Piedmont Natural Gas Company, Inc. is an energy services company primarily engaged in the distribution of natural gas to residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation. Our utility operations are regulated by three state regulatory commissions. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries. For further information on regulatory matters, see Note 2 to the consolidated financial statements.

The consolidated financial statements reflect the accounts of Piedmont and its wholly owned subsidiaries whose financial statements are prepared for the same reporting period as Piedmont using consistent accounting policies. Investments in non-utility activities, or joint ventures, are accounted for under the equity method as we do not have controlling voting interests or otherwise exercise control over the management of such companies. Our ownership interest in each entity is recorded in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Consolidated Balance Sheets at cost plus post-acquisition contributions and earnings based on our share in each of the joint ventures less any distributions received from the joint venture, and if applicable, less any impairment in value of the investment. Earnings or losses from equity method investments are recorded in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. For further information on equity method investments, see Note 12 to the consolidated financial statements. Revenues and expenses of all other non-utility activities are included in “Non-operating income” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation.

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. There are no subsequent events that had a material impact on our financial position, results of operations or cash flows. For further information, see Note 15 to the consolidated financial statements.

The consolidated financial statements of Piedmont have been prepared in conformity with generally accepted accounting principles in the United States of America (GAAP) and under the rules of the Securities and Exchange Commission (SEC). In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets and liabilities, disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and reported amounts of revenues and expenses during the periods reported. Actual results could differ significantly from estimates and assumptions.

Our segments are based on the components of the Company that are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Our chief operating decision maker is the executive management team comprised of senior level management. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision making activities. We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on earnings from the ventures.

We have two reportable business segments, regulated utility and non-utility activities. The regulated utility segment is the gas distribution business, where we include the operations of merchandising and its related service work and home warranty programs, with activities conducted by the utility. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures that are held by our wholly owned subsidiaries. See Note 14 for further discussion of segments.

Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by the regulatory commissions in the states in which we operate. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods.

Our regulatory assets are recoverable through either base rates or rate riders 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 the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commissions during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and regulatory liabilities that would result in an adjustment to net income. 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 rate-based regulation remains appropriate. It is our opinion that all regulatory assets are recoverable in current rates or in future rate proceedings.

Regulatory assets and liabilities in the Consolidated Balance Sheets as of October 31, 2012 and 2011 are as follows.

In thousands	2012		2011

Regulatory Assets:
Unamortized debt expense	$	13,583	$	11,315
Amounts due from customers		81,626		38,649
Environmental costs *		10,202		9,644
Deferred operations and maintenance expenses *		7,050		7,676
Deferred pipeline integrity expenses *		13,691		7,927
Deferred pension and other retirement benefits costs *		20,139		22,119
Amounts not yet recognized as a component of pension
and other retirement benefit costs		123,290		81,073
Regulatory cost of removal asset		21,129		19,336
Other *		2,394		2,396
Total	$	293,104	$	200,135

Regulatory Liabilities:
Regulatory cost of removal obligations	$	464,334	$	438,605
Amounts due to customers		28		2,617
Deferred income taxes*		25,330		25,731
Total	$	489,692	$	466,953

* Regulatory assets are included in “Other noncurrent assets” in “Noncurrent Assets” and regulatory liabilities are included in “Other noncurrent liabilities” in “Noncurrent Liabilities” in the Consolidated Balance Sheets.

As of October 31, 2012, we had regulatory assets totaling $.4 million on which we do not earn a return during the recovery period. The original amortization period for these assets is 15 years and, accordingly, $.4 million will be fully amortized by 2018. We have $2.2 million related to unrealized mark-to-market amounts on which we do not earn a return until they are recorded in interest-bearing amounts due to/from customer accounts when realized and $123.3 million of regulatory postretirement assets, $21.1 million of asset retirement obligations (AROs) and $8.4 million of estimated environmental costs on which we do not earn a return. Included in deferred pension and other retirement costs are amounts related to pension funding for our Tennessee jurisdiction. The recovery of these amounts is authorized by the Tennessee Regulatory Authority (TRA) on a deferred cash basis.

