383,646 | ) | 31.11 | |||||||||||||
| Forfeited | (23,997 | ) | 37.70 | |||||||||||||
| Outstanding - December 31, 2011 | 1,823,154 | $ | 35.61 | |||||||||||||
| Granted | - | - | ||||||||||||||
| Exercised | (234,844 | ) | 32.07 | |||||||||||||
| Forfeited | (59,720 | ) | 37.34 | |||||||||||||
Outstanding - December 31, 2012 (1) | 1,528,590 | $ | 36.09 | 3.7 | $ | 6 | ||||||||||
| Granted | - | - | - | |||||||||||||
| Exercised | (617,358 | ) | 35.37 | 2.3 | ||||||||||||
| Forfeited | (12,500 | ) | 38.36 | 2.6 | ||||||||||||
Outstanding - December 31, 2013 (1) (2) | 898,732 | $ | 36.55 | 3.0 | $ | 10 | ||||||||||
(1) All options outstanding at December 31, 2013 and 2012 were exercisable.
(2) The range of exercise prices for the options outstanding at December 31, 2013 was $30.70 to $43.85.
We measure compensation cost related to stock options based on the fair value of these awards at their date of grant using the Black-Scholes option-pricing model. There were no options granted in 2013 and 2012, and the number of options granted in 2011 was immaterial. We use shares purchased under our 2006 share repurchase program to satisfy exercises to the extent that repurchased shares are available. Otherwise, we issue new shares from our authorized common stock.
Performance Units
In general, a performance unit is an award of the right to receive (i) an equal number of shares of our common stock, which we refer to as a restricted stock unit or (ii) cash, subject to the achievement of certain pre-established performance criteria, which we refer to as a performance cash unit. Performance units are subject to certain transfer restrictions and forfeiture upon termination of employment. The compensation cost of restricted stock unit awards is equal to the grant date fair value of the awards, recognized over the requisite service period, determined according to the authoritative guidance related to stock compensation. The compensation cost of performance cash unit awards is equal to the grant date fair value of the awards measured against progress towards the performance measure, recognized over the requisite service period. No other assumptions are used to value these awards.
Restricted Stock Units In general, a restricted stock unit is an award that represents the opportunity to receive a specified number of shares of our common stock, subject to the achievement of certain pre-established performance criteria. In 2013, we granted 43,830 restricted stock units to certain employees, all of which were outstanding as of December 31, 2013. These restricted stock units had a performance measurement period that ended December 31, 2013. The performance measure, which related to earnings before interest, income tax, depreciation and amortization, was met. As such, the related restricted stock awards will occur in 2014.
Performance Share Unit Awards A performance share unit award represents the opportunity to receive cash and shares subject to the achievement of certain pre-established performance criteria. We granted performance share unit awards to certain officers. These awards have a performance measure that relates to the Company’s relative total shareholder return relative to a group of peer companies. The recorded liability and maximum potential liability related to the 2013, 2012 and 2011 grants are as follows:
| In millions | Measurement period end date | Fair value accrued at December 31, 2013 | Maximum aggregate payout | ||||||
| Granted in 2011 | December 31, 2013 | $ | 7 | $ | 12 | ||||
| Granted in 2012 | December 31, 2014 | $ | 6 | $ | 18 | ||||
| Granted in 2013 | December 31, 2015 | $ | 3 | $ | 18 | ||||
Stock and Restricted Stock Awards
The compensation cost of both stock awards and restricted stock awards is equal to the grant date fair value of the awards, recognized over the requisite service period. No other assumptions are used to value the awards. We refer to restricted stock as an award of our common stock that is subject to time-based vesting or achievement of performance measures. Restricted stock awards are subject to certain transfer restrictions and forfeiture upon termination of employment.
Stock Awards - Non-Employee Directors Non-employee director compensation may be paid in shares of our common stock in connection with initial election, the annual retainer, and chair retainers, as applicable. Stock awards for non-employee directors are 100% vested and non-forfeitable as of the date of grant. During 2013 we issued 26,915 shares with a weighted average fair value of $44.04 to our non-employee directors.
Restricted Stock Awards - Employees The following table summarizes the restricted stock awards activity for our employees during the last two years.
(1)Subject to restriction.
Employee Stock Purchase Plan (ESPP)
We have a nonqualified, broad based ESPP for all eligible employees. As of December 31, 2013, there were 122,763 shares available for future issuance under this plan. Employees may purchase shares of our common stock in quarterly intervals at 85% of fair market value, and we record an expense for the 15% purchase price discount. Employee ESPP contributions may not exceed $25,000 per employee during any calendar year.
| 2013 | 2012 | 2011 | ||||||||||
| Shares purchased on the open market | 97,734 | 103,589 | 65,843 | |||||||||
| Average per-share purchase price | $ | 42.96 | $ | 38.96 | $ | 40.55 | ||||||
| Total purchase price discount | $ | 628,358 | $ | 591,855 | $ | 401,346 | ||||||
Our financing activities, including long-term and short-term debt, are subject to customary approval or review by state and federal regulatory bodies. Our wholly-owned subsidiary, AGL Capital, was established to provide for our ongoing financing needs through a commercial paper program, the issuance of various debt and hybrid securities and other financing arrangements. We fully and unconditionally guarantee all debt issued by AGL Capital. Nicor Gas is not permitted by regulation to make loans to affiliates or utilize AGL Capital for its financing needs. The following table provides maturity dates, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities that are included in our Consolidated Statements of Financial Position.
| (1) | Interest rates are calculated based on the daily weighted average balance outstanding for the 12 months ended December 31, 2013 and 2012. |
| (2) | As of December 31, 2013, the effective interest rates on our commercial paper borrowings were 0.4% for AGL Capital and 0.3% for Nicor Gas. |
| (3) | See Note 4 for additional information on our fair value measurements. |
Short-term Debt
Our short-term debt at December 31, 2013 and 2012 was composed of borrowings under our commercial paper programs.
