Notes to Consolidated Financial Statements

Note 1 Accounting Policies and Methods of Application


General


AGL Resources Inc. is an energy services holding company that conducts substantially all 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. We have prepared the accompanying consolidated financial statements under the rules of the SEC.

Basis of Presentation

Our consolidated financial statements as of and for the period ended December 31, 2009, include our accounts, the accounts of our majority-owned and controlled subsidiaries and the accounts of variable interest entities for which we are the primary beneficiary. This means that our accounts are combined with the subsidiaries’ accounts. We have eliminated any intercompany profits and transactions in consolidation; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process. Certain amounts from prior periods have been reclassified and revised to conform to the current period presentation.

Cash and Cash Equivalents

Our cash and cash equivalents consist primarily of cash on deposit, money market accounts and certificates of deposit with original maturities of three months or less.

Receivables and Allowance for Uncollectible Accounts

Our receivables consist of natural gas sales and transportation services billed to residential, commercial, industrial and other customers.We bill customers monthly, and 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. On certain other receivables where 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 net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be different. Circumstances that could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. We write-off our customers’ accounts once we deem them to be uncollectible.

Inventories

For our distribution operations subsidiaries, we record natural gas stored underground at WACOG. For Sequent and SouthStar, we account for natural gas inventory at the lower of WACOG or market price.

Sequent and SouthStar evaluate the 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, adjustments are recorded to reduce the weighted average cost of the natural gas inventory to market price. Consequently, as a result of declining natural gas prices, Sequent recorded LOCOM adjustments against cost of gas to reduce the value of its inventories to market value of $8 million in 2009, $40 million in 2008 and $4 million in 2007. SouthStar recorded LOCOM adjustments of $6 million in 2009 and $24 million in 2008, but was not required to make LOCOM adjustments in 2007.

In Georgia’s competitive environment, Marketers including SouthStar, our marketing subsidiary, began selling natural gas in 1998 to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation that provides for this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. Atlanta Gas Light assigns, on a monthly basis, the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory.

Energy Marketing Receivables and Payables

Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements, which enable wholesale services to net receivables and payables by counterparty. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. The amounts due from or owed to wholesale services’ counterparties are netted and recorded on our consolidated statements of financial position as energy marketing receivables and energy marketing payables.
Our wholesale services segment has some trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. No collateral has been posted under such provisions since our credit ratings have always exceeded the minimum requirements. As of December 31, 2009 and December 31, 2008, the collateral that wholesale services would have been required to post would not have had a material impact to our consolidated results of operations, cash flows or financial condition. However, if such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be impaired.

Property, Plant and Equipment

A summary of our PP&E by classification as of December 31, 2009 and 2008 is provided in the following table.

In millions
2009
2008
Transmission and distribution
$ 4,579
$ 4,344
Storage
290
290
Other
725
543
Construction work in progress
345
323
Total gross PP&E
5,939
5,500
Accumulated depreciation
(1,793)
(1,684)
Total net PP&E
$ 4,146
$ 3,816


Distribution Operations PP&E expenditures consist of property and equipment that is in use, being held for future use and under construction. We report PP&E at its original cost, which includes:

  • material and labor
  • contractor costs
  • construction overhead costs
  • an allowance for funds used during construction (AFUDC) 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


We charge property retired or otherwise disposed of to accumulated depreciation since such costs are recovered in rates.

Retail Energy Operations, Wholesale Services, Energy Investments and Corporate PP&E expenditures include property that is in use and under construction, and we report it at cost. We record a gain or loss for retired or otherwise disposed-of property. Natural gas in storage at Jefferson Island that is retained as pad gas (volumes of non-working natural gas used to maintain the operational integrity of the cavern facility) is classified as nondepreciable property, plant and equipment and is valued at cost.

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. The composite straight-line depreciation rates for depreciable property — excluding transportation equipment for Atlanta Gas Light, Virginia Natural Gas and Chattanooga Gas and the composite, straight-line rates for Elizabethtown Gas, Florida City Gas and Elkton Gas are listed in the following table. We depreciate transportation equipment on a straight-line basis over a period of 5 to 10 years. We compute depreciation expense for other segments on a straight-line basis up to 35 years based on the useful life of the asset.