Utility plant is stated at original cost, including direct labor and materials, contractor costs, allocable overhead charges, such as engineering, supervision, corporate office salaries and expenses, and pensions and insurance, and an allowance for funds used during construction (AFUDC) that is calculated under a formula prescribed by our state regulators. We apply the group method of accounting, where the cost of homogeneous assets are aggregated and depreciated by applying a rate based on the average expected useful life of the assets. Major expenditures that last longer than a year and improve or lengthen the expected useful life of the overall property from original expectations that are recoverable in regulatory rate base are capitalized while expenditures not meeting these criteria are expensed as incurred. The costs of property retired or otherwise disposed of are removed from utility plant and charged to accumulated depreciation for recovery or refund through future rates. On certain assets, like land, that are nondepreciable, we record a gain or loss upon the disposal of the property that is recorded in “Non-operating income” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income.

The classification of total utility plant, net, for the years ended October 31, 2012 and 2011 is presented below.

In thousands	2012		2011

Intangible plant	$	3,374	$	3,377
Other storage plant		118,277		56,064
Transmission plant		866,000		652,069
Distribution plant		2,422,988		2,347,287
General plant		329,867		312,482
Asset retirement cost		10,819		11,156
Contributions in aid of construction		(5,147)		(5,125)
Total utility plant in service		3,746,178		3,377,310
Less accumulated depreciation		(1,036,814)		(974,631)
Total utility plant in service, net		2,709,364		2,402,679
Construction work in progress		388,979		217,832
Plant held for future use		6,743		6,751
Total utility plant, net	$	3,105,086	$	2,627,262

Contributions in aid of construction represent nonrefundable donations or contributions received from third-parties for partial or full reimbursement for construction expenditures for utility plant in service.

AFUDC represents the estimated costs of funds from both debt and equity sources used to finance the construction of major projects and is capitalized for ratemaking purposes when the completed projects are placed in service. The portion of AFUDC attributable to borrowed funds is shown as a reduction of “Utility Interest Charges” in the Consolidated Statements of Comprehensive Income. Any portion of AFUDC attributable to equity funds would be included in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income. For the three years ended October 31, 2012, 2011 and 2010, all of our AFUDC was attributable to borrowed funds.

In accordance with utility accounting practice, we have classified expenditures associated with a liquefied natural gas (LNG) peak storage facility in the eastern part of North Carolina that has been delayed as “Plant held for future use” in the Consolidated Balance Sheets. There is no current need to proceed with the LNG peak storage facility due to the expansion capacity, cost effectiveness, timing and design scope of another construction project that will enhance our ability to serve our North Carolina customers in this area. The future use of this property is dependent upon annual updates to our ongoing five-year plan for forecasted growth requirements, and the pursuit of such project will be determined as growth requirements dictate. Such costs, approximately half being land purchase and preparation, will be moved to any such future project. For further information on a regulatory filing related to these costs, see Note 2 to the consolidated financial statements.

We compute depreciation expense using the straight-line method over periods ranging from 4 to 88 years. The composite weighted-average depreciation rates were 2.94% for 2012, 3.19% for 2011 and 3.20% for 2010.

Depreciation rates for utility plant are approved by our regulatory commissions. In North Carolina, we are required to conduct a depreciation study every five years and file the results with the regulatory commission. No such five-year requirement exists in South Carolina or Tennessee; however, we periodically propose revised rates in those states based on depreciation studies. Our last system-wide depreciation study based on fiscal year 2009 data was completed in 2011 and filed with the appropriate regulatory commission in all jurisdictions. New depreciation rates were approved effective November 1, 2011 for South Carolina and March 1, 2012 for Tennessee. We anticipate the new rates will become effective in North Carolina in connection with our next general rate case filing.

The estimated costs of removal on certain regulated properties are collected through depreciation expense through rates with a corresponding credit to accumulated depreciation. Our approved depreciation rates are comprised of two components, one based on average service life and one based on cost of removal for certain regulated properties. Therefore, through depreciation expense, we accrue estimated non-legal costs of removal on any depreciable asset that includes cost of removal in its depreciation rate.