Commercial Paper Programs We maintain commercial paper programs at AGL Capital and at Nicor Gas that consist of short-term, unsecured promissory notes that are 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 2013, our commercial paper maturities ranged from 1 to 123 days, and at December 31, 2013, remaining terms to maturity ranged from 2 to 99 days. During 2013, total borrowings and repayments netted to a payment of $206 million. For commercial paper issuances with original maturities over 3 months, borrowings and repayments were $374 million and $181 million, respectively.
Credit Facilities At December 31, 2013 and 2012, there were no outstanding borrowings under either the AGL Capital or Nicor Gas credit facilities. In November 2013, the lenders for our two credit facilities consented to our request to extend the maturity date of each facility by one year, in accordance with the terms of the respective credit agreements. The AGL Credit Facility and Nicor Gas Credit Facility maturity dates were extended to November 10, 2017 and December 15, 2017, respectively. The terms, conditions and pricing under the agreements remain unchanged.
Current Portion of Long-term Debt and Capital Leases The current portion of our long-term debt at December 31, 2012 was composed of the current portions of our long-term debt and capital lease obligations. Our capital leases consisted primarily of a sale/leaseback transaction of gas meters and other equipment that was completed in 2002 by Florida City Gas and expired in the second quarter 2013. In the second quarter 2012, Florida City Gas had the option to purchase the leased meters from the lessor at their fair market value, but it did not exercise this option.
Long-term Debt
Our long-term debt at December 31, 2013 and 2012 consisted of medium-term notes: Series A, Series B, and Series C, which we issued under an indenture dated December 1, 1989; senior notes; first mortgage bonds; and gas facility revenue bonds. Some of these issuances were completed in the private placement market. In determining that those specific bonds qualify for exemption from registration under Section 4(2) of the Securities Act of 1933, we relied on the facts that the bonds were offered only to a limited number of large institutional investors and each institutional investor that purchased the bonds represented that it was purchasing the bonds for its own account and not with a view to distribute them. We fully and unconditionally guarantee all of our senior notes. Additionally, substantially all of Nicor Gas’ properties are subject to the lien of the indenture securing its first mortgage bonds.
The majority of our long-term debt matures after fiscal year 2018. The annual maturities of our long-term debt for the next five years and thereafter are as follows:
Senior Notes On May 16, 2013 we issued $500 million in 30-year senior notes with a fixed interest rate of 4.4%. The net proceeds were used to repay a portion of AGL Capital’s commercial paper, including $225 million we borrowed to repay our senior notes that matured on April 15, 2013. There were no senior note issuances in 2012.
First Mortgage Bonds We acquired the first mortgage bonds of Nicor Gas, which were issued through the public and private placement markets, as a result of the 2011 merger.
Gas Facility Revenue Bonds We are party to a series of loan agreements with the New Jersey Economic Development Authority (NJEDA) under which the NJEDA has issued a series of gas facility revenue bonds. These gas revenue bonds are issued by state agencies or counties to investors, and proceeds from the issuance are then loaned to us.
During 2013 we refinanced $200 million of our outstanding tax-exempt gas facility revenue bonds, $180 million of which were previously issued by the New Jersey Economic Development Authority and $20 million of which were previously issued by Brevard County, Florida. The refinancing involved a combination of the issuance of $60 million of refunding bonds to, and the purchase of $140 million of existing bonds by, a syndicate of banks. Our relationship with the syndicate of banks regarding the bonds is governed by an agreement that contains representations, warranties, covenants and default provisions consistent with those contained in similar financing documents of ours. All of the bonds are floating-rate instruments. We had no cash receipts or payments in connection with the refinancing. The letters of credit providing credit support for the outstanding revenue bonds along with other related agreements were terminated as a result of the refinancing.
Financial and Non-Financial Covenants
The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month; however, our goal is to maintain these ratios at levels between 50% and 60%. These ratios, as calculated in accordance with the debt covenants, include standby letters of credit and surety bonds and exclude accumulated OCI items related to non-cash 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.
The credit facilities contain certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations and other matters customarily restricted in such agreements.
Default Provisions
Our credit facilities and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. The most important default events include:
· | a maximum leverage ratio |
· | insolvency events and nonpayment of scheduled principal or interest payments |
· | acceleration of other financial obligations |
· | change of control provisions |
We have no triggering events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that requires us to issue equity based on credit ratings or other triggering events. We were in compliance with all existing debt provisions and covenants, both financial and non-financial, as of December 31, 2013 and 2012.
Preferred Securities
At December 31, 2013 and 2012, we had 10 million shares of authorized, unissued Class A junior participating preferred stock, no par value, and 10 million shares of authorized, unissued preferred stock, no par value.
Treasury Shares
Our Board of Directors authorized us to purchase up to 8 million treasury shares through our repurchase plan, which expired on January 31, 2011. This plan was used to offset shares issued under our employee and non-employee director incentive compensation plans and our dividend reinvestment and stock purchase plans. Stock purchases under this plan were made in the open market or in private transactions at times, and in amounts that we deemed appropriate. We held the purchased shares as treasury shares and accounted for them using the cost method. We purchased no treasury shares in 2013 or 2012.
Dividends
Our common shareholders may receive dividends when declared at the discretion of our Board of Directors. Dividends may be paid in cash, stock or other form of payment, and payment of future dividends will depend on our future earnings, cash flow, financial requirements and other factors.
Additionally, we derive a substantial portion of our consolidated assets, earnings and cash flow from the operation of regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. As with most other companies, the payment of dividends is restricted by laws in the states where we conduct business. In certain cases, our ability to pay dividends to our common shareholders is limited by (i) our ability to pay our debts as they become due in the usual course of business and satisfy our obligations under certain financing agreements, including our debt-to-capitalization covenant, (ii) our ability to maintain total assets below total liabilities, and (iii) our ability to satisfy our obligations to any preferred shareholders.