  2009 2008 2007
Atlanta Gas Light 2.5% 2.5% 2.5%
Chattanooga Gas 3.4% 3.3% 3.3%
Elizabethtown Gas 3.1% 3.1% 3.0%
Elkton Gas 2.1% 2.9% 4.0%
Florida City Gas 3.9% 3.9% 3.7%
Virginia Natural Gas 2.6% 2.7% 2.5%


AFUDC and Capitalized Interest


Four of our utilities are authorized by applicable state regulatory agencies or legislatures to record the cost of debt and equity funds as part of the cost of construction projects in our consolidated statements of financial position and as AFUDC of $13 million in 2009, $8 million in 2008 and $4 million in 2007 within the consolidated statements of income. The capital expenditures of our two other utilities do not qualify for AFUDC treatment. More information on our authorized AFUDC rates is provided in the following table.

 
Authorized AFUDC rate
Atlanta Gas Light
8.53%
Chattanooga Gas
7.89%
Elizabethtown Gas(1)
0.41%
Virginia Natural Gas(2)
9.24%

(1) Variable rate as of December 31, 2009, and is determined by FERC method of AFUDC accounting.
(2) Approved only for Hampton Roads construction project.


Within our energy investments operating segment, we have recorded capitalized interest as part of the cost of the Golden Triangle Storage facilities construction project in our consolidated statements of financial position in the amount of $3 million as of December 31, 2009 and $2 million as of December 31, 2008. The capitalized interest is also reported within interest expense in our consolidated statements of income. Goodwill Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in business combinations in accordance with the authoritative guidance. We do not amortize goodwill but annually test it for impairment or when indication of potential impairment exists. These indicators would include 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 among other factors. We test goodwill impairment utilizing a fair value approach at a reporting unit level which generally equates to our operating segments as discussed in Note 9 “Segment Information.” We have included $418 million of goodwill in our consolidated statement of financial position as of December 31, 2009 and 2008.

Our impairment analysis for the years ended December 31, 2009 and 2008 of our identifiable net assets acquired in business combinations indicated that the fair value substantially exceeded the carrying value. As a result, we did not recognize any impairment charges.

Fair value measurements

The carrying values of cash and cash equivalents, receivables, derivative financial assets and liabilities, accounts payable, pension and postretirement plan assets and liabilities, other current liabilities and accrued interest approximate fair value. See Notes 2, 3 and 6 for additional fair value disclosures.

As defined in authoritative guidance related to fair value measurements and disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor 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 are able to 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 are available 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 financial instruments with exchangetraded derivatives.

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 industrystandard 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 market place. As we aggregate our disclosures by counterparty, the underlying transactions for a given counterparty may be a combination of exchange-traded derivatives and values based on other sources. Instruments in this category include shorter tenor exchange-traded and non-exchangetraded derivatives such as OTC forwards and options.

Level 3

Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. We do not have any material assets or liabilities classified as level 3, except for retirement plan assets as described in Note 3.

In April 2009, additional authoritative guidance related to fair value measurements and disclosures established a two-step process to determine if the market for a financial asset is inactive and a transaction is not distressed. Currently, this authoritative guidance does not affect us, as our derivative financial instruments are traded in active markets.

Taxes

The reporting of our assets and liabilities for financial accounting purposes differs from the reporting for income tax purposes. The principal differences between net income and taxable income relate 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 differences in those items as deferred income tax assets or liabilities in our consolidated statements of financial position in accordance with authoritative guidance related to income taxes. Investment tax credits of approximately $13 million previously deducted for income tax purposes for Atlanta Gas Light, Elizabethtown Gas, Florida City Gas and Elkton Gas have been deferred for financial accounting purposes and are being amortized as credits to income over the estimated lives of the related properties in accordance with regulatory requirements.

We do not collect income taxes from our customers on behalf of governmental authorities. We collect and remit various taxes on behalf of various governmental authorities. We record these amounts in our consolidated statements of financial position except taxes in the state of Florida which we are required to include in revenues and operating expenses. These Florida related taxes are not material for any periods presented.