We consider instruments purchased with an original maturity at date of purchase of three months or less to be cash equivalents, particularly affecting the Consolidated Statements of Cash Flows. We have no restrictions on our cash balances that would impact the payment of dividends as of October 31, 2012 and 2011.

Trade accounts receivable consist of natural gas sales and transportation services, merchandise sales and service work. We bill customers monthly with payment due within 30 days. We maintain an allowance for doubtful accounts, which we adjust periodically, based on the aging of receivables and our historical and projected charge-off activity. Our estimate of recoverability could differ from actual experience based on customer credit issues, the level of natural gas prices and general economic conditions. We write off our customers' accounts when they are deemed to be uncollectible. Pursuant to orders issued by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (PSCSC) and the TRA, we are authorized to recover all uncollected gas costs through the purchased gas adjustment (PGA). As a result, only the portion of accounts written off relating to the non-gas costs, or margin, is included in base rates and, accordingly, only this portion is included in the provision for uncollectibles expense. Non-regulated merchandise and service work receivables due beyond one year are included in “Other noncurrent assets” in “Noncurrent Assets” in the Consolidated Balance Sheets.

We are exposed to credit risk when we enter into contracts with third parties to sell natural gas. We also enter into short-term contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. Our internal credit policies require counterparties to have an investment-grade or functionally equivalent credit rating at the time of the contract. Where the counterparty does not have an investment-grade credit rating, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, the policy specifies limits on the contract amount and duration based on the counterparty's credit rating and/or credit support. We continually re-evaluate third-party credit worthiness and market conditions and modify our requirements accordingly.

Our principal business activity is the distribution of natural gas. We believe that we have provided an adequate allowance for any receivables which may not be ultimately collected. As of October 31, 2012 and 2011, our trade accounts receivable consisted of the following.

In thousands		2012		2011

Gas receivables	$	55,956	$	55,928
Non-regulated merchandise and service work receivables		2,323		2,454
Allowance for doubtful accounts		(1,579)		(1,347)
Trade accounts receivable	$	56,700	$	57,035

A reconciliation of the changes in the allowance for doubtful accounts for the years ended October 31, 2012, 2011 and 2010 is presented below.

In thousands		2012		2011		2010

Balance at beginning of year	$	1,347	$	929	$	990
Additions charged to uncollectibles expense		4,584		4,842		4,886
Accounts written off, net of recoveries		(4,352)		(4,424)		(4,947)
Balance at end of year	$	1,579	$	1,347	$	929

We maintain gas inventories on the basis of average cost. Injections into storage are priced at the purchase cost at the time of injection, and withdrawals from storage are priced at the weighted average purchase price in storage. The cost of gas in storage is recoverable under rate schedules approved by state regulatory commissions. Inventory activity is subject to regulatory review on an annual basis in gas cost recovery proceedings.

We utilize asset management agreements with counterparties for certain natural gas storage and transportation assets. At October 31, 2012 and 2011, such counterparties held natural gas storage assets, included in “Prepayments” in “Current Assets” in the Consolidated Balance Sheets, with a value of $26.7 million and $35.8 million, respectively, through asset management relationships. Under the terms of the agreements, we receive capacity and storage asset management fees, which are recorded as secondary market transactions and shared between our utility customers and our shareholders. The asset management agreements expire at various times through March 31, 2014. For further information on the revenue sharing of secondary market transactions, see Note 2 to the consolidated financial statements.

Materials, supplies and merchandise inventories are valued at the lower of average cost or market and removed from such inventory at average cost.

The carrying values of cash and cash equivalents, receivables, short-term debt, accounts payable, accrued interest and other current liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our financial assets and liabilities are recorded at fair value. They consist primarily of derivatives that are recorded in the Consolidated Balance Sheets in accordance with derivative accounting standards and marketable securities that are classified as trading securities and are held in rabbi trusts established for our deferred compensation plans. Our qualified pension and postretirement plan assets and liabilities are recorded at fair value in the Consolidated Balance Sheets in accordance with employers' accounting and related disclosures of postretirement plans.