Accumulated Other Comprehensive Loss
Our share of comprehensive income (loss) includes net income plus OCI, which includes changes in fair value of certain derivatives designated as cash flow hedges, certain changes in pension and other retirement benefit plans and reclassifications for amounts included in net income less net income and OCI attributable to the noncontrolling interest. For more information on our derivative instruments, see Note 5. For more information on our pensions and retirement benefit obligations, see Note 6. Our other comprehensive income (loss) amounts are aggregated within our accumulated other comprehensive loss. The following table provides changes in the components of our accumulated other comprehensive loss balances, net of the related tax effects allocated to each component of OCI.
In millions (1) | Cash flow hedges | Retirement benefit plans | Total | |||||||||
| As of December 31, 2010 | $ | (5 | ) | $ | (145 | ) | $ | (150 | ) | |||
| Other comprehensive loss | (2 | ) | (65 | ) | (67 | ) | ||||||
| As of December 31, 2011 | (7 | ) | (210 | (217 | ) | |||||||
| Other comprehensive income (loss) | 4 | (5 | ) | (1 | ) | |||||||
| As of December 31, 2012 | (3 | ) | (215 | ) | (218 | ) | ||||||
| Other comprehensive income, before reclassifications | 1 | 66 | 67 | |||||||||
| Amounts reclassified from accumulated other comprehensive loss | 3 | 12 | 15 | |||||||||
| As of December 31, 2013 | $ | 1 | $ | (137 | ) | $ | (136 | ) | ||||
| (1) |
40
The following table provides details of the reclassifications out of accumulated other comprehensive loss for the year ended December 31, 2013 and the ultimate favorable (unfavorable) impact on net income.
In millions (1) | |||||
| Cash flow hedges | |||||
| Natural gas contracts | $ | (1 | ) | Cost of goods sold | |
| Interest rate contracts | (3 | ) | Interest expense, net | ||
| Total before income tax | (4 | ) | |||
| Income tax benefit | 1 | ||||
| Total cash flow hedges | (3 | ) | |||
| Retirement benefit plan amortization of | |||||
| Actuarial losses | (25 | ) | See (2), below | ||
| Prior service credits | 5 | See (2), below | |||
| Total before income tax | (20 | ) | |||
| Income tax benefit | 8 | ||||
| Total retirement benefit plans | (12 | ) | |||
| Total reclassification for the period | $ | (15 | ) | ||
(1) | Amounts in parentheses indicate debits, or reductions, to profit/loss and credits to accumulated other comprehensive loss. Except for retirement benefit plan amounts, the profit/loss impacts are immediate. |
(2) | Amortization of these accumulated other comprehensive loss components is included in the computation of net periodic benefit cost. See Note 5 for additional details about net periodic benefit cost. |
On a quarterly basis we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) as defined by the authoritative accounting guidance on consolidation, and if so, which party is the primary beneficiary. We have determined that SouthStar, a joint venture owned by us and Piedmont, is the only VIE for which we are the primary beneficiary, which requires us to consolidate its assets, liabilities and Statements of Income. Our conclusion that SouthStar is a VIE resulted from our equal voting rights with Piedmont not being proportional to our economic obligation to absorb 85% of losses or residual returns from the joint venture. We account for our ownership of SouthStar in accordance with authoritative accounting guidance which is described within Note 2. The primary risks associated with SouthStar are discussed in our risk factors included in Item 1A.
SouthStar markets natural gas and related services under the trade name Georgia Natural Gas to customers in Georgia, and under various other trade names to customers in Illinois, Ohio, Florida, Maryland, Michigan and New York. Following are additional factors we considered in determining that we have the power to direct SouthStar’s activities that most significantly impact its performance.
| Operations |
Our wholly owned subsidiaries, Nicor Gas and Atlanta Gas Light, provide the following services, which affect SouthStar’s operations:
· | meter reading for SouthStar’s customers in Illinois and Georgia |
· | maintenance and expansion of the natural gas infrastructure in Illinois and Georgia |
· | assigning storage and transportation capacity used in delivering natural gas to SouthStar’s customers |
Liquidity and capital resources
· | guarantees of SouthStar’s activities with, and its credit exposure to, its counterparties and to certain natural gas suppliers in support of SouthStar’s payment obligations |
· | support of SouthStar’s daily cash management activities and assistance ensuring SouthStar has adequate liquidity and working capital resources by allowing SouthStar to utilize the AGL Capital commercial paper program for its liquidity and working capital requirements in accordance with our services agreement. |
Back office functions
· | Accounting, information technology, credit and internal controls services in accordance with our services agreement |
SouthStar’s earnings are allocated entirely in accordance with the ownership interests and are seasonal in nature, with the majority occurring during the first and fourth quarters of each year. SouthStar’s current assets consist primarily of natural gas inventory, derivative instruments and receivables from its customers. SouthStar also has receivables from us due to its participation in AGL Capital’s commercial paper program. SouthStar’s current liabilities consist primarily of accrued natural gas costs, other accrued expenses, customer deposits, derivative instruments and payables to us from its participation in AGL Capital’s commercial paper program.
SouthStar’s contractual commitments and obligations, including operating leases and agreements with third party providers, do not contain terms that would trigger material financial obligations in the event that such contracts were terminated. As a result, our maximum exposure to a loss at SouthStar is considered to be immaterial. SouthStar’s creditors have no recourse to our general credit beyond our corporate guarantees we have provided to SouthStar’s counterparties and natural gas suppliers. We have provided no financial or other support that was not previously contractually required. With the exception of our corporate guarantees and the aforementioned limited protections related to goodwill and intangible assets, we have not entered into any arrangements that could require us to provide financial support to SouthStar.
Price and volume fluctuations of SouthStar’s natural gas inventories can cause significant variations in our working capital and cash flow from operations. Changes in our operating cash flows are also attributable to SouthStar’s working capital changes resulting from the impact of weather, the timing of customer collections, payments for natural gas purchases and cash collateral amounts that SouthStar maintains to facilitate its derivative instruments.