Revenues

Distribution operations We record revenues when 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, in July 1998, Atlanta Gas Light began billing Marketers in equal monthly installments for each residential, commercial and industrial customer’s distribution costs.

As required by the Georgia Commission, effective February 1, 2001, Atlanta Gas Light implemented a seasonal rate design for the calculation of each residential customer’s annual straight-fixedvariable (SFV) capacity charge, which is billed to Marketers and reflects the historic volumetric usage pattern for the entire residential class. Generally, this change results in residential customers being billed by Marketers for a higher capacity charge in the winter months and a lower charge in the summer months. This requirement has an operating cash flow impact but does not change revenue recognition. As a result, Atlanta Gas Light continues to recognize its residential SFV capacity revenues for financial reporting purposes in equal monthly installments.

The Elizabethtown Gas, Virginia Natural Gas, Florida City Gas, Chattanooga Gas and Elkton Gas rate structures include volumetric rate designs that allow recovery of costs through 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. In addition, revenues are recorded for estimated deliveries of gas not yet billed to these customers, from the last meter reading 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 all wholesale customers, revenues are based on actual deliveries to the end of the period.

The tariffs for Elizabethtown Gas, Virginia Natural Gas and Chattanooga Gas containWNA’s that partially mitigate the impact of unusually cold or warm weather on customer billings and operating margin. The WNA’s purpose is to reduce 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. Additionally, the tariff for Virginia Natural Gas contains a revenue normalization mechanism that mitigates the impact of conservation and declining customer usage.

Retail energy operations We record retail energy operations’ revenues when services are provided to customers. Revenues from 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 recorded 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. These are included in the consolidated statements of financial position as unbilled revenue. For other commercial and industrial customers and all wholesale customers, revenues are based on actual deliveries to the end of the period.

Wholesale services We record wholesale services’ revenues when services are provided to customers. Profits from sales between segments are eliminated in the corporate 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.

Energy investments We record operating revenues at Jefferson Island in the period in which actual volumes are transported and storage services are provided. The majority of our storage services are covered under medium to long-term contracts at fixed marketbased rates.

We record operating revenues at AGL Networks from leases of dark fiber pursuant to indefeasible rights-of-use (IRU) agreements as services are provided. Dark fiber IRU agreements generally require the customer to make a down payment upon execution of the agreement; however in some cases AGL Networks receives up to the entire lease payment at the inception of the lease and recognizes ratably over the lease term. AGL Networks had deferred revenue in our consolidated statements of financial position of $33 million at December 31, 2009 and December 31, 2008. In addition, AGL Networks recognizes sales revenues upon the execution of certain sales-type agreements for dark fiber when the agreements provide for the transfer of legal title to the dark fiber to the customer at the end of the agreement’s term. This sales-type accounting treatment is in accordance with authoritative guidance related to leases and revenue recognition, which provides that such transactions meet the criteria for sales-type lease accounting if the agreement obligates the lessor to convey ownership of the underlying asset to the lessee by the end of the lease term.

Cost of Gas

Excluding Atlanta Gas Light, we charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the state regulatory agencies. Under the these mechanisms, we defer (that is, include as a current asset or liability in the consolidated statements of financial position and exclude from the statements of consolidated income) the difference between the actual cost of gas and what is collected from or billed to customers in a given period. The deferred amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate.

Our retail energy operations customers are charged for natural gas consumed. We also include within our cost of gas amounts for fuel and lost and unaccounted for gas, adjustments to reduce the value of our inventories to market value and for gains and losses associated with derivatives.

Comprehensive Income

Our comprehensive income includes net income and net income attributable to AGL Resources Inc. plus OCI, which includes other gains and losses affecting shareholders’ equity that GAAP excludes from net income and net income attributable to AGL Resources Inc. Such items consist primarily of unrealized gains and losses on certain derivatives designated as cash flow hedges and overfunded or unfunded pension obligation adjustments.

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources Inc. common shareholders by dividing our income attributable to AGL Resources Inc. by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. common shareholders reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. common shareholders that could occur when potentially dilutive common shares are added to common shares outstanding.