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, or exit date. 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 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. The fair value of our financial assets and liabilities are subject to potentially significant volatility based on changes in market prices, the portfolio valuation of our contracts, as well as the maturity and settlement of those contracts, and subsequent newly originated transactions, each of which directly affects the estimated fair value of our financial instruments. We are able to classify fair value balances based on the observance of those inputs at the lowest level into the following fair value hierarchy levels as set forth in the fair value guidance.

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets have sufficient frequency and volume to provide pricing information for the asset or liability on an ongoing basis. Our Level 1 items consist of financial instruments of exchange-traded derivatives, investments in marketable securities and benefit plan assets held in registered investment companies and individual stocks.

Level 2 inputs are inputs other than quoted prices in active markets included in Level 1 and are either directly or indirectly corroborated or observable as of the reporting date, generally 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 market place. Our Level 2 items include non-exchange-traded derivative instruments, such as some qualified pension plan assets held in hedge fund of funds, commodities fund of funds, a common trust fund, collateralized mortgage obligations, swaps, futures, currency forwards, corporate bonds and government and agency obligations that are valued at the closing price reported in the active market for similar assets in which the individual securities are traded or based on yields currently available on comparable securities of issuers with similar credit ratings or based on the most recent available financial information for the respective funds and securities. For some qualified pension plan assets, the determination of Level 2 assets was completed through a process of reviewing each individual security while consulting research and other metrics provided by investment managers, including a pricing matrix detailing the pricing source and security type, annual audited financial statements and a review of valuation policies and procedures used by the investment managers as well as our investment advisor.

Level 3 inputs include significant pricing inputs that are generally less observable from objective sources and may be used with internally developed methodologies that result in management's best estimate of fair value. Our Level 3 inputs include cost estimates for removal (contract fees or manpower/equipment estimates), inflation factors, risk premiums, the remaining life of long-lived assets, the credit adjusted risk free rate to discount for the time value of money over an appropriate time span, and the most recent available financial information of an investment in a diversified private equity fund of funds for some of our qualified pension plan assets. We do not have any other assets or liabilities classified as Level 3.

In determining whether to categorize the fair value measurement of an instrument as Level 2 or Level 3, we must use judgment to assess whether we have the ability as of the measurement date to redeem an investment at its net asset value per share (NAV) in the near term. We consider when we might have the ability to redeem the investment by reviewing contractual restrictions in effect as of the investment date as well as any potential restrictions that the investee may impose. Regarding our benefit plans' investments, “near term” is the ability to redeem an investment in no more than 180 days.

Transfers between different levels of the fair value hierarchy may occur based on the level of observable inputs used to value the instruments for the period. These transfers represent existing assets or liabilities previously categorized as a Level 1 or Level 2 for which the inputs to the estimate became less observable or assets and liabilities previously classified as Level 2 or Level 3 for which the lowest significant input became more observable during the period. Transfers into and out of each level are measured at the actual date of the event or change in circumstances causing the transfer.

For the fair value measurements of our derivatives and marketable securities, see Note 7 to the consolidated financial statements. For the fair value measurements of our benefit plan assets, see Note 9 to the consolidated financial statements.

Goodwill is the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. We annually evaluate goodwill for impairment as of October 31, or more frequently if impairment indicators arise during the year. 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. We test goodwill using a fair value approach at a reporting unit level, generally equivalent to our operating segments as discussed in Note 14 to the consolidated financial statements. An impairment charge would be recognized if the carrying value of the reporting unit, including goodwill, exceeded its fair value. All of our goodwill is attributable to the regulated utility segment.

Our annual goodwill impairment assessment was performed as of October 31, 2012, and we determined that there was no impairment to the carrying value of our goodwill. No impairment has been recognized during the years ended October 31, 2012, 2011 and 2010.