Cash flows used in our investing activities include capital expenditures for SouthStar for the year ended December 31, of $3 million for 2013, $1 million for 2012 and $2 million for 2011. 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 or second quarter of each fiscal year. For the years ended December 31, 2013, 2012 and 2011, SouthStar distributed $17 million, $14 million and $16 million to Piedmont, respectively.
On September 1, 2013 we contributed to SouthStar our Illinois retail energy businesses with approximately 108,000 customers. Additionally, Piedmont contributed to SouthStar $22.5 million in cash to maintain its 15% ownership in the joint venture. In connection with the contribution of our Illinois retail energy businesses, we provided certain limited protections to Piedmont regarding the value of the contributed businesses related to goodwill and other intangible assets. Piedmont’s contribution is reflected as an increase to the noncontrolling interest on our Consolidated Statements of Financial Position and a financing activity on our Consolidated Statements of Cash Flows. These funds were used to reduce our commercial paper borrowings.
The following table provides additional information on SouthStar’s assets and liabilities as of the dates presented, which are consolidated within our Consolidated Statements of Financial Position.
(1) 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.
(2) SouthStar’s percentage of the amount on our Consolidated Statements of Financial Position.
The following table provides additional information about SouthStar’s revenues and expenses for the periods presented, which are consolidated within our Consolidated Statements of Income.
| December 31, | ||||||||
| In millions | 2013 | 2012 | ||||||
| Operating revenues | $ | 687 | $ | 576 | ||||
| Operating expenses | ||||||||
| Cost of goods sold | 491 | 411 | ||||||
| Operation and maintenance | 72 | 63 | ||||||
| Depreciation and amortization | 5 | 2 | ||||||
| Taxes other than income taxes | 1 | 2 | ||||||
| Total operating expenses | 569 | 478 | ||||||
| Operating income | $ | 118 | $ | 98 | ||||
Equity Method Investments
Triton We have an investment in Triton, a cargo container leasing company. Container equipment that is acquired by Triton is accounted for in tranches as defined in Triton’s operating agreement, and investors make capital contributions to Triton to invest in each of the tranches. As of December 31, 2013 we had invested in seven tranches established by Triton. For the years ended December 31, 2013 and 2012, income from our equity method investment in Triton of $9 million and $11 million, respectively, was classified as other income on our Consolidated Statements of Income.
Horizon Pipeline We have a 50% owned joint venture with Natural Gas Pipeline Company of America that is regulated by the FERC. Horizon Pipeline operates an approximate 70-mile natural gas pipeline from Joliet, Illinois to near the Wisconsin/Illinois border. Nicor Gas typically contracts for 70% to 80% of the total capacity.
Sawgrass Storage We own a 50% interest in Sawgrass Storage, a joint venture between us and a privately held energy exploration and production company. Sawgrass Storage was granted certification from the FERC in March 2012 for the development of an underground natural gas storage facility in Louisiana with 30 Bcf of working gas capacity. The FERC certificate is set to expire in March 2014.
In December 2013, the joint venture decided to terminate the development of this facility and recognized an impairment loss of $16 million, which reduced the carrying amount of the joint venture’s long-lived assets to fair value. Consequently, we recognized our 50% interest in the loss during the fourth quarter of 2013, resulting in an $8 million ($5 million net of tax) charge to operating income.
The carrying amounts of our investments that are accounted for under the equity method at December 31 were as follows:
| (1) | Includes our investment in Sawgrass Storage of $1 million at December 31, 2013 and $9 million at December 31, 2012. |
Our net equity investment income for the years ended December 31, 2013, 2012 and 2011, was $3 million, $13 million and $1 million, respectively, which is reflected within other income on our Consolidated Statements of Income. The majority of our net equity investment income is attributable to our investment in Triton. For more information on our other income, see Note 2. During 2013 we received distributions of $17 million from our equity investees and $14 million in 2012.
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. The following table illustrates our expected future contractual payments under our obligations and other commitments as of December 31, 2013.
| (1) | Excludes the $82 million step up to fair value of first mortgage bonds, $16 million unamortized debt premium and $9 million interest rate swaps fair value adjustment. |
| (2) | Includes charges recoverable through base rates or rate rider mechanisms. |
| (3) | In accordance with GAAP, these items are not reflected in our Consolidated Statements of Financial Position. |
| (5) |
| (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. |
43
Substitute Natural Gas
In 2011, Illinois enacted laws that required Nicor Gas and other large utilities in Illinois to elect to either sign contracts to purchase SNG from coal gasification plants to be constructed in Illinois or file rate cases with the Illinois Commission in 2012, 2014 and 2016.
On October 11, 2011, the Illinois Power Agency (IPA) approved the form of a draft 30-year contract for the purchase by Nicor Gas of 20 Bcf per year of SNG from a proposed plant beginning as early as 2018. The purchase price of the SNG that may be produced from this proposed coal gasification plant may significantly exceed market prices for natural gas and is expected to be dependent upon a variety of factors, including the developer’s financing, plant construction costs and volumes sold, which are currently not determinable. The Illinois law pertaining to this plant provides that the price paid for SNG purchased from the plant is to be considered prudent and not subject to review or disallowance by the Illinois Commission.
In November 2011, we filed a lawsuit against the IPA and the developer of this proposed plant contending that the draft contract approved by the IPA does not conform to certain requirements of the enabling legislation. The lawsuit is pending in circuit court in DuPage County, Illinois. In accordance with the enabling legislation, the draft contract approved by the IPA was submitted to the Illinois Commission for further approvals by that regulatory body. The final form of contract approved by the Illinois Commission modified the draft contract submitted by the IPA in various respects. We have appealed the Illinois Commission’s decision to the circuit court in DuPage County, Illinois. As a result of pending litigation challenging aspects of the IPA and Illinois Commission decisions regarding the contract terms, we have not yet signed a contract with the developer to purchase SNG from the proposed plant.