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

In millions
2009
2008
2007
Denominator for basic earnings per common share attributable to AGL Resources Inc. common shareholders(1) 
76.8
76.3
77.1
Assumed exercise of potential common shares 
0.3
0.3
0.3
Denominator for diluted earnings per common share attributable to AGL Resources Inc. common shareholders 
77.1
76.6
77.4

(1)Daily weighted average shares outstanding.

The following table contains the weighted average shares attributable to outstanding stock options that were excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. because their effect would have been anti-dilutive, as the exercise prices were greater than the average market price:

In millions
2009
December 31,
2008
2007 (1)
Twelve months ended
2.0
1.6
0.0

(1) 0.0 values represent amounts less than 0.1 million.

The increase in the number of shares that were excluded from the computation is the result of a decline in the average market value of our common shares for the years ended December 31, 2009 and 2008 as compared to December 31, 2007. While the market value of our common shares rose during 2009, the average share price for 2009 was lower than 2008 and 2007.

Regulatory Assets and Liabilities

We have recorded regulatory assets and liabilities in our consolidated statements of financial position in accordance with authoritative guidance related to regulated operations. Our regulatory assets and liabilities, and associated liabilities for our unrecovered regulatory infrastructure program costs, unrecovered ERC and the derivative financial instrument assets and liabilities for Elizabethtown Gas’ hedging program, are summarized in the following table.

 
December 31,
In millions
2009
2008
Regulatory assets
Unrecovered regulatory infrastructure program costs 
$266
$237
Unrecovered ERC(1)
172
143
Unrecovered seasonal rates
11
11
Unrecovered postretirement benefit costs
10
11
Unrecovered natural gas costs
19
Other
27
30
Total regulatory assets
486
451
Associated assets
Derivative financial instruments
11
23
Total regulatory and associated assets
$497
$474
Regulatory liabilities
Accumulated removal costs
$183
$178
Deferred natural gas costs
30
25
Regulatory tax liability
17
19
Unamortized investment tax credit
13
14
Derivative financial instruments
11
23
Other
17
22
Total regulatory liabilities
271
281
Associated liabilities
Regulatory infrastructure program costs
210
189
ERC(1)
133
96
Total associated liabilities
343
285
Total regulatory and associated liabilities 
$614
$566

(1) For a discussion of ERC, see Note 7.

Our regulatory assets are recoverable through either rate riders or base rates specifically authorized by a state regulatory commission. 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 our regulatory assets are subject to review by the respective state regulatory commission during any future rate proceedings. 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, the regulatory liabilities would not be written-off but would continue to be recorded as liabilities but not as regulatory liabilities. Although the natural gas distribution industry is becoming increasingly competitive, 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. The regulatory liabilities 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 in setting rates.

All the regulatory assets included in the preceding table are included in base rates except for the unrecovered regulatory infrastructure program costs, unrecovered ERC and deferred natural gas costs, which are recovered through specific rate riders on a dollar for dollar basis. The rate riders that authorize recovery of unrecovered regulatory infrastructure program costs and the deferred natural gas costs include both a recovery of costs and a return on investment during the recovery period.

We have two rate riders that authorize the recovery of unrecovered ERC. The ERC rate rider for Atlanta Gas Light only allows for recovery of the costs incurred and the recovery period occurs over the five years after the expense is incurred. ERC associated with the investigation and remediation of Elizabethtown Gas remediation sites located in the state of New Jersey are recovered under a remediation adjustment clause and include the carrying cost on unrecovered amounts not currently in rates.

Elizabethtown Gas’ derivative financial instrument asset and liability reflect unrealized losses or gains that will be recovered from or passed to rate payers through the recovery of its natural gas costs on a dollar for dollar basis, once the losses or gains are realized. For more information on Elizabethtown Gas’ derivative financial instruments, see Note 2.

Unrecovered postretirement benefit costs are recoverable through base rates over the next 4 to 23 years based on the remaining recovery period as designated by the applicable state regulatory commissions. Unrecovered seasonal rates 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. The unrecovered amounts are fully recoverable through base rates within one year.