We review our equity method investments and long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. There were no events or circumstances during the years ended October 31, 2012, 2011 and 2010 that resulted in any impairment charges. For further information on equity method investments, see Note 12 to the consolidated financial statements.

We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in rabbi trusts established for our deferred compensation plans. For further information on the deferred compensation plans, see Note 9 to the consolidated financial statements.

We have classified these marketable securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securities are recorded at fair value on the Consolidated Balance Sheets with any gains or losses recognized currently in earnings. We do not intend to engage in active trading of the securities, and participants in the deferred compensation plans may redirect their investments at any time. We have matched the current portion of the deferred compensation liability with the current asset and noncurrent deferred compensation liability with the noncurrent asset; the current portion has been included in “Other current assets” in “Current Assets” in the Consolidated Balance Sheets.

The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. The composition of these securities as of October 31, 2012 and 2011 is as follows.

In thousands	2012				2011
	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	-	$	-	$	-	$	-
Mutual funds		134		157		47		52
Total current trading securities		134		157		47		52
Noncurrent trading securities:
Money markets		243		243		217		217
Mutual funds		1,668		1,888		1,107		1,222
Total noncurrent trading securities		1,911		2,131		1,324		1,439
Total trading securities	$	2,045	$	2,288	$	1,371	$	1,491

Unamortized debt expense consists of costs, such as underwriting and broker dealer fees, discounts and commissions, legal fees, accountant fees, registration fees and rating agency fees, related to issuing long-term debt and the short-term syndicated revolving credit facility. We amortize long-term debt expense on a straight-line basis, which approximates the effective interest method, over the life of the related debt which has lives ranging from 5 to 30 years. We amortize bank debt expense over the life of the syndicated revolving credit facility, which is five years.

Should we reacquire long-term debt prior to its term date and simultaneously issue new debt, we defer the gain or loss resulting from the transaction, essentially the remaining unamortized debt expense, and amortize it over the life of the new debt in accordance with established regulatory practice. Where the refunding of the debt is not simultaneous, we defer the gain or loss resulting from the reacquisition of the debt and amortize over the remaining life of the redeemed debt in accordance with established regulatory practice. For income tax purposes, any gain or loss would be recognized as incurred.

As discussed in Note 6 to the consolidated financial statements, we repurchase shares on the open market and such shares are then cancelled and become authorized but unissued shares. It is our policy to issue new shares for share-based employee awards and shareholder and employee investment plans. We present net shares issued under these awards and plans in “Common Stock Issued” in the Consolidated Statements of Stockholders' Equity. Shares withheld by us to satisfy tax withholding obligations related to the vesting of shares awarded under the Incentive Compensation Plan have been immaterial to date.

The accounting guidance for AROs addresses the financial accounting and reporting for AROs associated with the retirement of long-lived assets that result from the acquisition, construction, development and operation of the assets. The accounting guidance requires the recognition of the fair value of a liability for AROs in the period in which the liability is incurred if a reasonable estimate of fair value can be made. We have determined that AROs exist for our underground mains and services.

In accordance with long-standing regulatory treatment, our depreciation rates are comprised of two components, one based on average service life and one based on cost of removal. We collect through rates the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation. These removal costs are non-legal obligations as defined by the accounting guidance. Because these estimated removal costs meet the requirements of rate-regulated accounting guidance, we have accounted for these non-legal AROs as a regulatory liability. We record the estimated non-legal AROs in “Cost of removal obligations” in “Noncurrent Liabilities” in the Consolidated Balance Sheets. In the rate setting process, the liability for non-legal costs of removal is treated as a reduction to the net rate base upon which the regulated utility has the opportunity to earn its allowed rate of return.