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 is insignificant.
Financial guarantees Tropic Equipment Leasing Inc. (TEL), a wholly owned subsidiary, holds our interest in Triton and has an obligation to restore to zero any deficit in its equity account for income tax purposes in the unlikely event that Triton is liquidated and a deficit balance remains. This obligation continues for the life of the Triton partnerships and any payment is effectively limited to the net assets of TEL, which were $16 million at December 31, 2013. We believe the likelihood of any such payment by TEL is remote. No liability has been recorded for this obligation.
Indemnities In certain instances, we have undertaken to indemnify current property owners and others against costs associated with the effects and/or remediation of contaminated sites for which we may be responsible under applicable federal or state environmental laws, generally with no limitation as to the amount. These indemnifications relate primarily to ongoing coal tar cleanup, as discussed in Environmental Matters. We believe that the likelihood of payment under our other environmental indemnifications is remote. No liability has been recorded for such indemnifications.
Regulatory Matters
In December 2012, Atlanta Gas Light filed a petition with the Georgia Commission for approval to resolve an imbalance of approximately 4.8 Bcf of natural gas related to Atlanta Gas Light’s use of retained storage assets to operationally balance the system for the benefit of the natural gas market. We believe that any costs associated with resolving the imbalance should be recoverable from Marketers. The resolution of this imbalance will be decided by the Georgia Commission and we are unable to predict the ultimate outcome and recovery.
Environmental Matters
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. See Note 3 for additional information.
We are involved in an investigation by the EPA regarding the applicable regulatory requirements for polychlorinated biphenyl in the Nicor Gas distribution system. While we are unable to predict the outcome of this matter or to reasonably estimate our potential exposure related thereto, if any, and have not recorded a liability associated with this contingency, the final disposition of this matter is not expected to have a material adverse impact on our liquidity or financial condition.
Litigation
We are involved in litigation arising in the normal course of business. Although in some cases we are unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require us to take charges against, or will result in reductions in, future earnings. 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, results of operations or cash flows.
44
PBR Proceeding Nicor Gas’ PBR plan for natural gas costs 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 Citizens Utility Board (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, the staff of the IAG and CUB requested refunds of $85 million, $255 million and $305 million, respectively.
In February 2012, we committed to a stipulation with the staff of the Illinois Commission for a resolution of the dispute through the crediting 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. 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 its 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 over a 12-month period. On July 1, 2013 we began refunding customers the full $72 million through our PGA mechanism. The amount refunded is based upon natural gas throughput and $29 million was refunded in 2013. The CUB is continuing to pursue its claim.
Other In addition to the matters set forth above, we are involved with legal or administrative proceedings before various courts and agencies with respect to general claims, taxes, environmental, gas cost prudence reviews and other matters. We are unable to determine the ultimate outcome of these other contingencies. We believe that these amounts are appropriately reflected in our financial statements, including the recording of appropriate liabilities when reasonably estimable.
Income Tax Expense
The relative split between current and deferred taxes is due to a variety of factors including true ups of prior year tax returns, and most importantly, the timing of our property-related deductions. Components of income tax expense in the Consolidated Statements of Income are shown in the following table.
The reconciliations between the statutory federal income tax rate of 35%, the effective rate and the related amount of income tax expense for the years ended December 31, in our Consolidated Statements of Income are presented in the following table.
Accumulated Deferred Income Tax Assets and Liabilities
We report some of our assets and liabilities differently for financial accounting purposes than we do for income tax purposes. We report the tax effects of the differences in those items as deferred income tax assets or liabilities in our Consolidated Statements of Financial Position. We measure the assets and liabilities using income tax rates that are currently in effect. We have provided a valuation allowance for some of these items that reduce our net deferred tax assets to amounts we believe are more likely than not to be realized in future periods. With respect to our continuing operations, we have net operating losses in various jurisdictions. Components that give rise to the net non-current accumulated deferred income tax liability are as follows.
| (1) | The total valuation allowance is $22 million, which is comprised of $3 million valuation allowance is due to the net operating losses of a former non-operating subsidiary that are not allowed in New Jersey and $19 million valuation allowance is related to our investment in Triton. In addition, $8 million of the total is classified as a valuation allowance against current deferred income tax assets. See Note 2 for more information regarding current deferred income taxes. |
A deferred income tax liability is not recorded on undistributed foreign earnings that are expected to be indefinitely reinvested offshore. We consider, among other factors, actual cash investments offshore as well as projected cash requirements in making this determination. Changes in our investment or repatriation plans or circumstances could result in a different deferred income tax liability. We had $80 million of such cash and short-term investments on our Consolidated Statements of Financial Position as of December 31, 2013 and 2012. As of March 31, 2014, in conjunction with the agreement to sell Tropical Shipping, we determined that we no longer have the intent to indefinitely reinvest Tropical Shipping’s cash and short and long-term investments offshore, and recognized income tax expense of $55 million in the first half of 2014 related to the cumulative foreign earnings for which no tax liabilities had previously been recorded. In connection with the sale, cash was repatriated immediately prior to closing the sale transaction. See Note 2 for more information about potential income taxes related to undistributed foreign earnings.
Tax Benefits
As of December 31, 2013 and December 31, 2012, we did not have a liability for unrecognized tax benefits. Based on current information, we do not anticipate that this will change materially in 2014. As of December 31, 2013, we did not have a liability recorded for payment of interest or penalties associated with uncertain tax positions nor did we have any such interest or penalties during 2013 or 2012.
We file a U.S. federal consolidated income tax return and various state income tax returns. We are no longer subject to income tax examinations by the Internal Revenue Service or in any state for years before 2008.
Our operating segments comprise revenue-generating components of our company for which we produce separate financial information internally that we regularly use to make operating decisions and assess performance. Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. We manage our businesses through four operating segments - distribution operations, retail operations, wholesale services, midstream operations and one non-operating segment, other.