Regulatory Infrastructure Programs

Atlanta Gas Light was ordered by the Georgia Commission (through a joint stipulation and a subsequent settlement agreement between Atlanta Gas Light and the Georgia Commission) to undertake a pipeline replacement program that would replace all bare steel and cast iron pipe in its system by December 2013. If Atlanta Gas Light does not perform in accordance with this order, it will be assessed certain nonperformance penalties. These replacements are on schedule.

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-fixedvariable rates and a pipeline replacement revenue rider. The regulatory asset has two components:

  • the costs incurred to date that have not yet been recovered through the rate rider
  • the future expected costs to be recovered through the rate rider


Atlanta Gas Light has recorded a long-term regulatory asset of $223 million, which represents the expected future collection of both expenditures already incurred and expected future capital expenditures to be incurred through the remainder of the program. Atlanta Gas Light has also recorded a current asset of $43 million, which represents the expected amount to be collected from customers over the next 12 months. The amounts recovered from the pipeline replacement revenue rider during the last three years were:

  • $41 million in 2009
  • $30 million in 2008
  • $27 million in 2007

As of December 31, 2009, Atlanta Gas Light had recorded a current liability of $55 million representing expected program expenditures for the next 12 months and a long-term liability of $155 million, representing expected program expenditures starting in 2011 through the end of the program in 2013.

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.

In June 2009, Atlanta Gas Light filed a request for a Strategic Infrastructure Development and Enhancement (STRIDE) program with the Georgia Commission to upgrade its distribution system and liquefied natural gas facilities to improve system reliability and create a platform to meet operational flexibility needs and forecasted growth. Under the program, Atlanta Gas Light would be required to file a ten-year infrastructure plan every three years for review and approval by the Georgia Commission. The program merges with Atlanta Gas Light’s existing pipeline replacement program. In October 2009, the Georgia Commission approved the initial three years of the STRIDE program, estimated at approximately $176 million. The program is subject to review and modification by the Georgia Commission every three years.

In April 2009, the New Jersey BPU approved an accelerated $60 million enhanced infrastructure program for Elizabethtown Gas, which began in 2009 and is scheduled to be completed in 2011. This program was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. A regulatory cost recovery mechanism will be established with estimated rates put into effect at the beginning of each year. At the end of the program the regulatory cost recovery mechanism will be trued-up and any remaining costs not previously collected will be included in base rates.

Treasury Shares

Our Board of Directors has authorized us to purchase up to 8 million treasury shares through our repurchase plans. These plans are 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 these plans may be made in the open market or in private transactions at times and in amounts that we deem appropriate. There is no guarantee as to the exact number of shares that we will purchase, and we can terminate or limit the program at any time.We will hold the purchased shares as treasury shares and account for them using the cost method. As of December 31, 2009, we had 5 million remaining authorized shares available for purchase. In 2007, we spent $80 million to purchase approximately 2 million treasury shares at a weighted average price per share of $39.56. We did not make any treasury share purchases in 2008 or 2009.

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 are restricted by laws in the states where we do business. In certain cases, our ability to pay dividends to our common shareholders is limited by the following:

  • our ability to pay our debts as they become due in the usual course of business, satisfy our obligations under certain financing agreements, including debt-to-capitalization covenants
  • our total assets are less than our total liabilities, and
  • our ability to satisfy our obligations to any preferred shareholders


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 of contingent assets and liabilities.We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, and we evaluate our estimates on an ongoing basis. Each of our estimates 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 include our pipeline replacement program accruals, environmental liability accruals, uncollectible accounts and other allowance for contingencies, pension and postretirement obligations, derivative and hedging activities and provision for income taxes. Our actual results could differ from our estimates.

Subsequent Events

In May 2009, the FASB established guidance for and disclosure of events that occur after the statements of financial position date, but before financial statements are issued, or are available to be issued. This guidance should now be applied by management to the accounting for and disclosure of subsequent events, but does not apply to subsequent events or transactions that are within the scope of other applicable GAAP that provide different guidance. In accordance with the guidance, we evaluated subsequent events until the time that our financial statements were issued.