We apply the accounting guidance for conditional AROs that requires recognition of a liability for the fair value of conditional AROs when incurred if the liability can be reasonably estimated. The NCUC, the PSCSC and the TRA have approved placing these ARO costs in deferred accounts to preserve the regulatory treatment of these costs; therefore, accretion is not reflected in the Consolidated Statements of Comprehensive Income as the regulatory treatment provides for deferral as a regulatory asset with netting against a regulatory liability. AROs are capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the liability. In periods subsequent to the initial measurement, any changes in the liability resulting from the passage of time (accretion) or due to the revisions of either timing or the amount of the originally estimated cash flows to settle conditional AROs must be recognized. The estimated cash flows to settle conditional AROs are discounted using the credit adjusted risk-free rate, which ranged from 3.86% to 5.87% with a weighted average of 5.73% for the twelve months ended October 31, 2012. The estimate was calculated using a time value weighted average credit adjusted risk-free rate. We have recorded a liability on our distribution and transmission mains and services.

The cost of removal obligations recorded in the Consolidated Balance Sheets as of October 31, 2012 and 2011 are presented below.

In thousands	2012		2011

Regulatory non-legal AROs	$	464,334	$	438,605
Conditional AROs		28,629		27,395
Total cost of removal obligations	$	492,963	$	466,000

A reconciliation of the changes in conditional AROs for the year ended October 31, 2012 and 2011 is presented below.

In thousands	2012		2011

Beginning of period	$	27,395	$	23,295
Liabilities incurred during the period		1,705		3,102
Liabilities settled during the period		(2,038)		(1,493)
Accretion		1,570		1,365
Adjustment to estimated cash flows		(3)		1,126
End of period	$	28,629	$	27,395

We record revenues when services are provided to our distribution service customers. Utility sales and transportation revenues are based on rates approved by state regulatory commissions. Base rates charged to jurisdictional customers may not be changed without formal approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas component of rates may be adjusted periodically under PGA provisions. In South Carolina and Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial customers during the winter heating season November through March. Effective March 1, 2012 the WNA mechanism in Tennessee was expanded to include the additional months of April and October in the winter heating season. The WNA mechanisms are designed to offset the impact that warmer-than-normal or colder-than-normal weather has on customer billings during the winter heating season. The WNA formula does not ensure full recovery of approved margin during periods when customer consumption patterns vary significantly from consumption patterns used to establish the WNA factors. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers on an annual basis independent of consumption patterns. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the margin decoupling mechanism or the WNA mechanisms.

Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas delivered to customers but not yet billed under the cycle-billing method from the last meter reading date to month end. The unbilled revenue estimate reflects factors requiring judgment related to estimated usage by customer class, customer mix, changes in weather during the period and the impact of the WNA or margin decoupling mechanisms, as applicable.

Secondary market revenues associated with the commodity are recognized when the physical sales are delivered based on contract or market prices. Asset management fees for storage and transportation remitted on a monthly basis are recognized as earned given the monthly capacity costs associated with the contracts involved. Asset management fees remitted in a lump sum are deferred and amortized ratably into income over the period in which they are earned, which is typically the contract term. See Note 2 to the consolidated financial statements regarding revenue sharing of secondary market transactions.

Utility sales, transportation and secondary market revenues are reported net of excise taxes, sales taxes and franchise fees. For further information regarding taxes, see “Taxes” in this Note 1 to the consolidated financial statements.

Non-regulated merchandise and service work includes the sale, installation and/or maintenance of natural gas appliances and gas piping beyond the meter. Revenue is recognized when the sale is made or the work is performed. If the customer is eligible for and elects financing through us, the finance fee income is recognized on a monthly basis based on principal, rate and term.

We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms as set by the regulatory commissions in states in which we operate. Rate schedules for utility sales and transportation customers include PGA provisions that provide for the recovery of prudently incurred and allocated gas costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas. We charge our secondary market customers for natural gas based on negotiated contract terms. Under PGA provisions, charges to cost of gas are based on the amount recoverable under approved rate schedules. Within our cost of gas, we include amounts for lost and unaccounted for gas and adjustments to reflect the gains and losses associated with gas price hedging derivatives. By jurisdiction, differences between gas costs incurred and gas costs billed to customers are deferred and included in “Amounts due from customers” in “Current Assets” or “Amounts due to customers” in “Current Liabilities” in the Consolidated Balance Sheets. We review gas costs and deferral activity periodically (including deferrals under the margin decoupling and WNA mechanisms) and, with regulatory commission approval, increase rates to collect under-recoveries or decrease rates to refund over-recoveries over a subsequent period.