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 regulated utilities, with rates determined by individual state regulatory commissions. These natural gas distribution utilities have similar economic and risk characteristics.
We are also involved in several related and complementary businesses. Our retail operations segment includes retail natural gas marketing to end-use customers primarily in Georgia as well as various businesses that market retail energy-related products and services to residential and small business customers in Illinois. Additionally, our retail operations segment provides 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, as well as for non-affiliated companies, natural gas storage arbitrage and related activities. Our midstream operations segment includes our non-utility storage and pipeline operations, including the development and operation of high-deliverability natural gas storage assets.
On April 4, 2014 we entered into a definitive agreement to sell 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 Consolidated Statements of Financial Position, and the financial results of these businesses are reflected as discontinued operations on the 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 is not a part of the sale and has been reclassified into our other segment. See Note 15 for additional information.
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 our segments and 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 and debt 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 years ended December 31, 2013, 2012 and 2011 are shown in the following tables.
| 2013 | ||||||||||||||||||||||||
| In millions | Distribution operations | Retail operations | Wholesale services | Midstream operations | Other and intercompany eliminations (4) | Consolidated | ||||||||||||||||||
| Operating revenues from external parties | $ | 3,275 | $ | 858 | $ | 45 | $ | 74 | $ | - | $ | 4,252 | ||||||||||||
Intercompany revenues (1) | 182 | - | 13 | - | (195 | ) | - | |||||||||||||||||
| Total operating revenues | 3,457 | 858 | 58 | 74 | (195 | ) | 4,252 | |||||||||||||||||
| Operating expenses | ||||||||||||||||||||||||
| Cost of goods sold | 1,687 | 564 | 21 | 33 | (195 | ) | 2,110 | |||||||||||||||||
| Operation and maintenance | 690 | 132 | 48 | 24 | (5 | ) | 889 | |||||||||||||||||
| Depreciation and amortization | 346 | 22 | 1 | 17 | 13 | 399 | ||||||||||||||||||
| Taxes other than income taxes | 167 | 3 | 3 | 5 | 9 | 187 | ||||||||||||||||||
| Total operating expenses | 2,890 | 721 | 73 | 79 | (178 | ) | 3,585 | |||||||||||||||||
| Gain on disposition of assets | - | - | 11 | - | - | 11 | ||||||||||||||||||
| Operating income (loss) | 567 | 137 | (4 | ) | (5 | ) | (17 | ) | 678 | |||||||||||||||
| Other income (expense) | 15 | - | - | (5 | ) | 7 | 17 | |||||||||||||||||
| EBIT | $ | 582 | $ | 137 | $ | (4 | ) | $ | (10 | ) | $ | (10 | ) | $ | 695 | |||||||||
Identifiable and total assets (3) | $ | 11,727 | $ | 694 | $ | 1,166 | $ | 713 | $ | 73 | $ | 14,373 | ||||||||||||
| Capital expenditures | $ | 684 | $ | 9 | $ | 2 | $ | 12 | $ | 24 | $ | 731 | ||||||||||||
| 2012 | ||||||||||||||||||||||||
| In millions | Distribution operations | Retail operations | Wholesale services | Midstream operations | Other and intercompany eliminations (4) | Consolidated | ||||||||||||||||||
| Operating revenues from external parties | $ | 2,710 | $ | 733 | $ | 58 | $ | 78 | $ | 1 | $ | 3,580 | ||||||||||||
Intercompany revenues (1) | 167 | 2 | 30 | - | (199 | ) | - | |||||||||||||||||
| Total operating revenues | 2,877 | 735 | 88 | 78 | (198 | ) | 3,580 | |||||||||||||||||
| Operating expenses | ||||||||||||||||||||||||
| Cost of goods sold | 1,221 | 488 | 38 | 32 | (196 | ) | 1,583 | |||||||||||||||||
| Operation and maintenance | 642 | 114 | 48 | 19 | (8 | ) | 815 | |||||||||||||||||
| Depreciation and amortization | 351 | 13 | 2 | 14 | 13 | 393 | ||||||||||||||||||
Nicor merger expenses (2) | - | - | - | - | 20 | 20 | ||||||||||||||||||
| Taxes other than income taxes | 140 | 4 | 4 | 5 | 6 | 159 | ||||||||||||||||||
| Total operating expenses | 2,354 | 619 | 92 | 70 | (165 | ) | 2,970 | |||||||||||||||||
| Operating income (loss) | 523 | 116 | (4 | ) | 8 | (33 | ) | 610 | ||||||||||||||||
| Other income | 9 | - | 1 | 2 | 12 | 24 | ||||||||||||||||||
| EBIT | $ | 532 | $ | 116 | $ | (3 | ) | $ | 10 | $ | (21 | ) | $ | 634 | ||||||||||
Identifiable and total assets (3) | $ | 11,320 | $ | 511 | $ | 1,218 | $ | 720 | $ | 81 | $ | 13,850 | ||||||||||||
| Capital expenditures | $ | 649 | $ | 8 | $ | 3 | $ | 62 | $ | 53 | $ | 775 | ||||||||||||
| (1) |
| (2) | Transaction expenses associated with the Nicor merger are shown separately to better compare year-over-year results. |
| (3) | Identifiable assets are those used in each segment’s operations and exclude assets held for sale. |
| (4) | Our other segment’s assets consist primarily of cash and cash equivalents, PP&E and the effect of intercompany eliminations. Our other segment now also includes our investment in Triton, which was part of our cargo shipping segment that is classified as discontinued operations. For more information see Note 15. |
The variance in our quarterly earnings is primarily the result of the seasonal nature of the distribution of natural gas to customers, the volatility within our wholesale services segment. During the Heating Season, natural gas usage and operating revenues are generally higher at our distribution operations and retail operations segments as more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather. However, our base operating expenses, excluding cost of goods sold, interest expense and certain incentive compensation costs, are incurred relatively uniformly over any given year. Thus, our operating results can vary significantly from quarter to quarter as a result of seasonality. The effects of seasonality on our quarterly earnings have been impacted by our Nicor merger as we have more customers within our distribution operations segment that are impacted by weather.
Our 2013 operating revenues and operating income were higher than 2012. This was primarily as a result of colder-than-normal weather in 2013 compared to significantly warmer-than-normal weather in 2012. The increases in our operating revenues and operating income in 2012 compared to 2011 are primarily the result of the Nicor merger, which closed on December 9, 2011. See Note 2 and Note 13 for the impact the Nicor merger had on our segments, financial position and results of operations. Our quarterly financial data for 2013, 2012 and 2011 are summarized below.
| In millions, except per share amounts | March 31 | June 30 | September 30 | December 31 | ||||||||||||
| 2013 | ||||||||||||||||
| Operating revenues | $ | 1,622 | $ | 816 | $ | 586 | $ | 1,228 | ||||||||
| Operating income | 298 | 123 | 81 | 176 | ||||||||||||
| EBIT | 303 | 130 | 88 | 174 | ||||||||||||
| Net income from continuing operations | 163 | 51 | 27 | 85 | ||||||||||||
| Net income (loss) from discontinued operations, net of tax | 1 | (1 | ) | 1 | 4 | |||||||||||
| Net income attributable to AGL Resources Inc. | 153 | 50 | 27 | 78 | ||||||||||||
| Basic earnings per common share attributable to AGL Resources Inc. common shareholders | 1.31 | 0.42 | 0.23 | 0.65 | ||||||||||||
| Diluted earnings per common share attributable to AGL Resources Inc. common shareholders | 1.30 | 0.42 | 0.23 | 0.65 | ||||||||||||
| 2012 | ||||||||||||||||
| Operating revenues | $ | 1,320 | $ | 606 | $ | 531 | $ | 1,123 | ||||||||
| Operating income | 263 | 95 | 57 | 195 | ||||||||||||
| EBIT | 267 | 104 | 62 | 201 | ||||||||||||
| Net income from continuing operations | 140 | 37 | 9 | 99 | ||||||||||||
| Net income (loss) from discontinued operations, net of tax | (1 | ) | (2 | ) | - | 4 | ||||||||||
| Net income attributable to AGL Resources Inc. | 131 | 36 | 9 | 95 | ||||||||||||
| Basic earnings per common share attributable to AGL Resources Inc. common shareholders | 1.12 | 0.30 | 0.08 | 0.80 | ||||||||||||
| Diluted earnings per common share attributable to AGL Resources Inc. common shareholders | 1.12 | 0.30 | 0.08 | 0.80 | ||||||||||||
| 2011 | ||||||||||||||||
| Operating revenues | $ | 878 | $ | 375 | $ | 295 | $ | 771 | ||||||||
| Operating income | 238 | 60 | 24 | 118 | ||||||||||||
| EBIT | 239 | 62 | 25 | 121 | ||||||||||||
| Net income (loss) from continuing operations | 134 | 19 | (4 | ) | 37 | |||||||||||
Net income (loss) from discontinued operations, net of tax (1) | - | - | - | - | ||||||||||||
| Net income (loss) attributable to AGL Resources Inc. | 124 | 18 | (3 | ) | 33 | |||||||||||
| Basic earnings (loss) per common share attributable to AGL Resources Inc. common shareholders | 1.60 | 0.23 | (0.04 | ) | 0.37 | |||||||||||
| Diluted earnings (loss) per common share attributable to AGL Resources Inc. common shareholders | 1.59 | 0.23 | (0.04 | ) | 0.37 | |||||||||||
| (1) | The discontinued operations were acquired on December 9, 2011 as part of the Nicor merger. |
Our basic and diluted earnings per common share are calculated based on the weighted daily average number of common shares and common share equivalents outstanding during the quarter. Those totals differ from the basic and diluted earnings per common share attributable to AGL Resources Inc. common shareholders shown in the Consolidated Statements of Income, which are based on the weighted average number of common shares and common share equivalents outstanding during the entire year.
Our financial statements, including footnotes 1, 2, 4, 6, 7, 10, 11, 12, 13 and 14 have been updated to recast our segment information and to give effect to the classification of Tropical Shipping as discontinued operations for all periods presented.
On April 4, 2014, we entered into a definitive agreement to sell Tropical Shipping. We received all regulatory approvals and our agreement to sell Tropical Shipping closed on August 31, 2014. After-tax cash proceeds and distributions from the transaction were $220 million, subject to certain defined post-closing adjustments, and we recorded $29 million of income tax expense upon closing the transaction.