We have two categories of income taxes in the Consolidated Statements of Comprehensive Income: current and deferred. Current income tax expense consists of federal and state income taxes less applicable tax credits related to the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year. Deferred taxes are primarily attributable to utility plant, deferred gas costs, revenues and cost of gas, equity method investments, benefit of loss carryforwards and employee benefits and compensation. The determination of our provision for income taxes requires judgment, the use of estimates, and the interpretation and application of complex tax laws. Judgment is required in assessing the timing and amounts of deductible and taxable items.

Deferred income taxes are determined based on the estimated future tax effects of differences between the book and tax basis of assets and liabilities. We have provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that are more likely than not to be realized. To the extent that the establishment of deferred income taxes is different from the recovery of taxes through the ratemaking process, the differences are deferred in accordance with rate-regulated accounting provisions, and a regulatory asset or liability is recognized for the impact of tax expenses or benefits that will be collected from or refunded to customers in different periods pursuant to rate orders.

Deferred investment tax credits, including energy credits, associated with our utility operations are presented in the Consolidated Balance Sheets. We amortize these deferred investment and energy tax credits to income over the estimated useful lives of the property to which the credits relate.

We recognize accrued interest and penalties, if any, related to uncertain tax positions as operating expenses in the Consolidated Statements of Comprehensive Income. This is consistent with the recognition of these items in prior reporting periods.

Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded on a net basis as liabilities payable to the applicable jurisdictions. All other taxes other than income taxes are recorded as general taxes. General taxes consist of property taxes, payroll taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use and other miscellaneous taxes.

With respect to cash overdrafts, book overdrafts are included within operating cash flows while any bank overdrafts are included with financing cash flows.

In January 2010, the Financial Accounting Standards Board (FASB) issued accounting guidance to require separate disclosures about purchases, sales, issuances and settlements relating to Level 3 fair value measurements, which primarily relates to our employee benefit plans. The guidance was effective for interim periods for fiscal years beginning after December 15, 2010. We adopted the guidance for Level 3 disclosures for recurring and non-recurring items covered under the fair value guidance for the first quarter of our fiscal year ending October 31, 2012. The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The adoption of the guidance, which was effective for interim and annual periods beginning after December 15, 2011, had no material impact on our financial position, results of operations or cash flows.

In June 2011, the FASB issued accounting guidance to increase the prominence of OCI in financial statements. The guidance gave businesses two options for presenting OCI. An OCI statement could be included with the statement of income, and together the two would make a statement of comprehensive income. Alternatively, businesses could present a separate OCI statement, but that statement would have to appear consecutively with the statement of income within the financial report. The guidance, which we early adopted and presented in one continuous statement for the first quarter of our fiscal year ending October 31, 2012, was effective for interim and annual periods beginning after December 15, 2011. The adoption of this guidance had no impact on our financial position, results of operations or cash flows.

In December 2011, the FASB issued accounting guidance to improve disclosures and make information more comparable to IFRS regarding the nature of an entity's rights of offset and related arrangements associated with its financial instruments and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements in tabular format to enable users of financial statements to understand the effect of those arrangements on the entity's financial position. The new disclosure requirements are effective for annual periods beginning after January 1, 2013 and interim periods therein and require retrospective application in all periods presented. We will adopt this offsetting disclosure guidance for the first quarter of our fiscal year ending October 31, 2014. The adoption of this guidance will have no impact on our financial position, results of operations or cash flows.

In November 2012, the FASB finalized the presentation disclosures on items reclassified from OCI. The guidance will be effective for interim and annual periods beginning after December 15, 2012. We will adopt this disclosure guidance for the second quarter of our fiscal year ending October 31, 2013. The adoption of this guidance will have no impact on our financial position, results of operations or cash flows.