In the first quarter of 2014, we recognized income tax expense of $31 million on our Consolidated Statements of Income related to the cumulative earnings of our foreign subsidiaries for which income taxes had not previously been recorded. We also recorded a goodwill impairment charge of $19 million, for which there is no income tax benefit, during the first quarter of 2014 based upon the negotiated sale price. Additionally, we suspended depreciation and amortization of the Tropical Shipping assets for which we recognized a $4 million pre-tax loss in the second quarter of 2014 to reflect the lower purchase price at closing. The assets and liabilities of Tropical Shipping classified as held for sale on the Consolidated Statements of Financial Position are as follows:
| December 31, | ||||||||
| In millions | 2013 | 2012 | ||||||
| Current assets | ||||||||
| Cash and cash equivalents | $ | 24 | $ | 23 | ||||
| Short-term investments | 1 | 2 | ||||||
| Receivables | 36 | 34 | ||||||
| Inventories | 9 | 9 | ||||||
| Other | 1 | 8 | ||||||
| Total current assets | 71 | 76 | ||||||
| Long-term assets and other deferred debits | ||||||||
| Property, plant and equipment, net | 124 | 130 | ||||||
| Goodwill | 61 | 61 | ||||||
| Intangible assets | 19 | 20 | ||||||
| Other | 8 | 4 | ||||||
| Total long-term assets and other deferred debits | 212 | 215 | ||||||
| Total assets held for sale | $ | 283 | $ | 291 | ||||
| Current liabilities | ||||||||
| Accrued expenses | $ | 7 | $ | 7 | ||||
| Other accounts payable - trade | 11 | 8 | ||||||
| Other | 22 | 24 | ||||||
| Total current liabilities | 40 | 39 | ||||||
| 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 Consolidated Statements of Income are as follows:
| December 31, | ||||||||||||
| In millions | 2013 | 2012 | 2011 | |||||||||
| Operating revenues | $ | 365 | $ | 342 | $ | 19 | ||||||
| Operating expenses | ||||||||||||
| Cost of goods sold | 222 | 208 | 12 | |||||||||
| Operation and maintenance | 110 | 106 | 6 | |||||||||
| Depreciation and amortization | 19 | 22 | 1 | |||||||||
| Taxes other than income taxes | 6 | 6 | - | |||||||||
| Total operating expenses | 357 | 342 | 19 | |||||||||
| Operating income | 8 | - | - | |||||||||
| Income before income taxes | 8 | - | - | |||||||||
| Income tax expense (benefit) | 3 | (1 | ) | - | ||||||||
| Income from discontinued operations, net of tax | $ | 5 | $ | 1 | $ | - | ||||||
Cash and cash equivalents As of December 31, 2013 and 2012, we had $31 million and $25 million of cash and short and long-term investments, respectively, in our Consolidated Statements of Financial Position held by Tropical Shipping that were included in the sale.
Property, plant and equipment A summary of Tropical Shipping’s PP&E as of December 31, 2013 and 2012 is provided in the following table.
| In millions | 2013 | 2012 | ||||||
| Shipping vessels and containers | 148 | 145 | ||||||
| Construction work in progress | 4 | 1 | ||||||
| Total PP&E, gross | 152 | 146 | ||||||
| Less accumulated depreciation | 28 | 16 | ||||||
| Total PP&E, net | $ | 124 | $ | 130 | ||||
Goodwill Changes in the amount of Tropical Shipping’s goodwill for the twelve months ended December 31, 2013 and 2012 are provided below.
In millions | ||||
| Goodwill - December 31, 2011 | $ | 77 | ||
| Adjustments to initial Nicor purchase price allocation and other | (16 | ) | ||
| Goodwill - December 31, 2012 | 61 | |||
| Goodwill - December 31, 2013 | $ | 61 | ||
Intangible Assets A summary of the intangible assets of Tropical Shipping, as of December 31, 2013 and 2012, is provided in the following table.
| Weighted average | December 31, 2013 | December 31, 2012 | ||||||||||||||||||||||||||
In millions | amortization period (in years) | Gross | Accumulated amortization | Net | Gross | Accumulated amortization | Net | |||||||||||||||||||||
| Customer relationships | 18 | $ | 6 | $ | - | $ | 6 | $ | 6 | $ | - | $ | 6 | |||||||||||||||
| Trade names | 15 | 15 | (2 | ) | 13 | 15 | (1 | ) | 14 | |||||||||||||||||||
| Total | $ | 21 | $ | (2 | ) | $ | 19 | $ | 21 | $ | (1 | ) | $ | 20 | ||||||||||||||
Amortization expense was $1 million in 2013, $1 million in 2012 and $0 in 2011.
Fair value of money market funds At December 31, 2013 and 2012, the fair value of our money market funds, which were held by Tropical Shipping, were as follows:
| In millions | 2013 | 2012 | ||||||
Money market funds (1) | $ | 48 | $ | 66 | ||||
| (1) | Carried at fair value and classified as Level 1 within the fair value hierarchy. |
Revenues Revenues are recognized at the time vessels depart from port. Insurance premiums are recognized when the vessel carrying the insured cargo reaches its port of destination and the insured cargo is released to the consignee. The portion of premiums not earned at the end of the year is recorded as unearned premiums.
Repair and maintenance expense We record expense for repair and maintenance costs as incurred. This includes expenses for planned major maintenance, such as dry docking the vessels.
Employee Savings Plan Benefits Under our defined contribution retirement benefit plans, our matching contributions to participant accounts of Tropical Shipping were $2 million in each of 2013 and 2012. There were no such matching contributions in 2011.
Employee Stock Purchase Plan (ESPP) ESPP information related to the employees of Tropical Shipping follows.
| 2013 | 2012 | 2011 | ||||||||||
| Shares purchased on the open market | 5,609 | 4,543 | - | |||||||||
| Average per-share purchase price | $ | 42.96 | $ | 38.96 | - | |||||||
| Total purchase price discount | $ | 35,928 | $ | 26,423 | - | |||||||
(a) Documents Filed as Part of This Report.
(1) Financial Statements Included in Item 8 are the following: |
| · | Report of Independent Registered Public Accounting Firm |
| · | Management’s Report on Internal Control Over Financial Reporting |
| · | Consolidated Statements of Financial Position as of December 31, 2013 and 2012 |
| · | Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011 |
| · | Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011 |
| · | Consolidated Statements of Equity for the years ended December 31, 2013, 2012 and 2011 |
| · | Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011 |
| · | Notes to Consolidated Financial Statements |
(2) Financial Statement Schedules
Financial Statement Schedule II. Valuation and Qualifying Accounts - Allowance for Uncollectible Accounts and Income Tax Valuations for Each of the Three Years in the Period Ended December 31, 2013. Schedules other than those referred to above are omitted and are not applicable or not required, or the required information is shown in the financial statements or notes thereto.
(b) There are no changes being made to Item 15(b) from the 2013 Form 10-K
AGL Resources Inc. and Subsidiaries
VALUATION AND QUALIFYING ACCOUNTS - FOR EACH OF THE THREE YEARS IN THE PERIOD ENDED DECEMBER 31, 2013.